IADC Drilling Manual eBook Version (V.11)

Copyright© 2000, International Association of Drilling Contractors All Rights Reserved

In publishing this Manual, IADC makes no warranty or representation, expressed or implied, with respect to the accuracy, completeness, usefulness, or fitness for purpose of the information contained herein, or that the use of any information, method, process, or apparatus disclosed in this report may not infringe on privately owned rights. IADC assumes no liability with respect to the use of, or for damages resulting from the use of, any information, method, process, or apparatus disclosed in this report. The text of this publication, or any part thereof, may not be reproduced or transmitted in any form by any means, electronic or mechanical, including photocopying, recording, storage in an information retrieval system, or otherwise, without the prior, written approval of IADC. IADC Contact Information: Office Address 15810 Park Ten Place, Suite 242 Houston, TX 77084-5139 USA Mailing Address P.O. Box 4287 Houston, TX 77210-4287 USA Phone: Fax: Email: Web:

1/281-578-7171 1/281-578-0589 [email protected] www.iadc.org

List Price: $595 Member Price: $495 ©

Copyright 2000 All Rights Reserved by International Association of Drilling Contractors

The IADC Drilling Manual Published by Technical Toolboxes, Inc. 3801 Kirby Drive, Suite 340 Houston, Texas 77098 Tel: 713-630-0505 Fax: 713-630-0560 Email: [email protected] Web: www.ttoolboxes.com

Acknowledgements The 1991 Drilling Technology Committee of IADC, chaired by W.M. “Sonny” Rogers, authorized the preparation of the eleventh edition of this manual. This edition is the eBook version of the entire eleventh edition. This version is fully searchable and has new color graphics and photographs. Jay Norton, Chairman of the Drilling Manual Subcommittee and many of the Industry’s most knowledgeable people have reviewed, rewritten, and added chapters for the benefit of the user. Their time, effort, and dedication, in spite of difficult economic times for the industry, is greatly appreciated. The Association would again like to express its appreciation to the many contributors to previous editions. Without their early interest, the manual would not have evolved to its present status. The following people served on the 1991-92 Rewrite Subcommittee and as Chairman for the Chapter rewrite task groups: John Altermann Robert Bennett Bill Bingham Sonny Cain Jerry Cerkovnik Otis Danielson John Gieck Bill Halliday Bruce Harwell Larry Jones Jay Norton Paul O’Connor Chuck Rayburn Chris Reinsvold W.M. “Sonny” Rogers Jim Senger Jim Sikes Jack Smith Tom Smith Mickey Thomas Jim West Wayne Wilson

Reading and Bates Millpark Drilling Fluids MH Koomey SWACO Hughes Christiansen Consultant Baker Hughes Millpard Drilling Fluids DI Industries Consultant Norton Drilling O’Connor and Young Drilling Grasso Oil Services Hughes Christiansen Tuboscope Security Dresser Sonat Offshore Baker Hughes Tom Smith Consulting Halliburton Services PETEX Tuboscope

Special Acknowledgement for the eBook version Special thanks are due to Hal Kendall of Noble Drilling Corporation for providing many of the enhanced graphics and illustrations used in this electronic version of the 11th Edition of the "IADC Drilling Manual".

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Table of Contents

Table of Contents - IADC Drilling Manual Chapter A - Bit Classification and Grading.................. A-1 A-1 First Revision To The IADC Fixed Cutter Dull Grading System .......................................................... A-7 Contributors ....................................................................................................................................... A-7 Summary ............................................................................................................................................ A-7 Abstract ............................................................................................................................................. A-7 Introduction ........................................................................................................................................ A-7 System Enhancements ......................................................................................................................... A-7 Application Of Dull Grading System .................................................................................................... A-9 Conclusion ....................................................................................................................................... A-14 References ....................................................................................................................................... A-14 Acknowledgements .......................................................................................................................... A-14 A2 - IADC Fixed Cutter Classification System ........................................................................................ A-16 Development Of A New IADC Fixed Cutter Drill Bit Classification System ....................................... A-16 Contributors ..................................................................................................................................... A-16 Abstract ........................................................................................................................................... A-16 Introduction ...................................................................................................................................... A-16 Background ...................................................................................................................................... A-17 Proposed System ............................................................................................................................. A-20 Conclusions ...................................................................................................................................... A-28 References ....................................................................................................................................... A-28 Acknowledgements .......................................................................................................................... A-28 A3 - The IADC Roller Bit Classification System ...................................................................................... A-29 Summary .......................................................................................................................................... A-29 Series And Type ............................................................................................................................... A-33 Characters 1 And 2 .......................................................................................................................... A-33 Cutting Action .................................................................................................................................. A-33 Tooth Count And Geometry .............................................................................................................. A-34 Insert Shape Comparison .................................................................................................................. A-34 Cone Design And Orientation ........................................................................................................... A-34 Cutting Structure Metallurgy .............................................................................................................. A-35 Bearing/Gage Design Configuration (Character 3) .............................................................................. A-35 Features Available (Optional 4th Character) ...................................................................................... A-37 A4 - IADC Roller Bit Dull Bit Grading System ........................................................................................ A-60 Description of the IADC Roller Bit Dull Bit Grading System .............................................................. A-60 A4. IADC Roller Bit Dull Grading System ......................................................................................... A-60 Discussion Of Dulling Characteristics ................................................................................................. A-66 BC (Broken Cone) or BF (Bond Failure) - (Fig. A4-3) ..................................................................... A-67 BT (Broken Teeth) - (Fig. A4-4) ...................................................................................................... A-68 BU (Balled Up) - (Fig. A4-5) ........................................................................................................... A-69 CC (Crocked Cone) - (Fig. A4-6) ................................................................................................... A-70 CD (Cone Dragged) - (Fig. A4-7) .................................................................................................... A-71 CI (Cone Interference) - (Fig. A4- 8) ............................................................................................... A-72

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CR (Cored) - (Fig. A4-9) ................................................................................................................. A-73 CT (Chipped Teeth) - (Fig. A4-10) .................................................................................................. A-74 ER (Erosion) - (Fig. A4-11) .............................................................................................................. A-75 FC (Flat Crested Wear) - (Fig. A4-12) ............................................................................................. A-76 HC (Heat Checking) - (Fig. A4-13) .................................................................................................. A-77 JD (Junk Damage) - (Fig. A4-14) ..................................................................................................... A-78 LC (Lost Cone) - (Fig. A4-15) ......................................................................................................... A-79 LN (Lost Nozzle) - (Fig. A4-16) ...................................................................................................... A-80 LT (Lost Teeth) - (Fig. A4-17) ......................................................................................................... A-81 OC (Off Center Wear) - (Fig. A4-18) .............................................................................................. A-82 PB (Pinched Bit) - (Fig. A4-19) ........................................................................................................ A-83 PN (Plugged Nozzle) - (Fig. A4-20) ................................................................................................. A-84 RG (Rounded Gage) - (Fig. A4-21) .................................................................................................. A-85 SD (Shirttail Damage) - (Fig. A4-22) ................................................................................................ A-86 SS (Self Sharpening Wear) - (Fig. A4-23) ........................................................................................ A-87 TR (Tracking) - (Fig. A4-24) ............................................................................................................ A-87 WO (Washed Out Bit) - (Fig. A4-25) ............................................................................................... A-88 WT (Worn Teeth) (Fig. A4-26) ........................................................................................................ A-89 NO (No Dull Characteristics) ........................................................................................................... A-89

Chapter B - Drill String ................................................... B-1 Preface ............................................................................................................................................... B-5 B1. Drill String .......................................................................................................................................... B-6 Introduction ........................................................................................................................................ B-6 I. Weld-on Tool Joints ........................................................................................................................ B-6 B2. Steel Drill Pipe ................................................................................................................................. B-45 B3. Tool Joints Care And Handling ......................................................................................................... B-54 I. Cleaning and Inspection ................................................................................................................. B-54 II. Picking Up the Drill String ............................................................................................................ B-55 III. Thread Compounds .................................................................................................................... B-58 IV. Breaking In New Tool Joints ....................................................................................................... B-58 V. Tripping ........................................................................................................................................ B-59 VI. Laying Down Drill String ............................................................................................................. B-67 VII. Damage and Failures -- Cause Prevention .................................................................................. B-69 VIII. Repair of Tool Joints ................................................................................................................ B-87 IX. Emergency Procedures ............................................................................................................... B-93 X. Transportation .............................................................................................................................. B-94 XI. Storage ...................................................................................................................................... B-95 XII. Floor Handling Procedures ........................................................................................................ B-96 B4. Drill String Operating Limits ............................................................................................................ B-104 I. Fatigue and Lateral Forces caused by Dog Legs and Floating Vessels ........................................... B-104 II. Fatigue Caused by Other Factors ............................................................................................... B-115 III. Critical Rotary Speed ................................................................................................................ B-120 IV. Collapsed Pipe -- From Drill Stem Test and BOP Test ............................................................... B-120 V. Transition from Drill String to Drill Collars ................................................................................... B-121 VI. Maximum Allowable Pull and Rotary Torque ............................................................................. B-121

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VII. Make up Torque versus Drilling Torque .................................................................................... B-123 IX. Dynamic Loading of Drill Pipe during Tripping ........................................................................... B-125 X. Biaxial Loading of Drill Pipe ....................................................................................................... B-125 XI. Drill String Design ..................................................................................................................... B-126 XII. References .............................................................................................................................. B-126 B5. Drill String Corrosion ..................................................................................................................... B-127 I. Introduction ................................................................................................................................. B-127 Il. Corrosion ................................................................................................................................... B-127 III. Sulfide Stress Cracking ............................................................................................................. B-132 IV. Drilling Fluids Containing Oil ...................................................................................................... B-135 B6. Drill String Inspection And Classification ......................................................................................... B-136 I. Purpose ...................................................................................................................................... B-136 II. Drill String Marking and Identification ......................................................................................... B-136 III. Drill Pipe And Tubing Work Strings ........................................................................................... B-136 IV. Tool Joints ................................................................................................................................ B-144 B7. Aluminum Drill String ...................................................................................................................... B-148 Introduction .................................................................................................................................... B-148 II. Installation and Removal of Tool Joints ........................................................................................ B-148 III. Aluminum Drill Pipe .................................................................................................................. B-148 IV. Drill String Care and Handling ................................................................................................... B-150 V. Drill String Maintenance .............................................................................................................. B-151 VI. Drill String Operating Limits ...................................................................................................... B-151 B-8 Glossary Of Drill String Terms ........................................................................................................ B-154

Chapter C - Casing and Tubing ......................................C-1 I. Care And Use Of Casing ....................................................................................................................... C-4 Introduction ........................................................................................................................................ C-4 I. Transportation ................................................................................................................................. C-4 II. Preparation And Inspection Before Running .................................................................................... C-4 III. Rig Equipment .............................................................................................................................. C-4 IV. Pre-running Preparations ............................................................................................................... C-5 V. Running Casing ............................................................................................................................... C-6 VI. Causes Of Casing Troubles ......................................................................................................... C-16 VII. Recovery Of Casing .................................................................................................................. C-19 VIII. Reconditioning ......................................................................................................................... C-20 IX. Field Welding Of Attachments On Casing .................................................................................... C-20 II. Care And Use Of Tubing .................................................................................................................... C-24 Introduction ...................................................................................................................................... C-24 I. Transportation ............................................................................................................................... C-24 II. Preparation And Inspection Before Running .................................................................................. C-24 III. Rig Equipment ............................................................................................................................ C-24 IV. Pre-running Preparations ............................................................................................................. C-25 V. Running ........................................................................................................................................ C-26 VI. Pulling Tubing ............................................................................................................................. C-36 VII. Causes Of Tubing Troubles ........................................................................................................ C-37 VIII Reconditioning .......................................................................................................................... C-37

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Chapter D - Drill Collars, Kellys, Subs and Heavy Weight Drill Pipe ...........................................................D-1 Preface ............................................................................................................................................... D-3 D1. Drill Collars: Specifications & Usage .................................................................................................. D-4 I. Specifications .................................................................................................................................. D-4 D2. Drill Collars: Care And Maintenance ................................................................................................ D-36 I. Recommended Drill Collar Care And Maintenance ........................................................................ D-36 D3. Kellys: Specifications ....................................................................................................................... D-59 I. Specifications ................................................................................................................................ D-59 D4. Kellys: Care And Maintenance ......................................................................................................... D-66 I. Care And Maintenance .................................................................................................................. D-66 D5. Drill Stem Subs: Specifications ......................................................................................................... D-71 I. Class And Type ............................................................................................................................. D-71 II. Dimensions For Type A & B Subs ................................................................................................ D-77 III. Dimensions For Type C (Swivel) Subs ........................................................................................ D-79 IV. Mechanical Properties Of Drill Stem Subs ................................................................................... D-79 V. Kelly Saver Subs .......................................................................................................................... D-80 D6. Kelly Valves: Specifications .............................................................................................................. D-81 I. Upper Kelly Cocks ....................................................................................................................... D-81 II. Lower Kelly Cocks ...................................................................................................................... D-85 III. Automatic Mud Saver Valves ...................................................................................................... D-87 IV. Kelly Saver Subs ........................................................................................................................ D-87 D-7 Specifications Of Heavy Weight Drill Pipe ........................................................................................ D-88 Care and Maintenance of HWDP ..................................................................................................... D-89 D8 - Glossary of Drill String Terms ......................................................................................................... D-90

Chapter E - Pipe Handling Equipment......................... E-1 E1. Pipe Handling Equipment .................................................................................................................... E-4 Introduction ........................................................................................................................................ E-4 I. Specifications .................................................................................................................................. E-4 E2. Bushings And Slips ............................................................................................................................. E-9 I. Specifications .................................................................................................................................. E-9 II. Care And Maintenance ................................................................................................................ E-13 E3. Elevators .......................................................................................................................................... E-23 I. Drill Pipe Elevators ........................................................................................................................ E-23 II. Drill Collar Elevators .................................................................................................................... E-25 E4 - Drill Collar Slips and Safety Clamps ................................................................................................ E-30 I. Drill Collar Slips ............................................................................................................................ E-30 II. Drill Collar Safety Clamps ............................................................................................................ E-30 E5. Elevator Links, Block, Hook And Swivel Specifications .................................................................... E-31

Chapter F - Drawworks Brakes ...................................... F-1 Introduction ........................................................................................................................................ F-3 I. Maintenance Procedures ................................................................................................................. F-4 II. Brake Linings (Blocks) ................................................................................................................... F-5

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III. Brake Bands ................................................................................................................................. F-5 IV. Brake Rims (Flanges) .................................................................................................................... F-6 V. Brake Linkage .............................................................................................................................. F-20 VI. Company Policy ......................................................................................................................... F-20

Chapter G - Chains and Sprockets .................................G-1 G1. Construction and Specifications .......................................................................................................... G-4 I. Roller Chain Construction And Types .............................................................................................. G-4 II. Sprockets. ................................................................................................................................... G-16 G2. Installation, Lubrication And Maintenance ......................................................................................... G-22 I. Installation ..................................................................................................................................... G-22 II. Lubrication ................................................................................................................................... G-25 III Maintenance ................................................................................................................................ G-36 Roller Chain Drive Troubleshooting Guide ......................................................................................... G-41

Chapter H - Rotary Hose and Swivels ...........................H-1 H1. Rotary Hose Specifications ................................................................................................................ H-4 I. Introduction ..................................................................................................................................... H-4 II. Specifications ................................................................................................................................. H-4 H2. Rotary Hose Care And Maintenance .................................................................................................. H-9 I. Recommended Dimensions ............................................................................................................ H-9 II. Care And Maintenance ................................................................................................................ H-10 H3. Swivels Specifications ...................................................................................................................... H-12 I. Swivel Pressure Testing ................................................................................................................. H-12 II. Swivel Gooseneck Connection ..................................................................................................... H-12 III. Swivel Subs ................................................................................................................................ H-13 H4. Inspection ........................................................................................................................................ H-14 I. Inspection ..................................................................................................................................... H-14

Chapter I - Engines ............................................................ I-1 I. Engines - Care And Maintenance ............................................................................................................ I-4 I. Installation ........................................................................................................................................ I-4 II. Maintenance ................................................................................................................................... I-9 III. Operating Troubles And Their Causes - Diesel Engines ................................................................. I-14 IV. Intake Vacuum vs Load ................................................................................................................ I-18

Chapter J - Pumps .............................................................J-1 J-1 Introduction - Pumps ........................................................................................................................... J-4 J-2 Surface and Mud System ................................................................................................................... J-13 I. Suction Mud System ...................................................................................................................... J-13 II. Discharge System .......................................................................................................................... J-17 III. Drilling Fluids And Their Effect On Expendable Pump Parts .......................................................... J-18 J-3 Pump Parts, Theory and Function ...................................................................................................... J-23 I. Pistons ........................................................................................................................................... J-23 II. Duplex Piston Rods ....................................................................................................................... J-25 III. Rod Lubricants ............................................................................................................................ J-27 IV. Liner Packing ............................................................................................................................... J-28

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J-4 Removal and Installation of Fluid Ends ............................................................................................... J-32 I. General - Removal and Installation of Fluid Ends ............................................................................. J-32 II. Duplex Pump -- Disassembly ....................................................................................................... J-32 III. Duplex Pump-assembly ............................................................................................................... J-37 IV. Duplex Pump -- Piston Assembly ................................................................................................. J-46 V. Single Acting Pump -- Disassembly .............................................................................................. J-54 VI. Single Acting Pump -- Assembly .................................................................................................. J-56 VII. Single Acting Piston Assembly .................................................................................................... J-57 IX. Valve and Seat ............................................................................................................................. J-64 J-5 Pump Problems, Failures and Analysis ............................................................................................... J-74 I. Priming and Starting Instructions ..................................................................................................... J-74 II. Pistons and Liners ......................................................................................................................... J-74 III. Fluid End Piston Rod and Packing ................................................................................................ J-77 IV. Valves and Seats .......................................................................................................................... J-78 V. Reducing Pump Volume ................................................................................................................. J-79 VI. Centrifugal Pump Care and Maintenance ...................................................................................... J-80 VII. Checklists .................................................................................................................................. J-82 J6. Power End Maintenance ................................................................................................................... J-84 I. Pump Storage ................................................................................................................................ J-90 J7. Preventive Maintenance ...................................................................................................................... J-91 I. Planned Preventative Maintenance .................................................................................................. J-91 II. Establishing a Preventative Maintenance Program ........................................................................... J-92 III. Advantages of programming: ........................................................................................................ J-94

Chapter K - Well Control Equipment and Procedures ......................................................................................K-1 Disclaimer and Credits ....................................................................................................................... K-3 K-1 Blowout Preventer Stack Equipment .................................................................................................. K-5 I. Annular Type Blowout Preventer ..................................................................................................... K-5 II. Ram Type Blowout Preventer ......................................................................................................... K-6 III. Typical Bop Stack Arrangement And Testing Procedures For A Surface Stack ............................ K-11 IV. Inside Blowout Preventers ........................................................................................................... K-36 V. Choke Manifold .......................................................................................................................... K-43 VI. Diverter Systems ........................................................................................................................ K-46 K2. Blowout Preventer Control Systems ................................................................................................. K-54 A. Surface Bop Stacks, (Land Rigs, Offshore Jackups, And Platforms) ............................................. K-54 B. Subsea Bop Stacks ...................................................................................................................... K-61 C. Remote Operated Choke Controls ............................................................................................... K-71 D. Diverter Control Systems ............................................................................................................. K-73 E. Control Systems Typical Capacity And Performance Data / Calculations ....................................... K-77 K3. Well Control Procedures .................................................................................................................. K-92 Basic Principles ................................................................................................................................ K-92 II. Pre-kill Procedures ...................................................................................................................... K-93 III. Formation Pressure Integrity Information ..................................................................................... K-96 IV. Kill Techniques ............................................................................................................................ K-99 K-4 Glossary of Well Control Terms ..................................................................................................... K-108

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Chapter L - Derricks and Masts ..................................... L-1 L-1 Ratings of L Derricks and Masts ........................................................................................................ L-4 Ratings ............................................................................................................................................... L-4 L-2 Inspection Report of Derricks and Masts .......................................................................................... L-20 Derricks And Masts ......................................................................................................................... L-20 A. Derricks And Masts ..................................................................................................................... L-21 B. Substructure And Vertical Extension ............................................................................................. L-25 C. Deadline Anchor And Supports .................................................................................................... L-26

Chapter M - Wire Rope .................................................. M-1 M1. Wire Rope: Specifications ................................................................................................................. M-4 I. Introduction .................................................................................................................................... M-4 II. Definition ...................................................................................................................................... M-4 III. Wire Rope Nomenclature ............................................................................................................. M-4 IV. Wire - Rope Sizes And Constructions ........................................................................................... M-6 M2. Care And Handling Of Wire Rope .................................................................................................. M-15 I. Field Care And Use Of Wire Rope ............................................................................................... M-15 II. Socketing Of Wire Rope ............................................................................................................. M-24 III Attachment Of Wire Rope Claps To Wire Rope .......................................................................... M-27 IV. Casing-line And Drilling Line Reeving Practice ............................................................................ M-32 M3. Factors Affecting Service Life Of Wire Rope .................................................................................. M-38 M4. Ton Mile Calculations ..................................................................................................................... M-40 A. Introduction ................................................................................................................................ M-40 B. Examples Of Ton-mile Calculations .............................................................................................. M-44 C. Ton-miles Per Foot Cut ............................................................................................................... M-48 D. Ton Mile Calculations - Drilling Ton Miles for Top Drive (Drilling with Stands) ...................................................................................................................................... M-49 M5. Cut-off Program ............................................................................................................................. M-50 C. Union Wire Rope Cut-Off Program For Rotary Drilling Line ........................................................ M-51 M-6 Drum And Reel Capacity ............................................................................................................... M-84 A. Design Factor ............................................................................................................................. M-84 B. Design Factor Charts .................................................................................................................. M-90 M-7 Wire Rope - Ton Mile Calculations - Special Applications ............................................................ M-105 M-8 Appendix - Ton Mile Formulas .................................................................................................... M-109 1. Round-Trip Operations: ............................................................................................................. M-109 2. Drilling Operations: .................................................................................................................... M-109 3. Coring Operations: .................................................................................................................... M-110 4. Setting Casing Operations: .......................................................................................................... M-111 5. Short Trip Operations: ................................................................................................................ M-111

Chapter N - Lubrication ..................................................N-1 N1. Lubrication ........................................................................................................................................ N-4 I. Conditions ....................................................................................................................................... N-4 IIA. Glossary ...................................................................................................................................... N-4 IIB: Definitions -- General ................................................................................................................... N-5 IIC. Definitions -- Lubricant Additives ................................................................................................. N-7

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N2. Types Of Lubrication ......................................................................................................................... N-9 I. Engine Crankcase Oil ...................................................................................................................... N-9 C. Government and Industry Specifications ....................................................................................... N-10 II. Industrial Gear Oils ...................................................................................................................... N-11 III. Hydraulic Oils ............................................................................................................................. N-12 IV. Grease ........................................................................................................................................ N-13 V. Tool Joint Lubricants .................................................................................................................... N-14 VI. Rust Preventives ......................................................................................................................... N-14 N3. Lubrication Practices ....................................................................................................................... N-15 I. Introduction ................................................................................................................................... N-15 II. General Hints On Lubrication ....................................................................................................... N-15 III. Cooling System ........................................................................................................................... N-15 IV. Record Keeping .......................................................................................................................... N-16 V. Storage And Handling Of Lubricants ............................................................................................. N-18 N4. Cold Weather Conditions ................................................................................................................. N-19 1. Introduction .................................................................................................................................. N-19 II. Rig Enclosures ............................................................................................................................. N-19 III. Engines And Power Plants .......................................................................................................... N-19 IV. Chain Drives, Compounds, Gear Reducers, Slush Pumps & Rotary Tables ................................... N-20 V. Grease Applications ..................................................................................................................... N-21 VI. Thread Lubricants ....................................................................................................................... N-22 VII. Blow-out Preventers .................................................................................................................. N-22 VIII. Machinery Storage ................................................................................................................... N-22 IX. Lubricant Storage ....................................................................................................................... N-22 X. Summary ..................................................................................................................................... N-23 XI. Fuel ............................................................................................................................................ N-23

Chapter O - Drilling Fluids .............................................O-1 1. Drilling Fluids: Functions And Tests ....................................................................................................... O-4 I. General ........................................................................................................................................... O-4 II. Functions ....................................................................................................................................... O-4 III. Test and Mud Properties ............................................................................................................... O-4 IV. Factors Affecting Mud Performance and Cost .............................................................................. O-6 2. Types Of Drilling Fluids ......................................................................................................................... O-7 I. Water Based Drilling Fluids .............................................................................................................. O-7 II. Oil Muds ..................................................................................................................................... O-13 3. Trouble Shooting ................................................................................................................................ O-14 I. Problems ....................................................................................................................................... O-14 II. Specific Problems ........................................................................................................................ O-16 4. Calculations ........................................................................................................................................ O-23 I. Calculations ................................................................................................................................... O-23 II. Additional Aids ............................................................................................................................ O-24 5. Additives For Drilling Fluids ................................................................................................................ O-33 I. Definitions for Drilling Fluid Classification ....................................................................................... O-33 II. Drilling Fluid Systems ................................................................................................................... O-33 III. Fluid Additive Functions .............................................................................................................. O-34

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Chapter P - Hole Deviation and Horizontal Drilling ... P-1 References ......................................................................................................................................... P-3 P-1 Straight Hole Drilling .......................................................................................................................... P-4 I. Introduction ..................................................................................................................................... P-4 II. Problems Associated With Dog-legs And Key Seats ..................................................................... P-10 III. Control Of Hole Angle? ............................................................................................................. P-13 IV. Factors To Consider When Designing Packed Hole Assembly ..................................................... P-34 V. Packed Hole Assemblies .............................................................................................................. P-35 VI. Stabilizing Tools .......................................................................................................................... P-38 VII. Conclusion ................................................................................................................................ P-51 P-2 Controlled Directional Drilling ........................................................................................................... P-52 I. Introduction ................................................................................................................................... P-52 II. Basic Deflection Patterns .............................................................................................................. P-54 III. Planning And Supervising The Directional Well ............................................................................ P-55 IV. Sub Surface Surveying ................................................................................................................ P-59 V. Deflection Tools ........................................................................................................................... P-66 VI. Orientation Of Deflection Tools ................................................................................................... P-73 VII. Principles Of Directional Drilling Stabilization .............................................................................. P-75 VIII. Dog-leg Severities .................................................................................................................... P-78 P-3 Horizontal Drilling ............................................................................................................................ P-84 A. Planning ....................................................................................................................................... P-84 B. Proper Drill Stem Design .............................................................................................................. P-92 C. Factors Determining Optimum Well Profiles .................................................................................. P-97 D. Four Factors That Affect Fatigue Damage .................................................................................. P-101 E. Directional Control In The Horizontal Section .............................................................................. P-105

Chapter R - Hydraulics ....................................................R-1 Preface ............................................................................................................................................... R-3 R-1 Introduction to the Bit Hydraulics Problem ......................................................................................... R-4 Determine Maximum Operating Pressure and Volumetric Discharge ..................................................... R-4 Tables R-1 Mud Circulation Equipment - Pump Data ........................................................................ R-13 R-2A Circulation Rates for Duplex Pumps ........................................................................................ R-21 R-2B Circulation Rates For Triplex Pumps ........................................................................................ R-31 R-3A Annular Velocity Around Drill Pipe .......................................................................................... R-36 R-3B Annular Velocity Around Drill Collars ...................................................................................... R-45 R-4 Surface Equipment Descriptions ................................................................................................ R-62 R-5 Surface Equipment Pressure Losses ......................................................................................... R-62 R-6 Drill Pipe Bore Pressure Losses ................................................................................................. R-65 R-7 Drill Pipe Annular Pressure Losses ............................................................................................. R-73 R-8 Drill Collar Pressure Losses ....................................................................................................... R-84 R-9 Drill Collar Annular Pressure Losses .......................................................................................... R-89 R-10 Selection Of Jet Nozzle Size .................................................................................................. R-104 R-11 Calculation Of Jet Velocity ..................................................................................................... R-114 R-12 Discharge Area Of Jet Nozzles .............................................................................................. R-124 R-13-1. Equations Used in Hydraulic Calculations ........................................................................... R-125 A. Bit Selection Equations ............................................................................................................... R-126

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D. Drilling Fluid Property Equations ................................................................................................ R-133 R-13-8 Nomenclature for Equations - Smith Int. ............................................................................. R-134 R-13-9 Nomenclature and Terminology .......................................................................................... R-137 R-13-10. Pipe Flow Equations ....................................................................................................... R-138 R-13-11. Annular Flow Equations ................................................................................................... R-138 R-13-12. Bit Hydraulic Calculations ................................................................................................ R-139 R-13-13. Chip Rate Calculations .................................................................................................... R-140 R-13-14. Completed Work Sheet ................................................................................................... R-141 R-13-15. Blank Work Sheet ........................................................................................................... R-142

Chapter T - Cementing..................................................... T-1 T1. Cementing............................................................................................................................................ T-4 I. Introduction ..................................................................................................................................... T-4 II. Types Of Cement Used In Oil Wells ............................................................................................... T-4 T2. Casing Strings .................................................................................................................................... T-9 I. Introduction ..................................................................................................................................... T-9 II. Plug Back Cementing ................................................................................................................... T-12 III. Squeeze Cementing ..................................................................................................................... T-15 IV. Horizontal Well Completions ....................................................................................................... T-21 T3. Balancing A Plug .............................................................................................................................. T-22 I. Balancing A Plug ........................................................................................................................... T-22 II. Calculating Fillup .......................................................................................................................... T-24 III. Pumping Large Diameter Surface-string Up The Hole .................................................................. T-24 T-4. Estimating Cement Required For Various Cementing Jobs ................................................................ T-26 Glossary of Cementing/Casing Terms ...................................................................................................... T-27

Chapter U - Electric Drilling Rigs ..................................U-1 U-1. Silicon Controlled Rectifier Systems .................................................................................................. U-4 1. Introduction .................................................................................................................................... U-4 A. DC/DC and SCR Systems ............................................................................................................. U-4 B. DC Drilling Motors ........................................................................................................................ U-4 U-2. SCR (AC/DC) Power Systems ........................................................................................................ U-6 A. AC Electrical Power Generation ..................................................................................................... U-6 A3. AC Switchgear ............................................................................................................................ U-7 B. AC/DC Conversion ....................................................................................................................... U-8 U-3. DC/DC Power Systems ................................................................................................................. U-13 A. Introduction ................................................................................................................................. U-13 B. Controls ....................................................................................................................................... U-13 C. Braking ........................................................................................................................................ U-13 D. System Protection ........................................................................................................................ U-14 E. Driller's Console ........................................................................................................................... U-14 U-4. Maintenance ................................................................................................................................... U-15 General ............................................................................................................................................ U-15 Maintenance Section Outline ............................................................................................................. U-15 Daily Maintenance: ........................................................................................................................... U-22 Monthly Maintenance: ....................................................................................................................... U-22 Repair: ............................................................................................................................................. U-22

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U-5. Technical Index .............................................................................................................................. U-23 1. Maintenance Checklists: ................................................................................................................ U-23 2. Reference Handbooks .................................................................................................................. U-24

Chapter V - General Information ................................... V-1 Introduction ........................................................................................................................................ V-3 1. Selected API Publications (Producton) .................................................................................................. V-4 Introduction ........................................................................................................................................ V-4 Belting ................................................................................................................................................ V-4 Derricks And Masts ........................................................................................................................... V-4 Tubular Goods .................................................................................................................................... V-4 Valves And Wellhead Equipments ....................................................................................................... V-6 Drilling Equipment ............................................................................................................................... V-6 Hoisting Tools ..................................................................................................................................... V-7 Wire Rope .......................................................................................................................................... V-7 Oil Well Cements ................................................................................................................................ V-7 Drilling Fluid Materials ........................................................................................................................ V-8 Drilling Well Control Systems .............................................................................................................. V-9 Drilling And Production Recommended Practices ................................................................................ V-9 Special Publications .......................................................................................................................... V-10 2. Hole and Pipe Data ............................................................................................................................ V-13 Capacity ........................................................................................................................................... V-13 Displacement of Hole and Pipe ......................................................................................................... V-22 Volume and Height between Pipe and Casing: .................................................................................... V-27 Volume and Height between Pipe and Hole: ....................................................................................... V-39 3. Field Gas Lines ................................................................................................................................... V-49 Pipeline Flow Of Gas Formulae And Conversions ............................................................................. V-49 Gas Delivery, Based on 1000 Ft pipeline lengths ................................................................................ V-51 Gas Delivery, Based on 1 Mile pipeline lengths .................................................................................. V-54 Gas Delivery, Based on 10 Mile pipeline lengths ................................................................................ V-57 4. Waterlines - Line Pipe Capacities ........................................................................................................ V-60 5. Tank and Pit Capacity ......................................................................................................................... V-62 6. Conversion Factors ............................................................................................................................ V-68 7. Density of Oilfield Materials and Wood ............................................................................................... V-80 8. Density of Fluids and Petroleum Products ............................................................................................ V-82 9. Soil Bearing Capacity ......................................................................................................................... V-83

Chapter Y - Drilling Mud Processing ............................Y-1 1. Introduction - Solids Control Removal Systems ..................................................................................... Y-4 A. Overview ....................................................................................................................................... Y-4 B. Solids Removal Theory ................................................................................................................. Y-5 C. Equipment Arrangement ................................................................................................................. Y-9 II. Solids Control Equipment ................................................................................................................... Y-11 A. Shale Shakers .............................................................................................................................. Y-11 B. Degassers .................................................................................................................................... Y-26 C. Hydrocyclones ............................................................................................................................. Y-30 D. Mud Cleaners .............................................................................................................................. Y-39

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E. Centrifuges ............................................................................................................................... Y-50 III. Surface Circulating Equipment ........................................................................................................... Y-55 A. Introduction ................................................................................................................................. Y-55 B. Considerations and Methods for Sizing Surface Mud Systems ....................................................... Y-55 C. Special Considerations ................................................................................................................. Y-56 D. Sizing Steel Pits ............................................................................................................................ Y-57 E. Earthen Pits .................................................................................................................................. Y-58 F. Reserve and/or Waste Pits ............................................................................................................ Y-59 4. System Rig-up Information .................................................................................................................. Y-61 A. Solids Control System Layout Considerations ............................................................................... Y-61 B. Centrifugal Pump Selection and Piping Design ............................................................................... Y-70 C. Mud Troughs After the Shale Shakers .......................................................................................... Y-88

Chapter Z - Glossary ........................................................ Z-1 IADC Glossary - A ............................................................................................................................ Z-3 IADC Glossary - B ............................................................................................................................ Z-4 IADC Glossary - C ............................................................................................................................ Z-7 IADC Glossary - D .......................................................................................................................... Z-10 IADC Glossary - E ........................................................................................................................... Z-13 IADC Glossary - F ........................................................................................................................... Z-13 IADC Glossary - G .......................................................................................................................... Z-15 IADC Glossary - H .......................................................................................................................... Z-17 IADC Glossary - I ............................................................................................................................ Z-18 IADC Glossary - J ........................................................................................................................... Z-19 IADC Glossary - K .......................................................................................................................... Z-20 IADC Glossary - L ........................................................................................................................... Z-20 IADC Glossary - M ......................................................................................................................... Z-21 IADC Glossary - N .......................................................................................................................... Z-23 IADC Glossary - O .......................................................................................................................... Z-23 IADC Glossary - P ........................................................................................................................... Z-24 IADC Glossary - Q .......................................................................................................................... Z-26 IADC Glossary - R .......................................................................................................................... Z-26 IADC Glossary - S ........................................................................................................................... Z-30 IADC Glossary - T ........................................................................................................................... Z-34 IADC Glossary - U .......................................................................................................................... Z-36 IADC Glossary - V .......................................................................................................................... Z-36 IADC Glossary - W ......................................................................................................................... Z-36 IADC Glossary - X .......................................................................................................................... Z-38 IADC Glossary - Y .......................................................................................................................... Z-38 IADC Glossary - Z ........................................................................................................................... Z-38

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Chapter A Bit Classification and Grading

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Table of Contents - Chapter A Bit Classification and Grading A-1 First Revision To The IADC Fixed Cutter Dull Grading System .......................................................... A-7 Contributors ....................................................................................................................................... A-7 Summary ............................................................................................................................................ A-7 Abstract ............................................................................................................................................. A-7 Introduction ........................................................................................................................................ A-7 System Enhancements ......................................................................................................................... A-7 Application Of Dull Grading System .................................................................................................... A-9 Conclusion ....................................................................................................................................... A-14 References ....................................................................................................................................... A-14 Acknowledgements .......................................................................................................................... A-14 A2 - IADC Fixed Cutter Classification System ........................................................................................ A-16 Development Of A New IADC Fixed Cutter Drill Bit Classification System ....................................... A-16 Contributors ..................................................................................................................................... A-16 Abstract ........................................................................................................................................... A-16 Introduction ...................................................................................................................................... A-16 Background ...................................................................................................................................... A-17 Proposed System ............................................................................................................................. A-20 Conclusions ...................................................................................................................................... A-28 References ....................................................................................................................................... A-28 Acknowledgements .......................................................................................................................... A-28 A3 - The IADC Roller Bit Classification System ...................................................................................... A-29 Summary .......................................................................................................................................... A-29 Series And Type ............................................................................................................................... A-33 Characters 1 And 2 .......................................................................................................................... A-33 Cutting Action .................................................................................................................................. A-33 Tooth Count And Geometry .............................................................................................................. A-34 Insert Shape Comparison .................................................................................................................. A-34 Cone Design And Orientation ........................................................................................................... A-34 Cutting Structure Metallurgy .............................................................................................................. A-35 Bearing/Gage Design Configuration (Character 3) .............................................................................. A-35 Features Available (Optional 4th Character) ...................................................................................... A-37 A4 - IADC Roller Bit Dull Bit Grading System ........................................................................................ A-60 Description of the IADC Roller Bit Dull Bit Grading System .............................................................. A-60 A4. IADC Roller Bit Dull Grading System ......................................................................................... A-60 Discussion Of Dulling Characteristics ................................................................................................. A-66 BC (Broken Cone) or BF (Bond Failure) - (Fig. A4-3) ..................................................................... A-67 BT (Broken Teeth) - (Fig. A4-4) ...................................................................................................... A-68 BU (Balled Up) - (Fig. A4-5) ........................................................................................................... A-69 CC (Crocked Cone) - (Fig. A4-6) ................................................................................................... A-70

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CD (Cone Dragged) - (Fig. A4-7) .................................................................................................... A-71 CI (Cone Interference) - (Fig. A4- 8) ............................................................................................... A-72 CR (Cored) - (Fig. A4-9) ................................................................................................................. A-73 CT (Chipped Teeth) - (Fig. A4-10) .................................................................................................. A-74 ER (Erosion) - (Fig. A4-11) .............................................................................................................. A-75 FC (Flat Crested Wear) - (Fig. A4-12) ............................................................................................. A-76 HC (Heat Checking) - (Fig. A4-13) .................................................................................................. A-77 JD (Junk Damage) - (Fig. A4-14) ..................................................................................................... A-78 LC (Lost Cone) - (Fig. A4-15) ......................................................................................................... A-79 LN (Lost Nozzle) - (Fig. A4-16) ...................................................................................................... A-80 LT (Lost Teeth) - (Fig. A4-17) ......................................................................................................... A-81 OC (Off Center Wear) - (Fig. A4-18) .............................................................................................. A-82 PB (Pinched Bit) - (Fig. A4-19) ........................................................................................................ A-83 PN (Plugged Nozzle) - (Fig. A4-20) ................................................................................................. A-84 RG (Rounded Gage) - (Fig. A4-21) .................................................................................................. A-85 SD (Shirttail Damage) - (Fig. A4-22) ................................................................................................ A-86 SS (Self Sharpening Wear) - (Fig. A4-23) ........................................................................................ A-87 TR (Tracking) - (Fig. A4-24) ............................................................................................................ A-87 WO (Washed Out Bit) - (Fig. A4-25) ............................................................................................... A-88 WT (Worn Teeth) (Fig. A4-26) ........................................................................................................ A-89 NO (No Dull Characteristics) ........................................................................................................... A-89

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Chapter A Bit Classification And Grading The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study. The following industry representatives have contributed to the development and updating of this chapter: FIXED CUTTER BITS B. D. Brandon

Hughes Christensen

Jerry Cerkovnik

Hughes Christensen

Earl Koskie

DBS

B. B. Bayoud

Hughes Christensen

Fred Coston

Smith Diamond

R. I. Clayton

Security Division Dresser Industries

M. E. Anderson

Hughes Christensen

K. T. Hollister

Hycalog

Jim Senger

Security Division Dresser Industries

Ralph Neimi

Cliffs Drilling

ROLLER CONE BITS Ed Andrews

Kenting Apollo Drilling, Inc.

Dennis Cox

Enserch

Jim Dahlems

Security Division Dresser Industries

Eric Elrod

Walker-McDonald Mfg. Co.

Roy Estes

Rock Bit International Inc.

Martyn Fear

BP Exploration

John Gieck

Hughes Tool Company

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Sam Hampton

Helmerich & Payne

Hal Kendall

Amoco

William Kost

Smith International

Dave Lafuze

Varel Manufacturing Company

Rick Lyon

Sandvik Rock Tools

Dave McGehee

Reed Tool Company

Ralph Neimi

Cliffs Drilling

Chris Reinsvold

Hughes Tool Company

Jim Senger

Security Division Dresser Industries

Steve Steinke

Smith International

Brian Tarr

Mobil Exploration

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A-1 First Revision To The IADC Fixed Cutter Dull Grading System Contributors B. D. Brandon* and Jerry Cerkovnik**, Eastman Christensen; Earl Koskie, DBS; B. B. Bayoud*, Eastman Christensen; Fred Colston, Smith Diamond; R. I. Clayton*, Security; M. E. Anderson*, Eastman Christensen; K. T. Hollister*, Hycalog; Jim Senger*, Security Division Dresser Industries; and Ralph Niemi*, Cliffs Drilling Company * SPE Member; ** IADC and SPE Member.

Summary This paper was prepared for presentation at the 1992 IADC/SPE Drilling Conference held in New Orleans, Louisiana, February 18-21, 1992. This paper was selected for presentation by an IADC/SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers or the International Association of Drilling Contractors and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the IADC or SPE, their officers, or members. Papers presented at IADC/SPE meetings are subject to publication review by Editorial Committees of the IADC and SPE. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Write Librarian, SPE, P. O. Box 833836, Richardson, TX 75083-3836 U.S.A., Telex 730989 SPEDAL. Copyright 1992, IADC/SPE Drilling Conference

Abstract This paper is one of two describing changes to the IADC Classification and Dull Grading Systems for fixed cutter bits. Dull grading system revisions, described herein, were implemented to improve utilization and effectiveness of the dull grading system. Classification system changes were required as a result of improvements in bit technology and applications, and are detailed in the companion paper SPE 23940.

Introduction The IADC Fixed Cutter Work Group this year audited the 1987 Fixed Cutter Dull Grading System and determined that some minor refinement was necessary. As was the case with introduction of the fixed cutter dull grading system in 1987, the objective of this revision was to facilitate creation of a "mental picture" of a worn bit's physical condition through a standardized evaluation of certain bit characteristics? Because the system provides an industry-wide standard for recording the physical condition of the worn bit for future reference, the meaning of a dull grade should be subject to as little misinterpretation as possible. Therefore, committee discussions focused on two specific areas: improving the definition of "usable cutter height" as it relates to evaluation of PDC cutter wear, and making minor enhancements to the wear characteristic codes.

System Enhancements The format of the dull grading chart, shown in Figure 1, has not changed under this revision.

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Figure A1-1 Format of the Dull Bit Grading Chart

Eight factors are recorded: the first four spaces describe the extent and location of wear of the "Cutting Structure". The next two spaces address other criteria for bit evaluation, with the fifth space reserved for grading "Bearing" wear of roller cone bits. This space is always marked with an "X" when fixed cutter bits are graded.

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The sixth space indicates "Gauge Measurement". The last two positions allow for "Remarks" which provide additional information concerning the dull bit, including "Other (or secondary) Dull Characteristics" and "Reason Pulled", respectively. The revised system grades all PDC cutters based on condition of the visible diamond table of the cutter, regardless of cutter shape or exposure. This differs from the former practice of grading PDC cutters based on "usable cutter height" remaining. It was determined that the definition of "usable cutter height" for PDC bits was subject to misinterpretation, given the initial positioning of some PDC cutters "within" the bit blade on some designs. Additional enhancements include addition of a dull characteristic code, "BF", to distinguish "bond failure" between the cutter and its support backing from "LT", loss or a cutter. In addition, the optional designations "RR" or "NR" were added to allow for indication of whether a bit is "rerunnable" or not. Application of these minor revisions will further "standardize" the meaning of a dull grade. Examples of dull characteristics are shown in Figure A1-2

Application Of Dull Grading System Evaluating "Cutting Structure" : Inner/Outer Rows: Spaces 1 and 2. See Figure A1-1a. Figure A1-1a Code for Cutting Structure

CUTTING STRUCTURE 0 - No Wear 4 - 50% Wear 8 - No Useable Cutting Structure Using a linear scale from 0 to 8, as before, a value is given to cutter wear in both the inner and outer rows of cutters. Grading numbers increase with amount of wear, with 0 representing no wear, and 8 meaning no usable cutters left. A grade of 4 indicates 50% wear. For surface-set bits, the scale of cutter wear is determined by comparing the initial cutter height with the amount of usable cutter height remaining. Rather than evaluating "usable cutter height", PDC cutter wear is now measured across the diamond table, regardless of the cutter shape, size, type or exposure. This eliminates the difficulty in determining the initial cutter height on a bit in which PDC cutters are designed with less-than-full exposure. For both surface-set and PDC bits, the average amount of wear for each area is recorded, with 2/3 of the radius representing the "inner rows" and the remainder representing the "outer rows" (Figure A1-3).

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Figure A1-3 Inner/Outer Row Designa-

on it

Average wear is calculated by simply averaging the individual grades for each cutter in the area. Dull Characteristics: Space 3. See A1-1d. Figure A1-1d Code for Dulling Characteristics

The most prominent or "primary" physical change from new condition of a cutter is recorded in the third space. "Other" dull characteristics of the bit are noted in the seventh space -- the difference being that space 3 describes cutter wear, while space 7 may concern other wear characteristics of the bit as a whole. Codes for dull characteristics of both categories are listed in the table in Figure 1, including the addition of "BF" for bond failure.

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Location: Space 4. See A1-1c. Figure A1-1b Code for Location on Bit

LOCATION C - Cone N - Nose (Row) T - Taper S - Shoulder G - Gauge A - All Areas Rows M - Middle Row H - Heel Row The fourth space is used to indicate the location of the primary dull characteristic noted in the third space. Locations are designated in the diagrams of Figure A1-4.

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Figure A1-4 Location Designation

They include: C - cone, N - nose (row), T - taper, S - shoulder, G - gauge, A - all areas, M - middle row and H heel row.

Other Evaluation Criteria Bearing: Space 5. See Figure A1-1c.

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Figure A1-1c Code for Bit Bearing, Seals

This space is used only for roller cone bits. It will always be marked "X" for fixed cutter bits. Gauge: Space 6. See Figure A1-1e. Figure A1-1e Code for Gauge

The sixth space is used to record the condition of the bit gauge. 'I' is used if the bit is still in gauge. Otherwise, the amount the bit is undergauge is recorded to the nearest 1/16th of an inch.

Additional "Remarks" Other Dull Characteristics: Space 7. See Figure A1-1d. In the seventh space, secondary evidence of bit wear is noted. Such evidence may relate specifically to cutting structure wear, as recorded in the third space, or may note identifiable wear of the bit as a whole, such as "erosion". Many times, this "secondary" dull grade identifies the cause of the dull characteristic noted in the third space. Codes for grading both "primary" and "secondary" dull characteristics are listed in the table shown in Figure A1-1d. The designations "RR" and "NR" have been included as options for noting whether the bit is rerunnable or not. Examples of dull characteristics are shown in Figure A1-2 Reason Pulled: Space 8. See Figure A1-1f.

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Figure A1-1f Reasons Pulled

The eighth space is used to record the reason the bit was pulled. A list of codes is shown in Figure A1-1f.

Conclusion Despite their minor nature, the changes described in this "First Revision to the IADC Dull Grading System" are expected to facilitate easier, more accurate evaluation of fixed cutter bit wear. With the addition of new dull characteristic codes, more specific descriptions of bit wear are possible, while the revised criteria for measuring PDC cutter wear will ensure a standard approach is taken in each instance. Thus, a dull grade ultimately will "mean the same thing" to everyone, as originally intended.

References 1. Clark, D. A., et. al., "Application of the New IADC Dull Grading System for Fixed Cutter Bits", paper SPE/ IADC 16145, presented at the 1987 SPE/IADC Drilling Conference, New Orleans, La., March 15-18, 1987.

Acknowledgements Members of the Committee are acknowledged for their contributions to this paper: Bethany Brandon, Jerry Cerkovnik, Bruce Bayoud and Mark Anderson of Eastman Christensen; Fred Colston, Smith Diamond; Robert Clayton and Jim Senger of Security; Kelly Hollister, Hycalog; Earl Koskie, DBS; and Ralph Niemi, Cliffs Drilling Company.

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Worn Cutter (WT)

Worn Cutters (WT), Balled Up (BU)

Plugged Nozzle Flow Pasage (PN)

Bond Failure (BF)

Lost Cutters (LT), Erosion (ER)

Heat Checking (HC)

Broken Cutters (BT)

Broken Cutter (BT)

Junk Damage (JD)

Chipped Cutters (CT)

Erosion (ER), Lost Cutters (LT)

Rounded Guage (RG)

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A2 - IADC Fixed Cutter Classification System Development Of A New IADC Fixed Cutter Drill Bit Classification System Contributors B. D. Brandon* and Jerry Cerkovnik**, Eastman Christensen; Earl Koskie, DBS; B. B. Bayoud*, Eastman Christensen; Fred Colston, Smith Diamond; R. I. Clayton*, Security; M. E. Anderson*, Eastman Christensen; K. T. Hollister*, Hycalog; Jim Senger*, Security Division Dresser Industries; and Ralph Niemi*, Cliffs Drilling Company * SPE Member; ** IADC and SPE Member; Copyright 1992, IADC/SPE Drilling Conference

Summary This paper was prepared for presentation at the 1992 IADC/SPE Drilling Conference held in New Orleans, Louisiana, February 18-21, 1992. This paper was selected for presentation by an IADC/SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers or the International Association of Drilling Contractors and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the IADC or SPE, their officers, or members. Papers presented at IADC/SPE meetings are subject to publication review by Editorial Committees of the IADC and SPE. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Write Librarian, SPE, P. O. Box 833836, Richardson, TX 75083-3836 U.S.A., Telex 730989 SPEDAL.

Abstract Following extensive review of the existing system, development of a new IADC Fixed-Cutter Drill Bit Classification System was initiated in late 1990, based on input gathered from the industry concerning the change. It was determined that existing fixed-cutter bit classifications, which attempted to describe each bit style individually, were not being used. In contrast, the success of the roller cone bit classification system was believed to lie in its grouping of similar bit styles into categories, thus allowing users to relate familiar bit styles with unfamiliar ones. Specifically, the IADC Fixed-Cutter Work Group committee undertaking the task developed a fixed-cutter bit reference chart patterned after the existing roller cone classification table, which would allow bit styles to be grouped by similar type. IADC classification codes for each bit are then generated by placing the bit style on the chart in the category which best describes it, thus grouping similar bit types under a single category. The new classification system is composed of our characters, designating body material, cutter density, cutter size or type, and profile, respectively. It is presented as an attempt to improve the ability to classify and thus employ fixed-cutter PDC and diamond drill bits more effectively in the drilling industry.

Introduction While the existing IADC Drill Bit Classification System was considered quite descriptive, it was this characteristic which made it subject to misinterpretation and inconsistency. Various ambiguities in manufacturers' use of the existing classifications made it difficult for useful cross-reference comparisons to be made.

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It was determined that any new IADC classification system would have to differ significantly from the existing system in order to solve the problems and be of greater utility to the industry. Since the current roller cone bit classification system, which enjoys wide acceptance and use, ranges from the softest formation bits to hard formation bits as the codes vary from IXX to 9XX, there was precedent to consider the IADC code as somewhat indicative of application. Developing a fixed-cutter classification chart similar to the existing roller cone bit classification chart would maximize the advantages inherent in that chart, while minimizing the need for education on how to use the new chart.

Background The original intention of instituting the IADC coding was to assist in evaluating various bits with regard to design, operating practices and performance, and to facilitate product selection as the bit market continues to grow. However, none of these goals is attainable if misinterpretation of design criteria occurs, which unfortunately, often was the case with the existing fixed-cutter classification system. While the problems of interpretation of the current fixed-cutter classification system are not as profound in areas actively represented by bit companies who may have daily contact with the end user, there exists some confusion for volume overseas tenders. In these cases, the user generally specifies the IADC code given to a specific product he is accustomed to using. If the codes for tendered products differ from the specified code, regardless of the remaining conditions, the tender risks disqualification. Examples of the most pointed discrepancies in interpretation of the IADC system include:

Principle Cutting Elements IADC gives a prefix which allows for cutter type and body material, with no variations for hybrid or mixed cutter bits. For example, Figure A2-1 shows three bits with matrix bodies and which employ shaped, PDC material as the primary cutting element; yet they are identified 0366, M256 and M366.

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Figure A2-1 Code Discrepancy for Principle Cutting Element

While this is not a problem when manufacturers identify the primary cutting element regardless of secondary cutting elements or reinforcement, such inconsistency in designation of design criteria is a primary shortcoming of the existing system.

Bit Profile With the existing system, detailed profile variations were explained through ratios of outer and inner cones to bit diameter. However, three manufacturers who produce similar bits with round, "B", or large radius profile bits, classified them as D4X9, D5X9 and D9X9. Despite the fact that these bits were virtually indistinguishable, they each had a different profile designation (Figure A2-2).

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Figure A2-2 Code Discrepancy for Bit Profile

Cutter Size and Density The increased use of thermally stable diamond material in place of natural diamonds posed a problem in that various sizes of TSP are employed for various formation hardnesses. However, the only allowance for TSP in the existing IADC system was to allocate them to the "small cutter" category (7 to 9) of "synthetic diamonds". In PDC bits, cutter density was ambiguous to each manufacturer. Density, being a key bit characteristic, needed to be more clearly defined so that a ranking or grouping of similar bits could be made. An example of the variation in cutter density designation that occurred with the existing system in one 8-1/2" bit which was given the IADC code M315. The bit is reported to have a total of 55 cutting elements. It was given a designation of 5, indicating a medium size cutter set in medium density. By contrast, a bit containing a total of 53 cutters, was given IADC code M646, the 6 indicating a heavy density of medium size PDC cutters (Figure A2-3).

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Figure A2-3 Variation in Cutter Density Designation

An 8-1/2" bit with a total of 47-1/2" (13mm) cutting elements was classified S648, with the 8 designating medium density, small size cutters. However, "small size" cutters are defined under the existing system as those less than 3/ 8" in diameter. These inconsistencies in interpretation indicate a weakness in the current classification system which could be eliminated with introduction of clearer definitions of the various codes.

Proposed System The proposed system for fixed-cutter bit classification is notably simpler than the existing system. For example, it no longer considers hydraulics, except as is implied by the "fishtail" body style being indicative of tall standoff bladed designs with very good cleaning ability. Neither does it attempt to completely describe body style itself; only basic classifications of the overall length of the bit cutting face are considered. Figures A2-4 and A2-5 show the new charts for PDC and TSP and Natural Diamond classifications, respectively.

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Figure A2-4 Revised Classification System Table - PDC

Figure A2-5 Revised Classification System Table - TSP/ND

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Body Material In all classifications, the first digit now simply becomes M or S, for matrix or steel body construction respectively.

Density The second digit is labeled density, and ranges from 1 to 4 for PDC bits, and from 6 to 8 for surface-set bits using diamond-type cutters. Numerals 0, 5 and 9 are not defined, or are reserved for future use (Figure A2-6). Figure A2-6 Revised Cutter Density Designation Table

Because heavier density generally corresponds to tougher drilling applications, this digit is the one which implies an applications aspect as the digit increases. The more exact meaning of this digit, however, varies for PDC versus surface-set bits. For PDC bits, it relates to cutter count, while for surface-set bits, it relates to diamond size. This makes sense, considering how the concept of "density" relates to variations in application.

PDC Cutter Density Cutter density is based on total cutter counts, including standard gauge cutter count. For PDC bits, then, a designation of 1 represents light set and 4 represents heavy set. This basically corresponds to the variations one sees in bits intended for softer formations (lighter set) to harder formations (heavy set). Specifically, the following density rules were applied: Density 1 refers to 30 or fewer 1/2" cutters; Density 2 refers to 30 to 40;

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Density 3 indicates 40 to 50; and Density 4 refers to 50 or more 1/2" cutters. Larger cutter sizes are projected as 1/2" cutter densities, as are those smaller than 1/2". Manufacturers will classify their bits in these four categories depending on their internal criteria for this element of bit. design. Bits which are "border-line" could be put in either category, depending on the manufacturer's preference. Note: Special designs using additional gauge cutters, such as sidetrack bits, or bits for horizontal drilling, are not considered for the purpose of classification.

Surface-Set Cutter Density For surface-set diamond bits, the numbers 6 through 8 are used, which continues the idea that higher IADC-coded bits are used where formations may be harder or more abrasive. With these bits, the digit categorizes variations in the size of the cutter material. For example, in the density number column, Density 6 represents diamond sizes larger than 3 stones per carat; Density 7 represents diamond sizes from 3 stones per carat to 7 stones per carat; and Density 8 represents diamond sizes smaller than 7 stones per carat. Thus, diamond size becomes smaller as the digit varies from 6 to 8, which again, generally corresponds to what is used for harder or more abrasive formations.

Size or Type The digit in the code position which designates "size" or "type" of cutter, again varies depending upon whether it refers to a PDC bit or a surface-set bit (Figure A2-7).

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Figure A2-7 Revised Cutter Size or Type Designation Table

Specifically, the third digit represents the size of PDC cutter on this type of bit: Size 1 indicates PDC cutters larger than 24mm in diameter, such as the 1" diameter PDC cutter bit. Size 2 represents cutters from 14mm to 24mm in diameter, such as the 19mm (3/4") PDC cutter. Size 3 indicates smaller PDCs, including the conventional 13.3mm (1/2") PDC; and Size 4 is used for the smaller, 8mm diameter PDC. For surface-set bits, the third digit represents diamond type, with Type 1 indicating Natural Diamonds, Type 2 referring to TSP material; Type 3 represents combination cutter types, such as those which use mixed natural diamond and TSP material; and Type 4 applies only to the highest "density" bit, indicating an impregnated diamond bit.

Body Style (Profile) The fourth digit on the new chart simply gives an idea of basic appearance of the bit, based on overall length of the cutting face of the bit. The only exception is for PDC bits which can be classified as "fishtail" bits; in this ease, the ability of such bits to clean in fast-drilling, soft formations is felt to be a more important body style feature than its profile -- again, indicative of application (Figure A2-8).

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Figure A2-8 Revised Body Style Designation Table

Therefore, 1 represents both fishtail PDC bits and "flat" TSP and Natural Diamond bits, while 2, 3, and 4 indicate increasingly longer bit profiles of both types. A virtually flat PDC bit would be identified by a 2, A longflanked "turbine style" bit would be categorized as a 4. In lieu of developing a formula relating overall bit face length (depth) to bit diameter, each manufacturer is responsible for classifying their product offerings relative to industry-accepted standards for bit profiles, as indicated in Figure A2-9.

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Figure A2-9a Profile of a Fishtail Bit

Figure A2-9b Profile of a Short PDC Bit

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Figure A2-9c Profile of a Medium PDC Bit

Figure A2-9d Profile of a Long PDC Bit

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Conclusions Although the present IADC Drill Bit Classification System is able to describe the appearance of a bit, it fails to provide a simple means of grouping similar bits in categories, and ranking these categories. Therefore, a simplified classification system was developed which groups similar bit types under a common code. The format currently used by roller cone bits provided a well-accepted and well-understood reference from which to design a new fixed-cutter classification chart which would require minimal education for use. The usefulness of the roller cone classification was not in its descriptive codes, but in generation of the cross-reference chart which allows comparison of various manufacturers' bits. Similarly, the benefit of the new fixed-cutter classification system is that it allows classification and grouping of similar bits. In addition, the complications which made the previous system difficult to use are significantly reduced. While the new system gives up much potential differentiation which the previous system provided, its simplicity makes it more usable and "learnable".

References "IADC Fixed Cutter Bit Classification System", paper SPE/IADC 16142 presented at the 1987 SPE/IADC Annual Technical Conference, New Orleans, La. March 15-18.

Acknowledgements Members of the Committee are acknowledged for their contributions to this paper: Bethany Brandon, Jerry Cerkovnik, Bruce Bayoud and Mark Anderson of Eastman Christensen; Fred Colston, Smith Diamond; Robert Clayton and Jim Senger of Security; Kelly Hollister, Hycalog; Earl Koskie, DBS; and Ralph Niemi, Cliffs Drilling Company.

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A3 - The IADC Roller Bit Classification System Summary This section is adapted from IADC/SPE 23937, The IADC Roller Bit Classification System, presented at the IADC/SPE Drilling Conference, February 18-21, 1992, New Orleans, LA. The 1992 IADC roller bit classification standard defines a 4-character design-related code. The first 3 characters are numeric and the 4th character is alphabetic. The sequence of numeric characters is defined as "Series, Type, Bearing/Gage". The alphabetic 4th character describes "Features Available". Roller Bits can be listed on a reference chart according to the digits in the IADC code. Description of Characters in the IADC Classification The chart form (Fig. A3-1) is explained as follows: 1. First Character - Cutting Structure Series (1-8). See Fig. A3-1a. Figure A3-1a First Character - Cutting Structure Series

Eight categories or "Series" numbers describe general formation characteristics. Series 1 through 3 refer to steel tooth (milled tooth) bits. Series 4 through 8 refer to insert (tungsten carbide) bits.

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Within the steel tooth and insert groups, the formations become harder and more abrasive as the Series numbers increase. 2. Second Character - Cutting Structure Types (1-4). See Fig. A3-1b. Figure A3-1b Second Character - Cutting Structure Types

Each Series is divided into 4 "Types" or degrees of hardness. Type 1 refers to bits designed for the softest formation in a particular Series. Type 4 refers to the hardest formation within the Series. 3. Third Character- Bearing/Gage. See Fig. A3-1c.

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Figure A3-1c Third Character - Bearing-Gauge

Seven categories of bearing design and gauge protection are defined as "Bearing/Gage". Categories 8 and 9 are reserved for future use. 4. Fourth Character. See Fig. A3-1d.

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Figure A3-1d Fourth Character - Optional Features Available

Features Available (Optional) Sixteen alphabetic characters are used to indicate "Features Available" as shown in Fig. A3-1d. This includes special cutting structures, bearings, hydraulic configurations, and body gauge protection. Notes on 1, 2, 3, and 4 above. Series and Types are arranged in numerically-increasing rows from top to bottom. Bearing/Gage categories are arranged in numerically-increasing columns from left to right. This creates 224 spaces with an additional 64 spaces reserved for future use. Thus, the code 111 indicates a steel tooth bit equipped with standard non-sealed roller bearings and a cutting structure designed to drill the very softest formations. At the opposite corner of the chart, an 847 code indicates an insert bit equipped with scaled friction bearings and gauge protection, designed for the very hardest abrasive formations. Every roller cone bit can be assigned an exact position on the IADC classification chart. A comparison of the bits in each manufacturer's product line is thus obtained. It is the manufacturer's responsibility to assign the most appropriate IADC code to each of his bits. The fact that each bit has a distinct IADC code does not mean that it is limited to drilling only the narrow range of formations defined by a single box on the chart. All bits will, within reason, drill effectively in both softer and harder formations than that specified by this IADC code.

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Also, while competitive products with the same IADC code are built for similar applications, they may be quite different in design detail, quality, cost, and performance.

Series And Type Characters 1 And 2 Numerous bit design factors and operating parameters undergo systematic changes as one moves up, down, or across the IADC classification chart. A knowledge of these factors adds meaning to IADC bit codes and bit comparison charts. These design features are discussed below.

Cutting Action Soft formations (Series 1 - steel tooth, Series 4 and 5 insert) are generally drilled most effectively by a combination of deep tooth penetration and a gouging-scraping action. This action is produced by equipping soft formation bits with relatively long, sharp, widely-spaced teeth affixed to more curved and highly offset cones. Bit offset is created by offsetting the bearing journals from a concentric alignment with the bit centerline (Fig. A3-2). Figure A3-2 Cone Offset

"Softer" bits are typically applied with lower weight on bit (WOB) and higher rotary speed (RPM).

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In contrast, hard formations (Series 3 - steel tooth, or Series 7 and 8 - insert) are drilled more effectively by a chipping and crushing action. Hard formations are stronger than softer formation and more likely to break. Compared to soft formation designs, harder bits utilize shorter, blunter, more closely-spaced teeth affixed to less curved and low offset cones. "Harder" bits are typically applied with higher WOB and lower RPM. Manufacturers build various combinations of design traits into each bit model to produce the desired performance. Improper selection of design characteristics or operating parameters for a particular formation will result in inefficient drilling.

Tooth Count And Geometry As bit "hardness" increases, the most obvious design changes occur in the number, height, and shape of the teeth. Tooth count is minimized while tooth height and sharpness is maximized on soft formation bits. The WOB load is shared by just a few teeth at a time, producing deep tooth penetration into low compressive strength formations at moderate WOB levels. Much of the rock removal results from the tooth sliding (gouging) action which is affected by the degree of cone profile and cone offset. Harder bits require more tooth contact with the bottomhole and the teeth must bc designed to operate at higher WOB levels in order to overcome the greater compressive strength of the rock. As a result, the bit teeth become shorter, blunter, more closely spaced, and more numerous as the intended formation hardness increases.

Insert Shape Comparison Inserts can be categorized into basic chisel and conical/rounded shapes. Each design incorporates a tradeoff between durability and penetrating ability depending on the intended formation. Inserts designed for extremely hard formations have a short round shape in order to minimize insert breakage. Inserts designed for medium hard formations are given more of a projectile shape to increase the rate of penetration. Chisel shaped inserts appear in the middle-to-softer range of medium formation bits. In formations that are soft enough, chisels effectively deliver both a penetrating and scraping action which enhances the drilling rate. However, if certain layers in the formation are too hard, chisel inserts tend to chip and break more readily due to high stresses along the sharp edges. Soft formation bits employ either long chisel or conical shaped inserts. Most popular soft formation insert bit models are available with either type of teeth.

Cone Design And Orientation Harder formations are generally drilled at higher WOB levels than softer formations, and therefore require stronger cone shells and bearings. Since harder bits have shorter teeth, it is possible to increase the cone shell thickness and bearing journal diameter in order to meet the higher strength requirements. The thicker cone shells are more resistant to fatigue failure while the greater bearing journal surface area is capable of supporting higher loads. The bearing journal angle (relative to hole bottom) is reduced for softer bits and increased for harder bits. This alters the cone profile which in turn affects tooth action on the hole bottom and gauge cutter action on the wall of the hole. Softer bits have more highly profiled cones than harder bits. This increases the scraping action of both bottomhole and gauge teeth. The scraping action is beneficial for drilling soft formations but it will result in accelerated tooth and gauge wear if the formation is abrasive. Scraping action is minimized on hard formation bits where strength and abrasion resistance are emphasized in the design. The scraping and gouging action of softer bits is increased by slightly offsetting the bearing journals from alignment with the bit centerline. This journal arrangement and resultant cone orientation is called cone offset. Scraping action increases with cone offset. A non-offset design produces nearly true rolling action.

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Cutting Structure Metallurgy Bit tooth metallurgy is varied according to formation hardness. Different approaches are used on steel teeth and tungsten carbide insert bits. Steel teeth cutters are toughened by a carburizing (case hardening) process. Wearresistant hardfacing is then applied to one or more sides of the teeth on soft and medium bits. The selective hardfacing of one tooth side is intended to produce a "self-sharpening" wear effect. The purpose of hardfacing two or more sides is to maintain as much tooth height as possible. This has proven to extend cutting structure life over self-sharpening designs. Hardfacing is not applied to the inner rows of hard formation steel tooth cutters since the hardfaced material is too brittle for high impact loads. The grain size and cobalt content of tungsten carbide inserts is varied to alter the impact toughness and abrasion resistance of the insert. Softer formation inserts, which are usually run at higher rotary speeds, require increased toughness to resist breakage of the relatively long inserts. A cobalt content of 16% and average grain size of 6 microns is typical for such inserts. Hard formation inserts are generally run at higher WOB levels. Hard formation inserts have a more breakage-resistant geometry so abrasion resistance becomes the most important factor. Thus, the cobalt content is about 10% and the average grain size is approximately 4 microns.

Bearing/Gauge Design Configuration (Character 3) Four styles of bearing designs (Fig. A3-3) are generally available:

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Figure A3-3 Bearing Designs

Standard non-sealed roller bearings (columns 1 and 3) Air cooled roller beatings (column 2) Sealed roller beatings, (columns 4 and 5) Sealed friction beatings (columns 6 and 7). Another name for friction beatings is journal beatings. Columns 3, 5, and 7 designate bit designs that have additional gauge protection added to their cutting structure (Fig. A3-4).

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Figure A3-4 Gauge Configurations

Standard roller bearings are mud lubricated and are therefore subject to abrasive wear from rock cuttings and weighing material in the drilling fluid. Sealed roller bearings are lubricated by grease rather than drilling mud and thus tend to last longer. Sealed journal bearings provide better load distribution and extended bearing life. Extended bearing life is often desirable, but the manufacturing cost and bit price are greater for sealed bearing assemblies. Thus the most economical result is obtained by selecting the type of bearing that most closely meets or exceeds the life expectancy of the cutting structure. Roller bearing wear is usually a function of the WOB and the total number of revolutions. Thus roller bearings, including sealed designs, wear continuously throughout the drilling operation. Journal bearing wear usually results from seal failure which soon leads to loss of lubrication followed by rapid wear. Journal bearings are designed to undergo minimal wear unless the seal fails. Thus journal bearing life is affected mainly by seal related factors such as heat and, occasionally, chemical attack or mechanical damage.

Features Available (Optional 4th Character) A number of roller cone bits have features that are not indicated by the first 3 characters in the IADC code. Such features are important since they can affect bit cost, application, and performance. The 4th character of the IADC code is used to indicate "Features Available". Such alphabetic characters are defined as shown in Fig. 1. Following are representative examples of four character IADC roller bit codes. (1) 124E -- a soft formation, sealed roller bearing steel tooth bit with extended jets,

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(2) 437X - - a soft formation, sealed friction bearing insert bit, with gauge protection and chisel-shaped teeth. Some bit designs may have several combination of features available. In such cases, the most significant feature should be listed. Features available are as follows: A - Air Application - Identifies a bit specifically for applications with air as the drilling fluid. B - Special Beating Seal - Seal configuration which provides special application advantages such as high RPM capability. C - Center Jet - (Larger diameter bits are sometimes equipped with center jets (Fig. A3-5) to provide a more uniform distribution of flow and hydraulic energy beneath the bit. Figure A3-5 Center Jet

Almost all extended nozzle bits have center jets to provide a beneficial tooth-cleaning action that might otherwise be lost by concentrating all of the hydraulic energy on the bottomhole. Some manufacturers use diffuser-type center jets while others use standard rock bit jet nozzles. The pressure drop through these two types of jets is different and this should be taken into consideration when doing hydraulic calculations for bits equipped with center jets. D - Deviation Control - Cutting structure specifically designed to minimize deviation.

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E - Extended Jets - Extended jets (nozzles) are used mainly on soft formation bits for improved bottomhole cuttings removal. Higher jet impact energy is delivered to the hole bottom by extended jets. Extended jets (Fig. A3-6) are generally available on bits larger than 9.5 inches. Figure A3-6 Bit with Extended Nozzles

Miniature extended jets are not included in the "E" designation. G - Gage and Body Protection - Welded tungsten carbide deposits (hardfacing) or carbide inserts added to the shirttail to protect the seal and/or body in special applications such as geothermal and directional drilling (Fig. A3-7)

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Figure A3-7 Gauge Protection

H - Horizontal/Steering Application - Designed specifically for horizontal and steerable applications. I - Jet Deflection - These bits are used for making trajectory changes where the formations are soft enough to be fluid-eroded. Such bits usually contain two standard jet nozzles and one large jet nozzle and can be oriented to preferentially excavate the hole in a desired direction (Fig. A3-8).

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Figure A3-8 Jet Deflection Bit

L - Lug pads - Steel pads with tungsten carbide inserts applied to the bit body. These pads generally are very close to gauge diameter (Fig. A3-9).

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Figure A3-9 Bit with Lug Pads

M - Motor Application - Specifically designed for application on downhole motors. S - Standard Steel Tooth Model. T - Two-Cone Bits - Two-cone bits are relatively uncommon but sometimes utilized for obtaining an acceptable combination of deviation control and penetration rate (Fig. A3-10).

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Figure A3-10 Two Cone Bit

W - Enhanced Cutting Structure X - Predominantly Chisel Tooth Insert (Fig. A3-11)

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Figure A3-11 Chisel Tooth Inserts

Y - Conical Tooth Insert (Fig. A3-12)

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Figure A3-12 Conical Tooth Inserts

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A3-App. A1 Hughes Tool Company Bit Classification Chart

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A3-App. A2 Hughes Tool Company Bit Classification Chart

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A3-App. B1 Reed Tool Company Bit Classification Chart

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A3-App. B2 Reed Tool Company Bit Classification Chart

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A3-App. C1 Rockbit International Bit Classification Chart

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A3-App. C2 Rockbit International Bit Classification Chart

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A3-App. D1 Security Rock Bits Classification Chart

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A3-App. D2 Security Rock Bits Classification Chart

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A3-App. E1 Smith International Bit Classification Chart

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A3-App. E2 Smith International Bit Classification Chart

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A3-App. F1 Varel Manufacturing Bit Classification Chart

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A3-App. F2 Varel Manufacturing Bit Classification Chart

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A3-App. G1 Sandvik Rock Tools Bit Classification Chart

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A3-App. H1 Walker McDonald Bit Classification Chart

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A4 - IADC Roller Bit Dull Bit Grading System Description of the IADC Roller Bit Dull Bit Grading System Columns (1&2) Steel Tooth Bits Columns (1&2) Insert Bits Columns (1&2) Fixed Cutter Bits Column (3) Dull Characteristics Column (4) Location Column (5) Bearings/Seals Column (6) Gage Column (7) Other Dull Characteristics Column (8) Reason Pulled or Run Terminated Discussion Of Dulling Characteristics

A4. IADC Roller Bit Dull Grading System This section is adapted from IADC/SPE 23938, The IADC Roller Bit Dull Grading System, presented at the IADC/SPE Drilling Conference, February 18-21, 1992, New Orleans, LA. The IADC Dull Grading System (above) can be applied to all types of roller cone bits as well as all types of fixed cutter bits. Bits with steel teeth, tungsten carbide inserts, natural or synthetic diamond cutters can all be described with this system. A description of the dull grading system follows with each of the components explained as they apply to roller cone bits. Applications to fixed cutter bits is discussed in another section. 1. Column 1 (I-Inner) is used to report the condition of the cutting elements not touching the wall of the hole (Inner). The change from inner 2/3 of the cutting structure was made to reduce variations in grading and increase understanding of the system. 2. Column 2 (O-Outer) is used to report the condition of the cutting elements that touch the wall of the hole (Outer). In the previous version, this was the outer 1/3 of the cutting structure. This change reflects the importance of gauge and heel condition to good bit performance. In columns 1 and 2 a linear scale from 0-8 is used to describe the condition of the cutting structure as follows: A measure of combined cutting structure reduction due to lost, worn and/or broken inserts/teeth. 0 - No loss of cutting structure. 8 - Total loss of cutting structure.

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See Figure A1-1a Code for Cutting Structure Example: A bit missing half of the inserts on the inner rows of the bit due to loss or breakage with the remaining teeth on the inner rows having a 50% reduction in height due to wear, should be graded a 6 in column 1. If the inserts on the outer rows of the bit were all intact but were reduced by wear to half of their original height, the proper grade for column 2 would be 4. 3. Column 3 (D - Dull Characteristic - Cutting Structure) uses a two-letter code to indicate the major dull characteristic of the cutting structure. Figure 1 lists the two-letter codes for the dull characteristics to be used in this column. See Fig. D1-1d. See Figure A1-1d Code for Dulling Characteristics 4. Column 4 (L - Location) uses a letter or number code to indicate the location on the face of the bit where the cutting structure dulling characteristic occurs. See Fig. A1-1b.

Figure A1-1b Code for Location on Bit

NOTE: "G" (gauge area) replaces "H" that was used in the previous dull grading system. Location is defined as follows: Gage - Those cutting elements which touch the hole wall. Nose - The centermost cutting element(s) of the bit. Middle - Cutting elements between the nose and the gauge. All - All Rows Cone numbers are identified as follows: The number one cone contains the centermost cutting element. Cones two and three follow in a clockwise orientation as viewed looking down at the cutting structure with the bit sitting on the pin.

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5. Column 5 (B - Bearing/Seals) uses a letter or a number code,depending on bearing types, to indicate bearing condition of roller cone bits. For non-sealed bearing roller cone bits, a linear scale from 0-8 is used to indicate the amount of bearing life that has been used. A zero (0) indicates that no bearing life has been used (a new bearing) and an 8 indicates that all of the bearing life has been used (locked or lost). See Fig. A1-1c. Figure A1-1c Code for Bit Bearing, Seals

For sealed bearing (journal or roller) bits, a letter code is used to indicate the condition of the seal. An "E" indicates an effective seal, an "F" indicates a failed seal(s), and an "N" indicating "not able to grade" has been added to allow reporting when seal or bearing conditions cannot be determined. 6. Column 6 (G -- Gauge) is used to report on the gauge of the bit. The letter "T" (IN) indicates no gauge reduction. If the bit does have a reduction in gauge it is to be recorded in 1/16th's of an inch. The "Two Third's Rule" is correct for three-cone bits. See Fig. A1-1e. Figure A1-1e Code for Gauge

The Two Thirds Rule, as used for three cone bits, requires that the gauge ring be pulled so that it contacts two of the cones at their outermost points. Then the distance between the outermost point of the third cone and the gauge ring is multiplied by 2/3's and rounded to the nearest 1/16th of an inch to give the correct diameter reduction. See Fig. 2)

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Figure A4-2 2/3 Rule for Measuring Gauge

7. Column 7 (O - Other Dull Characteristics) is used to report any dulling characteristic of the bit, in addition to the cutting structure dulling characteristic listed in column 3 (D). Note that this column is not restricted to only cutting structure dulling characteristics. Figure A1-1d lists the two-letter codes to be used in this column. 8. Column 8 (R - Reason Pulled) is used to report the reason for terminating the bit run. Figure A1-1f lists the twoletter or three-letter codes to be used in this column. Figure A1-1f Code for Reasons Pulled

NOTE: "LIH" was added to indicate "Left in Hole".

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Figure A4-1 - IADC Dull Grading System

Column (1) Inner Cutting Structure: (All inner rows) Column (2) Outer Cutting Structure: (Gage row only) In columns 1 and 2 a linear scale from 0 to 8 is used to describe the condition of the cutting structure according to the following: Columns (1&2) Steel Tooth Bits A measure of lost tooth height due to abrasion and/or damage where: 0 - no lost, worn and/or broken inserts. 8 - all of cutting structure lost, worn and/or broken. Columns (1&2) Insert Bits A measure of total cutting structure reduction due to lost, worn and/or broken inserts where: 0 - no lost, worn and/or broken inserts. 8 - all inserts lost, worn and/or broken. Columns (1&2) Fixed Cutter Bits A measure of lost, worn and/or broken cutting structure where: 0 - no lost, worn and/or broken cutting structure. 8 - all of cutting structure lost, worn and/or broken. Column (3) Dull Characteristics: (Use only cutting structure related codes.) BC - Broken Cone*

Lost Nozzle - LN

BF - Bond Failure

Lost Teeth/Cutters - LT

BT - Broken Teeth/Cutters

Off Center Wear - OC

BU - Balled Up Bit

Pinched Bit - PB

CC - Cracked Cone*

Plugged Nozzle/Flow Pack - CD

CD - Cone Dragged*

Rounded Gage - RG

CI - Cone Interference

Ring Out - RO

CR - Cored

Shirttale Damage- SD

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CT - Chipped Teeth/Cutters

Self Sharpening Wear - SS

ER - Erosion

Tracking- TR

FC - Flat Crested Wear

Washed Out Bit - WO

HC - Heat Checking

Worn Teeth/Cutters - WT

JD - Junk Damage

No Dull Characteristic - NO

LC - Lost Cone * Show cone # or #'s under location (4). Column (4) Location:

Roller Cone

Fixed Cutter

N - Nose Row

Cone- C

M - Middle Row (Cone #1)

Nose - N

G - Gage Row (Cone #2)

Taper - T

A - All Rows (Cone #3)

Shoulder - S Gage - G All Areas - A

Column (5) Bearings/Seals:

Non-sealed Bearings A linear scale estimating bearing life used (0 - no life used, 8 - all life used, i.e. no bearing life remaining).

Sealed Bearings E - Seals Effective F - Seals Failed N - Not Able to Grade X - Fixed Cutter Bit (Bearingless) Column (6) Gage: (Measure in fractions of an inch.) See A4-2. 1

- in gauge

1/16 - 1/16" out of gauge

2/16 - 1/8" out of gauge

3/16 - 3/16" out of gauge

4/16 - 1/4" out of gauge

Column (7) Other Dull Characteristic: (Refer to Column 3 Codes.) Column (8) Reason Pulled or Run Terminated: BHA - Chg. Bottom Hole Assembly

Hrs. on Bit - HR

CM - Conditional Mud

Left in Hole - LIH

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CP - Core Point

Run Logs - LOG

CMF - Downhole Motor Failure

Pump Pressure - PP

DP - Drill Plug

Penetration Rate- PR

DSF - Drill String Failure

Rig Repair - RIG

DST - Drill Stem Test

Total/Casing Depth - TD

DTF - Downhole Tool Failure

Twist Off- TW

FM - Formation Change

Torque- TQ

HP - Hole Problems

Weather Conditions - WC

Discussion Of Dulling Characteristics BC (Broken Cone) or BF (Bond Failure) BT (Broken Teeth) BU (Balled Up) CC (Crocked Cone) CD (Cone Dragged) CI (Cone Interference) CR (Cored) CT (Chipped Teeth) ER (Erosion) FC (Flat Crested Wear) HC (Heat Checking) JD (Junk Damage) LC (Lost Cone) LN (Lost Nozzle) LT (Lost Teeth) OC (Off Center Wear) PB (Pinched Bit) PN (Plugged Nozzle) RG (Rounded Gage) SD (Shirttail Damage) SS (Self Sharpening Wear) TR (Tracking) WO (Washed Out Bit)

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WT (Worn Teeth) Dull Bit Grading Example Following is a discussion, and photographs of the dulling characteristics common to roller cone bits. While the possible causes listed and possible solutions for problem wear modes are not presumed to be exclusive. they represent situations commonly encountered in the field.

BC (Broken Cone) or BF (Bond Failure) - (Fig. A4-3) Figure A4-3 Broken Cone, BC

This describes a bit with one or more cones that have been broken into two or more pieces, but with most of the cone still attached to the bit. Broken cones can be caused in several ways. Some of the causes of BC are: Cone interference - where the cones run on each other after a bearing failure and break one or more of the cones. Bit hitting a ledge on trip or connection. Dropped drill string. Hydrogen sulfide embrittlement. BF (Bond Failure) Refers to Fixed Cutter Dull Condition

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BT (Broken Teeth) - (Fig. A4-4) Figure A4-4 Broken Teeth, BT

In some formations BT is a normal wear characteristic of tungsten carbide insert bits and is not necessarily an indicator of any problems in bit selection or operating practices. However, if the bit run was of uncommonly short duration, broken teeth could indicate one or more of the following: the need for a shock sub, too much WOB and/ or RPM, or improper bit application. Broken teeth is not considered a normal wear mode for steel tooth roller cone bits and may indicate improper bit application or operating practices. Some causes of BT are: Bit run on junk. Bit hitting a ledge or hitting bottom suddenly. Excessive WOB for application. Indicated by broken teeth predominantly on the inner and middle row teeth. Excessive RPM for application. Indicated by broken teeth predominantly on the gauge row teeth. Improper break-in of bit when a major change in bottomhole pattern is made. Formation too hard for bit type.

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BU (Balled Up) - (Fig. A4-5) Figure A4-5 Balled Up, BU

A balled up bit will show tooth wear due to skidding, caused by a cone, or cones, not turning due to formation being packed between the cones. The bit will look as if a bearing had locked up even though the bearings are still good. Some causes of bailing up are: Inadequate hydraulic cleaning of the bottomhole. Forcing the bit into formation cuttings with the pump not running. Drilling a sticky formation.

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CC (Crocked Cone) - (Fig. A4-6) Figure A4-6 Cracked Cone, CC

A crocked cone is the start of a broken or lost cone and has many of the same possible causes. Some of these causes are: Junk on the bottom of the hole. Bit hitting a ledge or bottom. Dropped drill string. Hydrogen sulfide embrittlement. Overheating of the bit. Reduced cone shell thickness due to erosion. Cone interference.

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CD (Cone Dragged) - (Fig. A4-7) Figure A4-7 Cone Dragged, CD

This dull characteristic indicates that one or more of the cones did not turn during part of the bit run, indicated by one or more flat wear spots. Some of the possible causes are: Bearing failure on one or more of the cones. Junk lodging between the cones. Pinched bit causing cone interference. Bit bailing up. Inadequate break in.

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CI (Cone Interference) - (Fig. A4- 8) Figure A4-8 Cone Interference, CI

Cone interference often leads to cone grooving and broken teeth and is sometimes mistaken for formation damage. Broken teeth caused by cone interference are not an indicator of improper bit selection. Some of the causes of cone interference are: Bit being pinched. Reaming under gauge hole with excessive WOB. Bearing failure on one or more cones.

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Chapter A: Bit Classification and Grading

CR (Cored) - (Fig. A4-9) Figure A4-9 Cored Bit, CR

A bit is cored when its centermost cutters are worn and/or broken off. A bit can also be cored when the nose part of one or more cones is broken. Some things that can cause bits to become cored are: Abrasiveness of formation exceeds the wear resistance of the center cutters. Improper breaking in of a new bit when there is a major change in bottomhole pattern. Cone shell erosion resulting in lost cutters. Junk in the hole causing breakage of the center cutters.

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CT (Chipped Teeth) - (Fig. A4-10) Figure A4-10 Chipped Teeth, CT

On tungsten carbide insert bits, chipped insert often become broken teeth. A tooth is considered chipped, as opposed to broken, if a substantial part of the tooth remains above the cone shell. Some causes of chipped teeth are: Impact loading due to rough drilling. Slight cone interference. Rough running in air drilling application.

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Chapter A: Bit Classification and Grading

ER (Erosion) - (Fig. A4-11) Figure A4-11 Cone Erosion, ER

Fluid erosion leads to cutter reduction and/or loss of cone shell material. The loss of cone shell material on tungsten carbide insert bits can lead to a loss of inserts due to the reduced support and grip of the cone shell material. Erosion can be caused by: Abrasive formation contacting the cone shell between the cutters, caused by tracking, off-center wear, or excessive WOB. Abrasive formation cuttings eroding the cone shell due to inadequate hydraulics. Excessive hydraulics resulting in high velocity fluid erosion. Abrasive drilling fluids or poor solids control.

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FC (Flat Crested Wear) - (Fig. A4-12) Figure A4-12 Flat Crested Wear, FC

Flat crested wear is an even reduction in height across the entire face of the cutters. Interpretation of the significance of flat crested wear are numerous, and dependent on many factors, including formation, hardfacing and operating parameters. One of the causes of flat crested wear is: Low WOB and high RPM, often used in attempting to control deviation.

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Chapter A: Bit Classification and Grading

HC (Heat Checking) - (Fig. A4-13) Figure A4-13 Heat Checking, HC

This dulling characteristic happens when a cutter is overheated due to dragging on the formation and is then cooled by the drilling fluid over many cycles. Some situations that can cause heat checking are: Cutters being dragged. Reaming a slightly under gauge hole at high RPM.

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JD (Junk Damage) - (Fig. A4-14) Figure A4-14 Junk Damage, JD

Junk damage can be detected by marks on any part of the bit. Junk damage can lead to broken teeth, damaged shirttail, and shortened bit runs and therefore can become a problem. It is sometimes necessary to clear the junk out of the hole before continuing to drill. Some common sources of junk, and therefore causes of junk damage are: Junk dropped in the hole from the surface (tong dies, tools, etc.). Junk from the drill string (reamer pins, stabilizer blades, etc.). Junk from a previous bit run (tungsten carbide inserts, ball bearings, etc.). Junk from the bit itself (tungsten carbide inserts, etc.).

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Chapter A: Bit Classification and Grading

LC (Lost Cone) - (Fig. A4-15) Figure A4-15 Lost Cone, LC

It is possible to lose one or more cones in many ways. With few exceptions, the lost cone must be cleared from the hole before drilling can resume. Some of the causes of lost cones are: Bit hitting bottom or a ledge on a trip or connection. Dropped drill string. Bearing failure (causing the cone retention system to fail). Hydrogen sulfide embrittlement.

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LN (Lost Nozzle) - (Fig. A4-16) Figure A4-16 Lost Nozzle, LN

While LN is not a curing structure dulling characteristic, it is an important "Other Dulling Characteristic" that can help describe a bit condition. A lost nozzle causes a pressure decrease which requires that the bit be pulled out of the hole. A lost nozzle is also a source of junk in the hole. Some causes of lost nozzles are: Improper nozzle installation. Improper nozzle and/or nozzle design. Mechanical or erosion damage to nozzle and/or nozzle retaining system.

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LT (Lost Teeth) - (Fig. A4-17) Figure A4-17 Lost Teeth, LT

This dulling characteristic leaves entire tungsten carbide inserts in the hole which are far more detrimental to the rest of the bit than are broken inserts. Lost teeth often cause junk damage. Lost teeth are sometimes preceded by rotated inserts. Lost teeth can be caused by: Cone shell erosion. A crack in the cone that loosens the grip on the insert. Hydrogen sulfide embrittlement cracks.

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OC (Off Center Wear) - (Fig. A4-18) Figure A4-18 Off Center Wear, OC

This dulling characteristic occurs when the geometric center of the bit and the geometric center of the hole do not coincide. This results in an oversized hole. Off center wear can be recognized on the dull bit by wear on the cone shells between the rows of cutters, more gauge wear on one cone, and by a less than expected penetration rate. This can often be eliminated by changing bit types and thus changing the bottomhole pattern. Off Center Wear can be caused by: Change of formation from a brittle to a more plastic formation. Inadequate stabilization in a deviated hole. Inadequate WOB for formation and bit type. Hydrostatic pressure that significantly exceeds the formation pressure.

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PB (Pinched Bit) - (Fig. A4-19) Figure A4-19 Pinched Bit, PB

Bits become pinched when they are mechanically forced to a less than original gauge. Pinched bits can lead to broken teeth, chipped teeth, cone interference, dragged cones and many other cutting structure dulling characteristics. Some possible causes of pinched bits are: Bit being forced into under gauge hole. Roller cone bit being forced into a section of hole drilled by fixed cutter bits, due different OD tolerances. Forcing a bit through casing that does not drift to the bit size used. Bit being pinched in the bit breaker. Bit being forced into an undersized blow out preventer stack.

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PN (Plugged Nozzle) - (Fig. A4-20) Figure A4-20 Plugged Nozzle, PN

This dulling characteristic does not describe the cutting structure but can be useful in providing information about a bit run. A plugged nozzle can lead to reduced hydraulics or force a trip out of the hole due to excessive pump pressure. Plugged nozzles can be caused by: Jamming the bit into fill with the pump off. Solid material going up the drill string through the bit on a connection and becoming lodged in a nozzle when circulation is resumed. Solid material pumped down the drill string and becoming lodged in a nozzle.

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RG (Rounded Gage) - (Fig. A4-21) Figure A4-21 Rounded Gauge, RG

This dulling characteristic describes a bit that has experienced gauge wear in a rounded manner, but will still drill a full size hole. The gauge inserts may be less than nominal bit diameter but the cone backfaces are still at nominal diameter. Rounded Gage can be caused by: Drilling an abrasive formation with excessive RPM. Reaming an under gauge hole.

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SD (Shirttail Damage) - (Fig. A4-22) Figure A4-22 Shirttail Damage, SD

Shirttail damage may be different than junk damage and is not a cutting structure dulling characteristic. Shirttail wear can lead to seal failures. Some causes of shirttail damage are: Junk in the hole. Reaming under gauge hole in faulted or broken formations. A pinched bit causing the shirttails to be the outer most part of the bit. Poor hydraulics. High angle well bore.

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SS (Self Sharpening Wear) - (Fig. A4-23) Figure A4-23 Self Sharpening Wear, SS

This is a dulling characteristic which occurs when cutters wear in a manner such that they retain a sharp crest shape.

TR (Tracking) - (Fig. A4-24) Figure A4-24 Tracking Wear, TR

This dulling characteristic occurs when the teeth mesh like a gear into the bottomhole pattern. The cutter wear on a bit that has been tracking will be on the leading and trailing flanks. The cone shell wear will be between the cutters in a row.

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Tracking can sometimes be alleviated by using a softer bit to drill the formation and/or by reducing the hydrostatic pressure if possible. Tracking can be caused by: Formation changes from brittle to plastic. Hydrostatic pressure that significantly exceeds the formation pressure.

WO (Washed Out Bit) - (Fig. A4-25) Figure A4-25 Bit Washout, WO

Bit washouts are not cutting structure dulling characteristics but can provide important information when used as an "Other" dulling characteristic. This can occur at anytime during the bit run. If the bit weld is porous or not closed, then the bit will start to washout as soon as circulation starts. Often the welds are closed but crack during the bit run due to impact with bottom or ledges on connections. When a crack occurs and circulation starts through the crack, the washout is established very quickly.

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WT (Worn Teeth) (Fig. A4-26) Figure A4-26 Worn Teeth, WT

This is a normal dulling characteristic of the tungsten carbide insert bits as well as for the stoft tooth bits. When WT is noted for steel tooth bits, it is also often appropriate to note self sharpening (SS) or flat crested (FC) wear.

NO (No Dull Characteristics) This code is used to indicate that the dull shows no sign of the other dulling characteristics described. This is often used when a bit is pulled after a short run for a reason not related to the bit, such as a drill string washout.

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Chapter B: Drill String

Chapter B Drill String

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Table of Contents - Chapter B Drill String Preface .............................................................................................................................................. B-5 B1. Drill String ........................................................................................................................................ B-6 Introduction ...................................................................................................................................... B-6 I. Weld-on Tool Joints ....................................................................................................................... B-6 B2. Steel Drill Pipe ............................................................................................................................... B-45 B3. Tool Joints Care And Handling ...................................................................................................... B-54 I. Cleaning and Inspection ............................................................................................................... B-54 II. Picking Up the Drill String ......................................................................................................... B-55 III. Thread Compounds .................................................................................................................. B-58 IV. Breaking In New Tool Joints .................................................................................................... B-58 V. Tripping ...................................................................................................................................... B-59 VI. Laying Down Drill String ......................................................................................................... B-67 VII. Damage and Failures -- Cause Prevention .............................................................................. B-69 VIII. Repair of Tool Joints .............................................................................................................. B-87 IX. Emergency Procedures ............................................................................................................. B-93 X. Transportation ............................................................................................................................ B-94 XI. Storage ..................................................................................................................................... B-95 XII. Floor Handling Procedures ..................................................................................................... B-96 B4. Drill String Operating Limits ........................................................................................................ B-104 I. Fatigue and Lateral Forces caused by Dog Legs and Floating Vessels ..................................... B-104 II. Fatigue Caused by Other Factors ............................................................................................. B-115 III. Critical Rotary Speed .............................................................................................................. B-120 IV. Collapsed Pipe -- From Drill Stem Test and BOP Test ........................................................... B-120 V. Transition from Drill String to Drill Collars ............................................................................. B-121 VI. Maximum Allowable Pull and Rotary Torque ........................................................................ B-121 VII. Make up Torque versus Drilling Torque ............................................................................... B-123 IX. Dynamic Loading of Drill Pipe during Tripping ..................................................................... B-125 X. Biaxial Loading of Drill Pipe .................................................................................................... B-125 XI. Drill String Design .................................................................................................................. B-126 XII. References ............................................................................................................................. B-126 B5. Drill String Corrosion................................................................................................................... B-127 I. Introduction ............................................................................................................................... B-127 Il. Corrosion .................................................................................................................................. B-127 III. Sulfide Stress Cracking ........................................................................................................... B-132 IV. Drilling Fluids Containing Oil ................................................................................................. B-135 B6. Drill String Inspection And Classification .................................................................................... B-136 I. Purpose ...................................................................................................................................... B-136 II. Drill String Marking and Identification .................................................................................... B-136 III. Drill Pipe And Tubing Work Strings ....................................................................................... B-136

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IV. Tool Joints ............................................................................................................................... B-144 B7. Aluminum Drill String .................................................................................................................. B-148 Introduction .................................................................................................................................. B-148 II. Installation and Removal of Tool Joints ................................................................................... B-148 III. Aluminum Drill Pipe ............................................................................................................... B-148 IV. Drill String Care and Handling ................................................................................................ B-150 V. Drill String Maintenance........................................................................................................... B-151 VI. Drill String Operating Limits .................................................................................................. B-151 B-8 Glossary Of Drill String Terms .................................................................................................... B-154

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Chapter B: Drill String

Chapter B Drill String The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study. The following industry representatives have contributed to the development and updating of this chapter: TUBULAR GOODS TASK GROUP MEMBERS: John Altermann

Reading & Bales Drilling Company

Bruce Dawson

National Oilwell

Jerrell Hinton

Broughton Offshore Drilling, Inc.

Weldon Rogers Tom Smith

Tuboscope Vetco Smith Consulting Services

Preface This Chapter of the Drilling Manual, formerly the Tool Pushers' Manual, is concerned with the specifications, operating data, care and handling, and trouble-shooting of the drill string. By definition, the drill string is the drill pipe with the tool joints attached. The drill stem consists of the drill string and all other attached members, including kelly, subs, drill collars, heavy weight, drill pipe, stabilizers, shock absorbers, reamers, and any other in-hole equipment used generally or part-time during drilling operations. The drill string is one of the most expensive integral pieces of rotary drilling equipment. Its life span will determine whether it can be expensed or depreciated. Therefore, proper design, care and handling with the consequent life extension is an important economic factor. With the idea of economics in mind, a committee was appointed to prepare a manual on the care and handling of the drill string. The original committee, chaired by Russell Lewis and consisting of Howard Lorenz of Oilfield Machine Supply Company; Moak Rollins, Drilco Oil Tools; John Willis, Hughes Tool Company; and Roy McGrann of U.S. Steel, prepared the original draft. There have been many contributors to Chapter B over the years, too many to mention in the space available. The present revision to the section has been the responsibility of Bruce Dawson, National-Oilwell; Weldon Rogers, AMF Tuboscope; Tom Smith, Smith Consulting Services; John Altermann, Reading & Bates; Jerell S. Hinton, Broughton Offshore Drilling, Inc. Acknowledgement is also made to the men other than those mentioned above who have worked diligently with IADC subcommittees and the API task groups who are responsible for the specifications and recommended use of the drill string.

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B1. Drill String API Specifications In the world wide oil industry today, an overwhelming majority of all tubular goods is manufactured to specifications developed and approved by the American Petroleum Institute. These specifications cover the mechanical properties of the steel, the details of manufacture and physical dimensions of the pipe. The latter include internal and external diameters, wall thickness and upset dimensions for each nominal size, weight and grade, as well as tool joint type, OD and ID, and length. API Specification 5D covers drill pipe. Bulletins 5A2, 5C2 and 5C3 cover aspects of the use of and care of drill pipe. In the early days of rotary drilling, it was quite difficult to be certain that drill string members would match in weight and wall thickness or that joints would mate with similar products manufactured by different companies. To mitigate the resulting confusion and loss of time, the API was induced to undertake a program of standardization and marking. This program is a continuing one which enables changes occurring based upon improved technology and the needs of users and manufacturers to be disseminated to the industry in a minimum amount of time and with a high degree of accuracy. API Specifications and Recommended Practices cover a wide range of oilfield equipment in addition to tubular goods. These publications are revised as necessary and constitute one the best sources of information on the design, manufacture, care and use of drilling and production equipment. This section of the Drilling Manual relates not only to the API 5 specifications but also to API Specification 7, Recommended Practice RP7G, and RP7A1. These publications relate to the connections for the drill string and also to the design and operating limits of the drill stem. This section of the Drilling Manual discusses drill string care and use and gives examples of the types of problems usually encountered when the drill string is improperly used or used beyond its physical capabilities. This section also recommends practices which will overcome or eliminate the problems often encountered when using the drill stem.

Introduction A number of tables herein are duplicates of (or derived from) the API Specification 7 and Recommended Practice RP7G. Always refer to the current API RPs.

I. Weld-on Tool Joints The flash-welded tool joint was the first weld-on type tool joint introduced to the industry in 1938. Inertia welding was offered in 1974, and continuous drive friction welding in 1978, Figure B1-1, illustrates a weld-on tool joint.

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Figure B1-1 Weld-on Tool Joint

Both inertia and continuous drive friction welders utilize frictional heat for achieving welding temperatures, however, the inertia welder uses a flywheel and momentum principle whereas the continuous drive friction welder maintains a constant rpm motor and brake system.

A. Tool Joint Selection Tool joint selection for all weights and grades of drill pipe should be discussed with the manufacturer if unusual operating conditions are anticipated. Tool joints for standard weights and grades have been established by API. However, many other tool joints are being manufactured and are in use and most are included in API RP7G. These tables were utilized in the preparation of Tables B1-1 through B1-4, titled Selection Chart.

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Table B1-1 Tool Joints on Standard Weight Drill Pipe - Grade 75

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Table B1-2 Tool Joints on Light Weight Drill Pipe - Grade 75

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Notes on Table B1-2 1. Tool Joint Plus 29.4' of Drill Pipe. 2. Tensile Yield Strength of Drill Pipe Based on 75,000 psi. 3. Tensile Yield Strength of the Tool Joint Pin is based on 120,000 psi Yield and the Cross Sectional Area at the Root of the Thread 5/8 inch from the Shoulder. 4. Torsional Yield Strength of the Drill Pipe is Based on a Shear Strength of 57.7% of the Minimum Yield Strength. 5. Torsional Yield Strength of the Tool Joint Based on Tensile Yield Strength of the Pin and Compressive Yield Strength of the Box - Lower Value Prevailing.

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Table B1-3 Tool Joints on Heavy Weight Drill Pipe - Grade 75

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Notes on Table B1-3 1. Tool Joint Plus 29.4' of Drill Pipe. 2. Tensile Yield Strength of Drill Pipe Based on 75,000 psi. 3. Tensile Yield Strength of the Tool Joint Pin is based on 120,000 psi Yield and the Cross Sectional Area at the Root of the Thread 5/8 inch from the Shoulder. 4. Torsional Yield Strength of the Drill Pipe is Based on a Shear Strength of 57.7% of the Minimum Yield Strength. 5. Torsional Yield Strength of the Tool Joint Based on Tensile Yield Strength of the Pin and Compressive Yield Strength of the Box - Lower Value Prevailing.

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Table B1-4 Tool Joints on High Strength Drill Pipe

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Notes on Table B1-4 1. Tool Joint Plus 29.4' of Drill Pipe. 2. Tensile Yield Strength of Drill Pipe Based on Minimum Yield Strength for that Grade. 3. Tensile Yield Strength of the Tool Joint Pin is based on 120,000 psi Yield and the Cross Sectional Area at the Root of the Thread 5/8 inch from the Shoulder. 4. Torsional Yield Strength of the Drill Pipe is Based on a Shear Strength of 57.7% of the Minimum Yield Strength. 5. Torsional Yield Strength of the Tool Joint Based on Tensile Yield Strength of the Pin and Compressive Yield Strength of the Box - Lower Value Prevailing. NOTE: The tool joint OD and ID dimensions have been selected so that the torsional ratio between too[ joint and tube is 80% or more. Other OD and ID tool joints may be satisfactory when design is based on tensile rather than torsional strength requirements. Additional detailed dimensional data for joints is shown in Table B1-5 and Table B1-6.

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Table B1-5 Dimensional Data for Rotary Shouldered Connections

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Notes on Table B1-5 *The bevel diameters on drill stem members may vary. The length of perfect threads in box shall not be less than maximum pin length (LpC), plus 1/8". Note: See Figure B1-5 for nomenclature.

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Table B1-6 Thread Form Dimensions

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Notes on Table B1-6 H - Thread Height, Not Truncated hn-h, - Thread Height, Truncated sm-srs, fm-frn - Root Truncation fon - fcb - Crest Truncation Fcn - Fcb - Width of Flat, Crest Fm - Frs - Width of Flat, Root rm - rrs - Root Radius r - Radius at Thread Corners This is primarily for the use of crews in inspecting pipe and field shops repairing joints. For design purposes, reference is also made to Table B 1-7, showing comparative allowable torque and dimensional data for drill pipe and tool joints.

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Table B1-7 Minimum OD and Make-up Torque of Weld-on Tool Joints

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Notes on Table B1-7 1) The use of outside diameters (OD) smaller than those listed in the table may be acceptable on slim hole (SH) tool joints due to special service requirements. 2) Tool joint with dimensions shown has a lower torsional yield ratio than the 0.80 which is generally used. 3) Recommended make-up torque is based on 72,000 psi stress. 4) In calculation of torsional strengths of tool joints, both new and worn, the bevels of the tool joint shoulders are disregarded. This thickness measurement should be made in the plane of the face from the I.D. of the counter bore to outside diameter of the box, disregarding the bevels. * Tool joint diameters specified are required to retain torsional strength in the tool joint comparable to the torsional strength of the attached drill pipe. These should be adequate for all service. Tool joints with torsional strengths considerably below that of the drill pipe may be adequate for much drilling service. Figure B1-2 and Figure B1-5 depict the interchangeability of the older API rotary shouldered connection style and the current series referred to as the number style or numbered connection, NC.

Figure B1-2 Tool Joint Interchangeability Chart

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Figure B1-5 Tool Joint Interchangeability Chart

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The NC connection is designated by a two-digit number indicating the pitch diameter of the pin member at the gage point. The NC connections employ a "V" thread form having a .065 inch flat crest and .038 inch rounded root. This is designated as the V-0.038R form and mates with the V-0.065 thread form.

B. Torsional Strength of Tool Joints The torsional strength of a tool joint is a function of several variables. These include the strength of the steel, connection size, thread form, lead, taper, and coefficient of friction on the mating surfaces of threads and shoulders. The torque required to yield a rotary shouldered connection may be obtained from the equation in Appendix A, API RP7G. The pin or box area, whichever controls, is the largest factor and is subject to the widest variation. The tool joint outside diameter (OD) and inside diameter (ID) largely determine the strength of the joint in torsion. The OD affects the box area and the ID affects the pin area. Choice of OD and ID determines the areas of the pin and box and establishes the theoretical torsional strength, assuming all other factors are constant. The greatest reduction in theoretical torsional strength of a tool joint during its service life occurs with OD wear. At whatever point the tool joint box area becomes the smaller or controlling area, any further reduction in OD causes a direct reduction in torsional strength. If the box area controls when the tool joint is new, initial OD wear reduces torsional strength. If the pin controls when new, some OD wear may occur before the torsional strength is affected. Conversely, it is possible to increase torsional strength by making joint with oversize OD and reduced ID. The curves in Figures B1-6 through B1-30 depict the theoretical torsional yield strength of a number of commonly used tool joint connections over a wide range of inside and outside tool joint diameters.

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Figure B1-6

Figure B1-7

Figure B1-8

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Figure B1-9

Figure B1-10

Figure B1-11

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Figure B1-12

Figure B1-13

Figure B1-14

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Figure B1-15

Figure B1-16

Figure B1-17

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Figure B1-18

Figure B1-19

Figure B1-20

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Figure B1-21

Figure B1-22

Figure B1-23

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Figure B1-24

Figure B1-25

Figure B1-26

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Figure B1-27

Figure B1-28

Figure B1-29

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Figure B1-30

The theoretical torsional yield strength for the purpose of these curves is the theoretical torque which will cause additional make-up of a tool joint each time the torque is used to make up pin and box. The coefficient of friction between mating surfaces, threads, or shoulders, is assumed to be 0.08, and minimum tensile yield is 120,000 psi. The curves may be used by taking the following steps: a. Select the curve for the size and type tool joint connection being studied. b. Extend a horizontal line from the OD under consideration to the curve and read the torsional strength representing the box. c. Extend a vertical line from the ID to the curve and read the torsional strength representing the pin. d. The smaller of the two torsional strengths thus obtained, is the theoretical torsional strength of the tool joint. e. It is emphasized that the values obtained from the curves are theoretical values of torsional strength. Tool joints in the field, subject to many factors not included in determination of points for the curves, may vary considerably from these values. f. The curves are most useful to show the relative torsional strengths of joints for variations in OD and ID, both new and after wear. In each case, the smaller values should be used. The recommended make-up torque for a used tool joint is determined by taking the following steps: a. Select the appropriately titled curve for the size and type of tool joint connection being studied. b. Extend a horizontal line from the OD under consideration to the curve and read the recommended make-up torque representing the box. c. Extend a vertical line from the ID under consideration to the curve and read the recommended make-up torque representing the pin. d. The smaller of the two recommended make-up torques thus obtained is the recommended make-up torque for the tool joint. e. A make-up torque higher than recommended may be required under extreme conditions.

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C. Elevator Shoulder Design Tool joint box elevator shoulders are manufactured in both the square and 18 degree taper. Most weld-on type tool joints are furnished with tapered shoulders. Tool joint pins are generally furnished with 35 degree tapered shoulders but can be made available with an 18 degree tapered shoulder. Elevators are available to work with either 18 degree tapered or squared shouldered joints. Those for use with the 18 degree tapered shoulders are generally heavier due to the higher radial loading that results from the wedging action. API Spec 8C specifies elevator bores to correspond to dimensions of the box elevator upset. On some tool joint assemblies, such as Slim Hole, lifting plugs are used to provide the elevator shoulder necessary to handle the drill string.

D. Marking of Tool Joints It is recommended that weld-on tool joints be stencilled on the base of the pin with the information shown in Figure B1-3.

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Figure B1-3a Tool Joint Markings for Component Identification Also see Figure B1-3f below

Figure B1-3b Pipe Mills & Pipe Processors Past & Present (1992)

Notes for Figure B1-3b

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Note: Pipe mills may upset and heat treat their own drill pipe or they may have this done according to their own specifications. The mill's assigned symbol should be used on each drill string assembly. Pipe processors may buy "green" tubes and upset and heat treat these according to their own specifications. In this case, the processor's assigned symbol should be used on each drill string assembly. Note: These codes are provided for pipe manufacturer* identification and have been assigned at pipe manufacturer's requests. Manufacturers included in this list may not be current API licensed pipe manufacturers. A list of manufacturers licensed to use of the API monogram can be obtained by calling API headquarters. * See API Spec 5D. The "manufacturer" may be either a pipe mill or processor.

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Figure B1-3c Identification of Standard Weight High Strength Drill Pipe

Figure B1-3d Identification of Heavy Weight Grade E-75 Drill Pipe

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Figure B1-3e Identification of Heavy Weight High Strength Drill Pipe

Notes for Figure B1-3e

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Note A: Standard weight Grade E-75 drill pipe designated by an asterisk (*) in the drill pipe weight code will have no groove or milled slot for identification. Grade E-75 heavy weight drill pipe will have a milled slot only, in the center of the tong space. Note B: Groove radius approximately 3/8 inch. Groove and milled slot to be 1/4 inch deep on 5-1/4 in. OD and larger tool joints, 3/16 in. deep on 5 in. OD and smaller tool joints. Note C: Stencil the grade code symbol and weight code number corresponding to grade and weight of pipe in milled slot of pin. Stencil with 1/4 in. high characters so marking may be read with drill pipe hanging in elevators. LPB = Pin Tong Space Length (See Table 4.2, API Spec 7)

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Figure B1-3f Identification of Tool Joint Manufacturers Registered Trademarks

Notes on Figure B1-3f * These are nearly always registered trademarks and may be used only with permission of the owner. Note: From API RP7G, 14th Edition, Table 2.14 Also, it is further recommended that drill pipe weight and grade identification as shown in Figure B1-4 be used.

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Figure B1-4 Rec. Prac. for Mill Slot and Groove Drill Pipe Identification

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E. Drill Pipe Upsets for Weld-on Tool Joints Upsets are necessary on drill pipe to which weld-on type tool joints are applied. This allows adequate safety factor in the weld area for mechanical strength and metallurgical considerations. The tool joint is made with a welding neck or tang to facilitate welding API upsets for various sizes, grades, and weights of drill pipe listed in API Specification 5D.

F. High Strength Drill Pipe Because of deeper drilling and higher stress levels, grades of drill pipe stronger than Grade E-75 have been developed. Grades and minimum tensile yield strengths are: Drill Pipe Grade X- 95

Minimum Tensile Yield Strength, psi 95,000

G-105

105,000

S-135

135,000

V-150*

150,000

*V-150 is not a standard API grade. It is listed as the next higher grade above S-135. High strength drill pipe requires heavier and longer upsets than those used on Grade E-75. Tool joints on high strength drill pipe are designed to fit the same elevators as those used for the Grade E-75 assemblies.

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B2. Steel Drill Pipe I. General Information Drill pipe is used to transmit power by rotary motion from ground level to a drilling bit at the bottom of the hole and to convey flushing media to the cutting face of the tool. Thus it plays a vital pan in the successful drilling of oil and gas wells. With the exception of specialty tools, it is probable that no other part of the drill stem is subjected to the complex stresses which drill pipe must withstand. For this reason, the combined skill of steel industry engineers, with full cooperation by oil companies and drilling contractors and in conjunction with the API and IADC, has been used in the development of this vital tool. The same skill was utilized in formulating suggested practices in the care and handling of pipe on the surface, while making trips in the hole and while drilling. By utilizing this compiled information, contractors and operators alike may take full advantage of these developments and realize optimum economies by extended life of the pipe. An important consideration is that drill pipe is an important and expensive part of the total rig with relatively short life. The cost of the pipe places it in the category of a capital investment and not strictly expendable. A recommended practice, followed by many contractors, is to identify each joint upon purchase. In turn a recording should be made, along with its length, when it is placed in the string. By this means, and with some effort in the field and through office accounting, the following is made possible: 1. Useful life of the joint may be determined. 2. Type of service and/or stresses to which it is subjected may be recorded. 3. Switching within the string to obtain optimum use. 4. Determine causes of failures with greater accuracy. 5. Prevent or minimize downhole failures. Too little of this type of feed back information is available. The more of this kind of data which is accumulated, the more assistance industry experts could be to the users. Results would be more economical operation for the contractor and cheaper holes for the operator.

II. Grades of and Lengths of Steel Drill Pipe Drill pipe is furnished in the following API length ranges: Range 1 ...............................18 ft to 22 ft Range 2 ...............................27 ft to 30 ft Range 3 ...............................38 ft to 45 ft Seamless drill pipe is offered in the grades listed below under "Mechanical Properties - API Steel Drill Pipe".

III. Physical Data For Steel Drill Pipe Most of the tables in this manual and in API Specifications and Recommended Practices are based on minimum yield strength values for each grade of drill pipe. In combination with the dimensional data given in Table B6-2 of Section B6, the minimum yield strength values are used to develop tables for new through Class 2 used pipe. These include Tables B1-1 through B1-5, B1-7, B2-1 through B2-4.

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Table B2-1 New DP - Torsion, Tension, Collapse, Internal Pressure

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Notes for Table B2-1 * Based on the shear strength equal to 57.7% of minimum yield strength and nominal wall thickness. NOTE: Calculations are based on formulas in Appendix A, API RP7G and API Bul. 5C3. Table is based on API RPTG, Tables 2.2 and 2.3.

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Table B2-2 Used DP - Torsion, Tension, Collapse, Internal Pressure

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Notes for Table B2-2 * Based on the shear strength equal to 57.7%, of minimum yield strength. ** Torsional and Tensile data based on 20% uniform wear on outside diameter. *** Collapse and internal pressure data based on minimum wall of 80% of nominal (new) and uniform O0 wear. NOTE: Calculations for Premium Class drill pipe are based on formulas in Appendix A, API RP7G and API Bul 5C3. Table is based on API RP7G, tables 2.4 and 2.5.

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Table B2-3 Class 2 DP - Torsion, Tension, Collapse, Internal Pressure

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Notes for Table B2-3 * Based on the shear strength equal to 57.7% of minimum yield strength. ** Torsional and Tensile data based on 30% uniform wear on outside diameter. *** Collapse and Internal pressure data based on minimum wall of 70% nominal (new) wall and uniform O0 wear. NOTE: Calculations for Class 2 drill pipe are based on formulas in Appendix A, APl RP7G and APl Bul 5C3. Table is based on API RP7G, tables 2.6 and 2.7.

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Table B2-4 New DP - Dimensional Data

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Notes for Table B2-4 * lb/ft = 3.3996 x A (col. 6) ** A = 0.7854 x (D2 - d2) *** Z = 0.19635 x 1/D x (Da - crs) NOTE: Table is based on API RPTG, Table 2.1

IV. Marking Drill pipe identification is marked at the base of the pin by the tool joint manufacturer after the pin is affixed. The marking will be in accordance with Figure B1-3. Also it is recommended that drill pipe other than standard weight Grade E-75, be marked according to Figure B1-4. This is to give the crew rapid identification of high strength drill pipe on the racks and on the floor during trips when it is in a combination string with Grade E-75. With little trouble, if necessary cleaning out the milled slot, the specific grade and weight can be determined from the stenciled figures.

MECHANICAL PROPERTIES API STEEL DRILL PIPE Grade

E-75

X-95

G-105

S-135

Yield Strength (minimum psi)

75,000

95,000

105,000

135,000

105,000 125,000

135,000

165,000

Yield Strength (maximum psi)

Tensile Strength (minimum psi) 100,000 105,000

115,000

145,000

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B3. Tool Joints Care And Handling I. Cleaning and Inspection A. Cleaning Pin and box thread and shoulders should be thoroughly cleaned in preparation to adding them to the string. Cleaning pays off in three ways. First, it removes foreign material and permits proper makeup, thereby reducing danger of galling and wobbles. Second, it permits better inspection. Third, it increases life of connections by elimination of abrasive materials. Connections should be thoroughly dried after cleaning so that the thread compound will properly adhere to the surface.

B. Inspection After cleaning, inspect thread and shoulders carefully. Damaged connections should never be run in the hole. Even slight damage will likely cause wobbling or leaking. Slight damage may be repaired at the rig with a shoulder dressing tool or file. Test each box and pin shoulder with a shoulder dressing tool test ring. Use the benchmark to make sure that no tool joint shoulder has been dressed beyond recommended limits. Check the plastic coating in the pin bore under the last engaged thread as a first check on pin stretch. (Figure B3-1),

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Figure B3-1 Plastic Coating in Pin an Indicator of Pin Stretch

Figure B3-1. Plastic coating in the pin bore acts as a stress coat and serves as an early indicator of pin stretch. After inspection, protect all boxes and pins with thread protectors which are clean and dry.

II. Picking Up the Drill String Thread protectors will prevent most of the tool joint damage which occurs in moving and racking. Threads and shoulders of both boxes and pins should be protected from damage when drill string is picked up or laid down. Do not permit threads or shoulders to strike steel on walk or ramp. Wood splinters from the walk can be packed so tightly into the threads that they are very difficult to remove. A clean thread protector made up hand tight should be used in this operation, Figure B3-2, Figure B3-3, Figure B3-4.

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Figure B3-2 Use of Thread Protectors Prevent TJ Damage

Figure B3-2. Thread protectors will prevent most tool joint damage occurring in moving and racking.

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Figure B3-3 TJ Damage - Blow to the Bevel Area

Figure B3-3. A blow on the bevel can create high spots on the shoulder. If not removed, these could cause galling, a washout, or a broken pin and a fishing job.

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Figure B3-4 Mashed Pins

Figure B3-4. Pin threads mashed due to lack of protectors must be repaired or serious trouble will result.

III. Thread Compounds Rotary shouldered connections are subjected to high unit stresses in normal service. Galling and seizing may occur if the separating grim is insufficient to prevent metal to metal contact. This separating film is normally a soft metallic fiber in a grease base carrier. A good thread compound, properly applied, should prevent or minimize galling in all but the most severe service and it should also help to minimize make-up while drilling. The present API RP7A1 gives a method by which the friction factor may be compared between any thread compound and a reference compound. RP7A1 does not yet offer a way to compare resistance to additional makeup or resistance to galling. Thread compounds should not be thinned for ease of application. Dilution will reduce the percentage of the metallic constituent which may make the compound inadequate to prevent galling. For best results, thread compound should be applied to threads and shoulders which are clean and dry. The presence of many cleaning fluids can dilute the compound and keep it from adhering properly to the surfaces it is to protect.

IV. Breaking In New Tool Joints The specific recommendations concerning cleaning, inspection, make-up, handling, etc., are extremely important throughout the life of tool joints. In addition, there are extremely important factors to consider during the break-in period of new joints. The newly machined surfaces are more apt to gall than those which have had some use. After some service, the surfaces undergo certain changes which offer more resistance to galling. Therefore, the initial makeup and first few trips are the most critical time and extra care is essential to give longer trouble-free service. The following steps should be specifically observed on new joints:

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1. Verify recommended makeup torque. Check condition and/or accuracy of all makeup equipment and gauges. Include saver sub condition in this check. 2. Observe all threads and shoulders for handling damage; repair as necessary. 3. Coat all threads and shoulders liberally with thread compound containing 50% by weight finely powdered metallic zinc and not more than 0.3% sulfur. 4. On initial makeup, and for several trips thereafter, stab carefully, makeup slowly, and tong to full makeup using both sets of tongs. 5. Watch for excess resistance during makeup and breakout. Galling, cross threading, and crest to crest makeup can cause excess resistance during makeup. Galling or downhole makeup can cause high breakout torques. Breakout torques over 90% of makeup are warning flags. 6. Alternate breaks on every trip and continue to stab carefully, makeup slowly, and tong to full makeup using both sets of tongs. 7. Avoid high torque situations with new tool joints until they have received a good breaking in.

V. Tripping A. Coming out of the hole 1. Lowering the Elevators Box shoulder may be badly damaged it struck by elevators or hook, Figure B3-5. Figure B3-5 Damage to Box from being Struck by Elevators

Figure B3-5. Box shoulder will be damaged when struck by elevators, take care that this does not happen during trips. Severe damage can be properly repaired only by reworking the box in the machine shop. 2. Breaking Out.

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When breaking the connection, use both breakout and backup tongs. After breaking the connections, rotate out slowly. Keep just enough tension on the hook spring to keep minimum pressure on the disengaging threads; but keep enough tension to avoid the end of the pin striking the box shoulder, Figure B3-6. Figure B3-6 Damage to Box from being Struck by Pin

Figure B3-6. Indentation by pin end bumping shoulder face may destroy deal resulting in leaking and washout. When spring hook lifts pin from box, joint must be pushed to the side to prevent the pin from striking the shoulder when it drops back down. Breakout torque should be 80 to 90 percent of makeup torque. High breakout torque is a warning. Look for galling and/or thread damage. If these are not found, down hole makeup may have occurred. Consider increasing makeup torque. 3. Alternating Breaks Come out of hole on a different break each trip so that every connection can be periodically broken and its condition observed and torque rechecked. This may prevent wobbles and leakage failures. Also excessive breakout torque may indicate abnormal downhole torque conditions. Check should be made for damage due to excessive torque. 4. Standing Back When standing the pipe back, be sure set back area is clean. If desired position of stand is not achieved, do not use wrench jaw or other sharp edged tool to jack into position. This will cause shoulder damage and lead to an epidemic of shoulder leakage and washouts. Special handling tools, Figure B3-7, are available to minimize such trouble.

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Figure B3-7 Recommended Pipe Jack

Figure B3-7. Using the recommended type of pipe jack will reduce damage to pin shoulders on trips.

B. Going in the Hole 1. Lubrication Practice

Before each joint is added to the string, it should be cleaned and dried. This includes complete removal of rust preventatives or previously applied tool joint compound. When the joint is picked up and on each trip, the box threads and shoulder should be doped, distributing the compound over threads and mating surfaces, preferably with a round, stiff bristle brush, Figure B3-8. Keep compound and brush clean and free from dirt.

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Figure B3-8 Lubrication of Box Threads

Figure B3-8. Lubricate threads and shoulders every trip. A round, stiff brush gives the best results. Figure B3-9 Galling by Lack of Lubrication - Box

Figure B3-9. Insufficient lubrication can cause galling or high spot on shoulder. This results in wobble which in turn causes fatigue breakage of threads.

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Figure B3-10 Galling by Lack of Lubrication - Pin

Figure B3-10. Pure thread galling results from lack of lubricating film. This allows steel surfaces to freeze together. 2. Stabbing Do not allow the ends of the pins to strike the box shoulders. Such damage may be avoided by achieving coordination between drillers and floormen, Figure B3-11.

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Figure B3-11 Damage to TJ by Bumping of Box by End of Pin

Figure B3-11. Bumping of box shoulder by end of pin while stabbing is a common cause of damage. 3. Spinning Up Before spinning up pipe, be sure connections are in alignment. Don't rotate pipe too fast; if joint wobbles and binds, high speeds can burn threads. The use of kelly spinners during high speed drilling operations has become quite common on broken-in tool joints. This is particularly true in high daily cost offshore operations. Kelly spinners rotate the kelly at high rates into the mousehole joint and then the mousehole joint going into the joint in the rotary table. Extra care is necessary that the connection is clean, adequately lubricated and the joint does not wobble and bind. After both spinning operations, the rotary tongs should be used to tighten the joints to the recommended torque. Failure to follow the procedures may increase the likelihood of damage. 4. Makeup and Tonging When making up the connection, use both makeup and back-up tongs. Avoid forced makeup of improperly engaged threads. In stabbing, flat thread crests on the pin can land opposite similar crests on the box. This results in jamming action and forced makeup will cause serious damage. A slight amount of left hand rotation with tongs will free them. The stand can be lifted, rotated slightly and stabbed again, Figure B3-12.

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Figure B3-12 Forced Makeup can cause Thread Galling

Figure B3-12. While stabbing, flat thread crests on pin may land opposite similar crests on box. Forced makeup causes thread galling.

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Figure B3-13 Shoulders Damaged when Tongs Engage Shoulder

Figure B3-13. Shoulders may be damaged when tongs are allowed to engage the shoulder.

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Figure B3-14 Correct Bucking Up on TJ is Critical to its Life

Figure B3-14. Bucking up is one of the most critical of all rigs activities in the life of a tool joint. Tonging tool joints properly is the most important single factor in prevention of tool joint troubles. Torque measuring equipment should always be used to prevent under torque or over torque of tool joints. Slicker than normal thread compounds can contribute to torsional problems. 5. Running In Refer to Section B3-XII, "FLOOR HANDLING PROCEDURES."

VI. Laying Down Drill String When laying down the drill string, specific operations should include: a. Wash tool joints and drill string internally and externally with clear fresh water. This will remove any salt or other corrosive agent which might bring about more rapid deterioration. b. Apply a rust preventive compound to the threads and shoulders, particularly if drill string is to be stored for any length of time. c. Install thread protectors before swinging through "V" door and onto walk. Keep walk clear -- do not allow joint coming down to hit another joint or other objects on the walk. Be sure thread protectors are installed tightly on boxes and pins, Figure B3-15 and Figure B3-16.

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Figure B3-15 Install Thread Protectors before Laying Joint Down

Figure B3-15. Install thread protectors before laying down a joint.

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Figure B3-16 Keep Catwalk Clear when Laying Pipe Down

Figure B3-16. When laying pipe down, keep walk clear. Do not allow joint coming down to hit another joint or objects on the walk. d. Check drill string for straightness and straighten if needed. When racking, use wood spacers between layers. Three spacers are desirable -- one in the center and one close to either end and behind the tool joints. Spacers should be thick enough to keep tool joints separated when rolling drill string.

VII. Damage and Failures -- Cause Prevention A. Visual Examination for Damage While Tripping 1. Look for dry or muddy threads, Figure B3-17, check for washing and galling, check for worn threads.

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Figure B3-17 Watch for Dry Connections when Tripping

Figure B3-17. Watch for dry connections when making trips as they are positive indications that something is wrong. Correct any damage and return to service. Be sure to check that proper makeup torque and procedures are being used. Measure breakout torque periodically. 2. Look for galling on threads and shoulders, Figure B3-18.

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Figure B3-18 Galled Shoulder Prevents Sealing

Figure B3-18. Gall on shoulder prevents shoulder from sealing, causing washing of shoulder and threads. When galling is encountered, check for proper thread compound, proper torque, and adequate shoulder areas. 3. Look for wear on tool joints and drill pipe. If eccentric tool joint wear is noticed, check pipe for straightness. 4. Watch for undercutting of the tool joint in the area of the 18 degree elevator shoulder. Undercutting may be more prevalent on tool joints with hard metal bands, but may also occur on tool joints without hard metal bands. Check pipe for straightness. Check operations for critical rotating speed. 5. Watch tool joints while tripping for evidence of pin stretch and box swelling due to over-torquing. Over-torquing frequently occurs downhole while drilling. 6. Watch for washouts in drill pipe in the connection area of the joint, in the slip area and in the transition between the upset and the pipe nominal wall. 7. Watch for mashes, dents, slip cuts and other similar damage. These areas are potential points for failures to originate and should be thoroughly investigated and checked out before running in the hole.

B. Failures 1. Fatigue -- Most fatigue failures in a tool joint occur in the last engaged thread of the pin. This is the area approximately 1" from the pin shoulder. The most common cause of fatigue failures is insufficient makeup torque to stabilize the box and pin shoulders and threads, therefore, permitting stress reversals that exceed the endurance limit of the material and result in failures, Figure B3-19.

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Figure B3-19 Weak Connections if Makeup is Insufficient

Figure B3-19. Connection will not develop maximum strength and will lack shoulder support with insufficient makeup torque. This can cause fatigue failure in the pin. Mechanical damage and/or galling can also allow conditions of instability causing a fatigue crack to occur. When fatigue cracks occur or are suspected, a magnetic particle inspection of the pin thread areas should be made. Some of the indications that a pin could have been subjected to fatigue are: 1. Galled face and shoulders. 2. Worn and lapped threads. 3. Galled threads. 4. Dry or muddy pins. 5. Washed, mud cut faces and shoulders. 2. Torsional -- Torsional failure and torsional damage to joints are both obvious and obscure, catastrophic and passive. 2a. The most common cause of torsional failure is down hole torque. Apparently the worst condition exists when the bottom portion of the drill stem stops rotation or hangs up and the upper portion, the drill string, keeps turning due to momentum or rotational forces from the rotary table or top drive.

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One of the most common types of torsional failures is tensile failure of the pin. The fracture surface appearance is usually the classical cup/cone type failure as illustrated in Figure B3-20. Figure B3-20 Cup-Type Fracture from Excessive Torque (Tension)

Figure B3-20. Tension due to excessive torque is normally a cup-type fracture. The concave portion of the fracture surface will be on the pin dutchman that remains in the box. The convex portion of the fracture surface will be on the pin body. This type of failure occurs instantaneously when the connection makes up suddenly downhole and the rotation of the pin into the box produces tensile stresses in the last engaged thread area above the strength of the material. The torque required to produce this type of failure is much higher than the recommended makeup of torque. This type of failure is common in new drill strings. To reduce the incidence of this type of failure: 1. Use the recommended makeup for tool joint. 2. Use the recommended tool joint thread compound. 2b. Another form of torsional failure is illustrated in Figure B3-21.

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Figure B3-21 Excessive Torque can cause Pin Failure

Figure B3-21. Fishing jobs can occur when excessive torque causes pin to be screwed into box until it fails in tension. The mechanism of failure is the same as presented in 2a, but instead of the pure cup/cone fracture surface this type of failure has a combination of cup/cone and shear. The angle of the shear surface from the cup/cone area to the end of the pin is approximately 45 degree This type of failure is also common on new drill strings. 2c. Other obvious forms of torsional failures: On worn tool joints, boxes may bell or split. Sometimes the belling may be detected by placing a straight edge on the box and looking for belling. Sometimes the box OD near the makeup shoulder may be a bright shiny color caused by a belled box rubbing in the hole while rotating.

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Figures B3-22 and B3-25 show examples of split boxes. Figure B3-22 Excessive Torque can cause Swelled/Split Box

Figure B3-22. Excessive torque may result in swelled and split tool joint box. Figure B3-25 Excessive Down-Hole Torque can cause Swollen TJs

Figure B3-25. Extreme damage caused by excessive torque developed during drilling includes: belled out and split box and sheared shoulder of the pin.

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Figures B3-23 and B3-24 show examples of belled boxes. Figure B3-23 Excessive Down-Hole Torque can cause Swollen TJs

Figure B3-23. A tool joint belled out by excessive torque also has internal distortion. Figure B3-24 Excessive Torque can cause Swollen Tool Joints

Figure B3-24. Down hole excessive torque may result in a belled-out box and overly made-up pin. Another problem occurs with tool joints due to torsion. This commonly referred to as "stretched pins". Stretched pins may occur along with other types of torsional failures or they may be the only evidence of over torquing. The stretch is produced by the same mechanism as 2a and 2b, but the torque is not high enough to produce failure or the torque is removed before failure occurs, such as the failure of another tool joint in the string. This type of torsional damage is difficult to detect but dangerous because cracks may be present that will progress to failure if not

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detected and removed or cracks may develop from the stretched area. Stretch may be present in varying degrees and may be detected and measured in several ways. The most accurate method of detecting and measuring pin stretch is with a dial indicator lead gage as shown in Figure B3-26. Figure B3-26 Use of Lead Gauge to Determine TJ Pin Stretch

Figure B3-26. Lead gage will most accurately determine thread stretch on tool joint pins. It is recommended that any pin that has over .006" stretch in 2" be remachined. Stretch may be detected with a thread profile gage as shown in Figure B3-27 and Figure B3-28.

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Figure B3-27 Thread Profile Gauge Determines Stretching of Threads

Figure B3-27. Thread profile gage indicates necking down and stretching of thread lead due to excessive torque. Figure B3-28 Thread Distortion Indicates Excessive Torque

Figure B3-28. Excessive torque is indicated by some stretching and distortion of the threads. The amount of stretch is difficult to determine by this method.

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Stretch may sometimes be detected by other means when lead and profile gages are not available. A straight edge may be used by putting it on the crest of the threads as shown in Figure B3-29. Figure B3-29 Stretched Pin from Excessive Torque

Figure B3-29. Excessive torque, either downhole or during makeup in rotary table, results in stretched and neckeddown pin. If the pin is stretched the 3rd, 4th and/or 5th thread crest from the shoulder will not be in the plane of the thread crest and daylight or space will occur between the crest of the thread and the straight edge. When checking with a straight edge, use caution that mechanical damage to the threads is not contributing to the space between thread crest and straight edge. If the drill string has been plastic coated, an inspection of the plastic coating in the stretched area may reveal circumferential cracks in the plastic coating. (Figure B3-1.) The circumferential cracks will coincide with the pin thread roots near the last engaged thread in the pin bore. Usually the pin will be stretched by over 0.006" in 2" whenever cracks occur in the plastic coating. When torsional failures or damages are detected, all pins left. in the string should receive a magnetic particle thread inspection to detect any cracks that may have occurred in the thread roots. 2d. Although downhole torque may be the major cause of torsional damage and failures -- torsional damage may also be initiated by over torquing in the rotary table. This is most prevalent on tool joints 3-1/2 IF and smaller. Using the recommended makeup torque and proper tool joint thread compound will minimize torsional damage due to over torquing.

C. Other Damages 1. Watch for lapped and worn threads for indications of wobble. Insufficient makeup torque allows wobbling and produces lapped and worn threads that may result in a broken tool joint pin. See Figure B3-30, Figure B3-31, Figure B3-32, Figure B3-33, Figure B3-34, and Figure B3-35.

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Figure B3-30 Lapped Threads Indicative of Insufficient Makeup Torque

Figure B3-30. Lapped threads, indicated by ridge on shoulder and thread flank, are evidence of wobbling connection caused from insufficient makeup torque. Figure B3-31 Shadowgraph Indicates Thread Lapping

Figure B3-31. Good thread should follow the dotted lines on the shadow graph. The ridge on the thread flank indicates that the connection was working on this surface due to lapping.

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Figure B3-32 Insufficient Torque Allows Wobbling of Tool Joint

Figure B3-32. Insufficient makeup torque allows wobbling and produces lapped, sharp and broken threads and broken pins.

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Figure B3-33 Wobble Occurs From Gall Area

Figure B-33. Wobble about two opposite high places on shoulder breaks threads on axis and laps those at 90° from axis.

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Figure B3-34 Wobble Causes Threads to Break when Tool Joint is Broken

Figure B3-34. Wobble causes threads to break and when connection is backed out, the broken threads become fouled. Such troubles are often incorrectly referred to as galls. Figure B3-35 Worn/Sharp Threads from Tool Joint Wobbles

Figure B3-35. Worn or sharp threads result from lapping when tool joint wobbles. There is a difference is wear on axis and 90° from axis. 2. Washes on faces can be caused by insufficient makeup torque, galled threads or stabbing damage. The shoulder is the only seal in the tool joint and will not prevent leaking if the connection is not made up to recommended torque, Figure B3-36 and Figure B3-37.

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Figure B3-36 Shoulder is Only Seal for a Rotary Tool Joint

Figure B3-36. Shoulder is the only area of seal in a rotary shouldered connection. Threads have a clearance between crest and root which acts as a channel for lubricant and fluid.

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Figure B3-37 Thread Washout from lack of Shoulder Seal

Figure B3-37. Washing will occur if the connection is not tightened with tongs and there is complete absence of a shoulder seal. Washed or damaged tool joint faces should be repaired immediately as shown in the next Section B3-VIII, below. The threads should also be inspected for any damage. 3. Heat checking or friction cracking is the result of rapid heating and cooling of the tool joint box or pin OD. A pattern of parallel surface cracks is formed perpendicular to the direction of rotation. Heating above the critical temperature results from the friction developed between the tool joint OD and the casing, formation, whipstock, or some other object that the tool joint may rub against. Drilling fluid provides the environment for the rapid cooling. Figure B3-38 shows a blacklight photograph of a heat checked tool joint box which has progressed to a fracture through the wall.

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Figure B3-38 Black Light shows Heat Checking

Figure B3-38. Heat-checking and resulting fractures are revealed under black light. Examine boxes and pins for longitudinal cracks. A blacklight inspection for longitudinal crack is necessary to find the full extent of the damage. Check boxes and pins. 4. The kelly saver sub should be cleaned and inspected every time it is removed from the rathole and always maintained in good condition. The saver sub mates with every tool joint box in the string as drilling progresses. See Figure B3-39.

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Figure B3-39 Inspect Saver Sub Regularly

Figure B3-39. Keep an eye on the saver sub. It mates with every box in the string if in poor condition, and may cause extensive damage. Clean and inspect saver sub regularly. If a saver sub is damaged, it should be repaired or replaced immediately. For this reason, a spare sub in good condition should be kept on the rig at all times. Follow recommended break-in practices when a newly threaded saver sub is placed in service. Always keep the rat hole as clean as possible. 5. Damage to and failure of tool joints can be caused by corrosion, corrosion fatigue, and sulfide stress cracking (SSC). See Section B5 for a discussion of these effects and how to control them.

VIII. Repair of Tool Joints A. General The repair of damage tool joints in the field and in the shop is discussed in subsections B and C respectively. The degree of damage is the determining factor in deciding whether it can be repaired in the field by shoulder dressing tools or by shop machine work. Some of the criteria have been discussed in Section B3. In either event, the following paragraph regarding plug and ring gages adopted by the API Task Group on Care and Use of Drill String should be considered: Thread wear, plastic deformation, mechanical damage and cleanliness may all contribute to erroneous figures when plug and ring gages are applied to used connections. Therefore ring and plug standoffs should not be used to determine rejection or continued use of rotary shouldered connections. Smooth sealing shoulders are more critical to tool joint operation than gage standoff. When refacing tool joint shoulders, material should be removed only when necessary; i.e., when it appears necessary to dress the make and break shoulder so it will seal again. Not more than 1/32" should be removed at one refacing and not more than 1/16" cumulatively. Use the benchmark to control this operation.

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B. Field Repair of Damaged Tool Joints Tool joints which are found to have a slight damage to the shoulders can usually be repaired at the rig with the hand held tools. Such damage includes slight crowning of the shoulders due to wobble, slight leakage, dents or upsets, fins, and galls. Where shoulders are obviously damaged, as those in Figures B3-40 and 41, repairs should be made. Figure B3-40 Repair Damage with Shoulder Dressing Tool

Figure B3-40: Slight damage such as shoulder upset can be repaired with shoulder dressing tool.

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Figure B3-41 Galled Shoulder Repaired with Shoulder Dressing Tool

Figure B3-41: Shoulder dressing tool can repair galled and scored box shoulders. In checking over a string of tool joints, all the shoulders not obviously in need of repairs, should be checked for flatness with the test ring as shown in Figure B3-42.

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Figure B3-42 Shoulder Test Ring to determine Condition of Shoulders

Figure B3-42: Shoulder test ring is used to check conditions of shoulders, before, during and after refacing. Shoulders must be faced flat and square with the threads. Threads must be deburred and checked with a thread profile gage before facing. Before using the test ring, be sure the shoulders and the ring are clean and dry. Hold the ring, which is flat itself, against the shoulder by applying pressure with the fingers at two diametrically opposed points, as shown in Figure B3-42 and attempt to make it rock. Figure B3-42: Shoulder test ring is used to check conditions of shoulders, before, during and after refacing. Repeat at points 90 degrees from the first points of pressure. If the ring rocks at all, the shoulder is either rough or crowned and it should be faced off flat with a Shoulder Dressing Tool. The shoulders of a used tool joint may be refaced to remove damage which might allow a washout to occur. It is good practice to remove a minimum amount but not more than 1/32 inch at any one refacing and never more than 1/16 inch cumulatively on each member. Use the box or pin benchmark to gauge the total amount of refacing.

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Pin and box benchmarks have been recommended for more than ten years. These should be used in judging how much a used tool joint shoulder has been faced. An API style benchmark should be required on all recut connections (Figure B3-43). Figure B3-43 Tong Space and Bench Mark Position

Figure B3-43: Tong space and bench mark position. (From API RP7G) Care must be used when dressing shoulders with power tools in the field as power tools are capable of removing an excessive amount of metal in an extremely short time. Should it be found on inspecting depth of damage on a shoulder that is too badly damaged to effect satisfactory repair with hand tools, it should be set aside for machine shop repair.

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Figure B3-44 Box Shoulder after Refacing

Figure B3-44. After refacing a box shoulder such as that shown in Figure 41, shoulder should be flat and square with the threads.

C. Shop Repair of Damaged Tool Joints The threads on the pins and boxes must be thoroughly cleaned and buffed. Magnetic particle inspection must be performed on the pin box thread roots. If cracks are found, the connection must be cut off. After machining, the connections must be rechecked for cracks. No cracks should remain in the newly cut connections. The thread gage stand-off must be checked with hardened and ground gages to API specifications. A thread profile gage must fit the threads and further checking of thread lead, thread taper, and thread forms may be indicated. Particular care must be taken on the following: 1. The specified thread root radius must be maintained. Lack of a proper radius in the root of the thread will result in premature fatigue failures. 2. Thread depth and thread crests must be maintained within specifications to avoid interference when connection is made up. 3. Thread angles must be maintained and the threads must be normal to the axis of the connection. 4. A radius at the shoulder of the pin connections must be maintained to specification.

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5. Specified perfect thread lengths must be maintained. This should be checked with a thread profile gage. 6. All dimensions such as counterbore diameter and length, pin thread length, shoulder bevel diameter, etc., shall be checked against specification drawings. 7. All newly-machined threads and shoulders should be treated to protect against galling during the break-in period. A phosphate coating is the usual treatment. 8. All connections shall be properly greased and thread protectors installed immediately after inspection. 9. Contact manufacturers for thread and dimensional data on non-API connections.

IX. Emergency Procedures A. O-Ring Use There may arise from time to time a situation which calls for a procedure which places upon drill pipe a condition or operating situation for which it was either not designed or for which it was not in suitable condition to perform. One such situation is the performance of either testing, squeezing, or fracturing using drill pipe wherein higher than normal drilling pressures are to be employed. The tool joints, as a result of normal drilling operations, may have small indentations on the faces, or small galled spots which render its pressure retention capabilities insufficient to handle the task to be performed. In this event, it is possible to place a rubber O-ring at the base of the pin immediately adjacent to the face of the pin. Many tool joint manufacturers build into the pin a shallow (1/16" deep) recess, called a mud groove. The selection of the proper O-ring may fill this groove and offer contact with the counterbore of the box tool joint, when the box and pin are screwed together. When pressure is applied, the O-ring will be compressed and will move to impede the flow of fluid across the faces of the tool joint. Care must be taken to restrict the amount of thread compound employed when using O-rings as a surplus of compound will cause the O-ring to move and to become pinched between the faces of the box and pin. The size of the O-ring to be used depends upon the design of the tool joints. Some manufacturers provide a conical section at the base of the pin which makes the space between the base of the pin and the counterbore of the box small, requiring an O-ring with 3/32" cross-section. Some manufacturers provide cylindrical section at the base of the pin which provides a larger void between the pin base and the box counterbore, requiring O-rings with crosssections from 1/8" to 3/16", depending upon the tool joint size. Before using O-rings, the base of the pins should be calipered and compared to API specifications to determine the conformation of the pin base and then select the proper O-ring that will fill the void and not become pinched between the box and pin faces.

B. Welding Procedures to be Used on Down Hole Drilling Tools Usually the materials used in the manufacture of down hole drilling equipment (tool joints, drill collars, stabilizers and subs) are AISI - 4135, 4140 or 4145 steels. These are alloy steels and are normally in the heat treated state. These materials are not weldable unless proper procedures are used to prevent cracking and to recondition the sections where welding has been performed. It should be emphasized that areas welded can only be reconditioned and cannot be restored to their original state free of metallurgical damage unless a complete heat treatment is performed after welding.

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Where welding becomes mandatory on downhole drilling tools, it is recommended that procedures as outlines by American Welding Society for the composition and configuration be consulted. The mechanical properties of API rotary shouldered connections on all drill stem members will be adversely affected by welding and will likely fail to meet the minimum requirements necessary in the critical portions of boxes and/or pins.

X. Transportation A. Truck Transportation API tubular goods in general, and threads in particular, require careful handling in transportation and storage as well as during drilling operations. The following precautions should be taken for truck transportation: 1. Load pipe on bolsters and tie down with suitable chain at the bolsters. In hauling long pipe, an additional chain should be provided in the middle. 2. Load with either all the pin ends or all of the box ends of the tool joints to the same end of the truck. 3. Care should be taken to prevent chafing of tool joint shoulders on adjacent joints. Proper spacing practices should be observed to prevent chafing of drill pipe by hard banding on tool joints. 4. Do not overload truck, boat, or barge with cargo to the point where there is any danger that load cannot be delivered to its destination without unloading. 5. After load has been hauled a short distance, retighten load binding chains loosened as a result of load settling.

B. Offshore Service Vessels The following are suggestions for loading and securing drill pipe and casing on offshore vessels. 1. Thread protectors must be installed on both ends of pipe, prior to commencement of loading operations. 2. Pipe is to be placed on wooden stringers which are spaced at approximately 10 foot intervals and shimmed to the same horizontal plane. 3. Wooden strips are placed so as to separate each layer of pipe; strips should be lined up on a vertical plane with the deck stringers. 4. Tubulars should be secured to the deck or hull of the vessel by the use of load binding cables or chains attached at structurally adequate points. The number and size of such cable or chains is usually determined by the boat captain according to expected sea conditions. Properly sized steam boat ratchets or turnbuckles are used to maintain proper chain or cable tension. Each layer of pipe should be blocked unless vertical stanchions are provided. 5. Special precautions are needed in loading and unloading pipe at offshore well sites. In rough seas, pipe loads that are to be handled by cranes must be kept at a minimum in the interest of safety and controlling the movement of swinging loads. 6. Movement of pipe between drilling tenders and derrick floor on offshore platforms presents problems in handling and individual conditions dictate that close supervision is needed to devise and regulate proper means for this operation. When possible, trolley lines, whirley cranes, and other means for controlled descent of pipe in lowering it from the derrick floor to the tender is necessary to prevent severe damage to drill string.

C. Handling The following precautions should be observed in handling pipe:

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1. Before unloading, make sure that the thread protectors are tightly in place. Use slings to load pipe. See Figure B3-45. Figure B3-45 Use of Slings to Load Drill Pipe

Figure B3-45. Use proper handling procedures when loading drill pipe utilizing hooks, slings, etc. 2. Do not unload pipe by dropping. Avoid rough handling which might ding or dent the body of the pipe. Out-ofroundness will reduce collapse strength greatly. 3. When roiling down skids, pull pipe parallel to the stack and do not allow pipe to gather momentum or to strike ends because, even with protectors in place, there is danger of damaging the threads. 4. Stop each length before it reaches preceding length; then push together by hand.

XI. Storage The following precautions are recommended for pipe storage: A. Do not pile pipe directly on ground, rails, steel or concrete floors. The first tier of pipe should be no less than 12 inches from the ground to keep moisture and dirt away from pipe. B. Pipe should rest on supports properly spaced to prevent bending of the pipe or damage to the threads. The stringers should lie in the same plane and be reasonably level, and should be supported by piers adequate to carry the full stack without settling. C. Provide wooden strips as separators between successive layers of pipe so that no weight rests on the tool joint. Use at least three spacing strips. D. Place spacing strips at right angles to pipe and directly above the lower strips and supports to prevent bending of the pipe.

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E. Stagger adjoining lengths of pipe in the tiers, an amount approximately the length of the tool joint or collars. F. Block pipe by nailing 1" by 2" by 2" wooden blocks at both ends of the spacing strips. Plastic chocks are now available which will do a better job of blocking. G. When pipe is to be stored, the bore should be washed out with clean fresh water and the bore coated with oil or rust preventive material. Tool joint pins and boxes must be cleaned and coated with a rust preventive material. Clean thread protectors should be installed in every pin and box. H. In cleaning for storage, crooked joints and damaged tool joint should be identified, marked, and set aside for repair. I. Rubber protectors should be removed during the storage period. A circumferential groove can be caused by corrosion when rubber protectors are left on during storage. This situation occurs quite frequently on all drill pipe grades, B3-46. Figure B3-46 Corrosion Ring caused by Protectors left on in Storage

Figure B3-46. A groove can be caused by corrosion of protectors left on pipe in storage. J. Pipe in storage should be visually examined periodically protective coatings applied inside and out when necessary to control corrosion.

XII. Floor Handling Procedures A. Slips and Bushing Requirements The successful handling of drill pipe with rotary slips and master bushings for all depths and drilling conditions is directly dependent on the following factors: 1. Compatibility in design and manufacture of master bushings and drill pipe slips.

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2. Proper application, based on hook load, of square drive and pin drive type rotating equipment. 3. Wear conditions existing in rotary table equipment. Square drive master bushings and/or matching bowls with the appropriate shorter slips can be used successfully when hook load does not exceed 250,000 lbs. For greater hook loads, it is advisable to use a master bushing designed to accept a 4 pin drive kelly bushing. The reason is that this type of bushing has an extended API taper, thus increasing the back-up support for the slips. The use of the extra long slips, which are designed to be compatible, will more effectively distribute the forces that try to crush or "bottleneck" the drill pipe. A comparison of conventional and extra long slips and standard and extended bowl master bushing combinations can be seen in Figure B3-47. Figure B3-47 Extended Bowl, Extra Long Slips Support Heavy Strings

Figure B3-47. Extended bowl, extra long rotary slips and pin drive allow for more effective support for heavy strings. Much can be done to prevent cutting, gouging and bottlenecking of drill pipe by proper maintenance of master bushings and rotary slips. This will prevent unnecessary downgrading and discarding of pipe as well as minimizing washouts and other types of downhole failures. The damaging effects of worn rotary tables, master bushings and rotary slips can be seen in Figure B3-48.

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Figure B3-48 DP Damaged with Worn Slips and New Master Bushings

Figure B3-48. Drill pipe will be damaged if there is any combination of worn and new master bushings, rotary table and slips. Obviously the drill pipe will be damaged under these circumstances. This is an extreme case; however, the same type of damage can be incurred with less worn equipment. This illustration (Figure B3-48) uses a split master bushing. A similar condition occurs after several years to the bowls and outer hull of a solid or hinged master bushing.

B. Simple Test to Check Condition of Rotary Slips and Master Bushings A slip test is an invaluable aid to determining the degree of rotary equipment wear. This test should be performed every three months and each time a new master bushings or set of slips is put into service. For accurate results, use a hook-load of at least 100,000 pounds: 1. Clean an area of pipe where there are no insert marks and clean slip inserts with a wire brash. 2. Wrap two layers of test paper or mud sack around the cleaned section of pipe. Use tape at the top and bottom of the paper to hold it in place. 3. Place the slips around the pipe and on the paper. Hole the slips in place while the pipe is lowered at normal speed. 4. After the slips are set, hold them firmly around the pipe as it is raised. The slips should be carefully removed to prevent damage to the paper. Then carefully remove the paper. Evaluation should be done by observing the second layer of the paper because the outside layer will have misleading slip impressions. If a full insert contact is indicated, the master bushing and slips are in good condition and no further analysis is necessary. If there is not full contact, the test should be rerun with new slips. If the second test results in full contact, discard the old slips because they are worn, crushed or otherwise distorted. Cut off the toes of discarded slips so they cannot be furbished and used again. If the results of the second test indicate top contact only, the master bushing and/or bowls are worn and should be inspected for replacement.

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C. Proper Slip Handling Techniques 1. The right size slips should always be used on the size pipe being handled. Figure B3-49 shows the effects of using the wrong size slip in tubular goods. Figure B3-49A Drill Pipe Damaged by Using Wrong Sized Slips

Figure B3-49B Drill Pipe Damaged by Using Wrong Sized Slips

Slips that are smaller than the pipe will damage the pipe and the comers of the slips as well as risk dropping a string of pipe. Slips that are too large will not contact the pipe all the way around. This risks dropping the pipe and destroys the center part of the slips's gripping surface. 2. The downward motion of the drill pipe must be stopped with the drawworks brakes, not with the slips. Figure B3-50 shows the effect of stopping the motion of the pipe with slips.

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Figure B3-50 Do Not Stop Drill Pipe with Slips

Figure B3-50. Effects of stopping downward motion of drill pipe with slips. This can occur when the floor hands are not careful to set the slips after the driller has stopped the pipe. Pipe and collars larger than the slips rapidly wear down the outer edges of the gripped elements with damage as shown above. After using slips on drill stem elements that are too large, the same slips will quickly damage the smaller but correct size pipe because of the reduced contact surface of the dripping elements. A. Swedges and elongates pipe in slip area. B. Stretches and bottlenecks pipe. C. Transmits excessive load to rotary table and master bushing or slip bowl. 3. Do not let the slips "ride" on the pipe while it is being pulled out of the hole. This practice accelerates the wear on the gripping elements of the slip. It also may cause the slip to be ejected from the rotary bowl when a tool joint comes through with possible injury to personnel. 4. Never resharpen inserts. Doing so causes improper contact with the pipe, resulting in both pipe and slip damage as is illustrated in Figure B3-51.

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Figure B3-51 Do Not Use Resharpened Gripping Elements

5. Setting Slips on Tool Joint: Be careful not to catch the tool joint box in the slips when the driller slacks off. This often happens when coming out of the hole and the driller does not pick up high enough for the slips to fall around the pipe properly. (Figure B3-52.) This can ruin the slips, damage the tool joint box and body of the pipe. Figure B3-52 Do Not Catch the Tool Joint with the Slips

Figure B3-52. Try to prevent catching the tool joint accidentally with the slips.

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D. Proper Use of Drill Pipe Tongs Tonging tool joints properly is the most important single factor in prevention of tool joint troubles. Tables B1-7 give the recommended makeup torques for the various sizes, types and classes of tool joints. Torque measuring equipment should always be used to prevent under makeup or over makeup of tool joints. Slicker than normal thread compounds can contribute to torsional problems. 1. Always use back-up tongs when making up or breaking out drill pipe stands. Without back-up tongs, the pipe may rotate and cause deep slip cuts. Such slip cuts are usually spiral because the pipe is dropping as it rotates. Also the use of one tong greatly increase the possibility of bending or "hooking" the pipe at the rotary. 2. Keep the tool joint as close to the rotary table as possible during makeup and breakout. There is a maximum height that a tool joint may be positioned above the rotary slips and the pipe still be able to resist bending, Figure B3-53. Figure B3-53 Determine the Height of Tool Joint above Slips

Figure B3-53: The sketches and formulas show how to figure height of tool joint above the slips. This is while maximum torque is applied. Factors governing the height limitation are: a. Angle of separation between tongs. b. Minimum tensile yield strength of pipe. c. Length of the tong handles. d. Maximum recommended makeup torque. Although not recommended, if only one tong is used with a locked rotary table, height of the tool joint should not exceed that shown in Case I. Also line pull should not exceed recommended makeup torque with tongs at 90 degrees to the jerk line. 3. Height above the rotary table can be calculated by means of the following: In the formula, Figure B3-53:

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Figure B3-53 Determine the Height of Tool Joint above Slips Hmax = Height of tool joint above slips, ft Ym = Minimum tensile yield of pipe, psi. Grade E-75

75,000

Grade X-95

95,000

Grade G-105

105,000

Grade S-135

135,000

LT = Tong arm length, ft (measured on rig) P = Line pull, lb. T = P x LT, makeup torque, Table B1-7 Table B1-7 Minimum OD and Make-up Torque of Weld-on Tool Joints I/C = Section Modulus of pipe, in, Table B3-1. Table B3-1 Section Modulus Values Sample Calculations Assume: 4-1/2 in, 16.60 lb/ft, Grade E75 drill pipe, with 4-1/2 in, XH 6 in OD, 3-1/4 in ID tool joints. Tong arm 3 1/2 ft. Tongs at 90 degrees. Ym = 75,000 psi (for Grade E75) I/C = 4.27 in LT = 3.5 ft T = 18,000 ft-lbs.

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B4. Drill String Operating Limits I. Fatigue and Lateral Forces caused by Dog Legs and Floating Vessels It is well known that metal is weaker under dynamic loading than under static conditions. Steel has the capability of absorbing dynamic loading, or cycles of stress, for an infinite number of reversals if the stress is kept under a certain limit. This is illustrated in Figure B41, which is a simple example of an S-N curve, stress versus number of cycles to produce failure. Figure B4-1. S-N curve of mild steel shows number of cycles under stress to produce failure

The point at which the curve straightens out is called the endurance limits of steel. If the stress never goes above that point, any number of cycles will not cause failure. To illustrate simply, consider a nail bent back and forth until it breaks. With this mild steel if the stress is kept below 27,000 psi the nail will not break regardless of the cycles. At 30,000 psi the nail will break with 2,000,000 cycles and at a stress of 48,000 is the elastic limit, the nail will break immediately. Such failures with cyclic stresses are called fatigue failures, Figure B4-2.

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Figure B4-2 Pure Fatigue Failure in Drill Pipe

The mechanism of fatigue failure is a progressive one. It starts a submicroscopic yielding of the atoms along the crystal slip planes. With alternating stress, heat is generated with this moving, lowering the cohesive strength of the constituents. This forms submicroscopic cracks which will progressively unite until the crack becomes visible. The direction of the crack is normal, 90 degrees to the stress. Thus drill pipe failures will be circumferential. The chemical composition, microstructure, surface finish, and tensile properties are some of the properties of steel which determine the fatigue or endurance limit. A very rough approximation of the fatigue strength of drill pipe is one half of its tensile strength. In addition, the presence of notches and corrosion have a great effect on the fatigue strength. Drill pipe is subjected to cyclic stresses in tension, compression, torsion and bending. Tension and bending (alternate tension and compression of the same pipe wall) are the most critical stresses. The magnitude of any stress can be compounded by the effect of vibration. Pure fatigue failures in straight hole drilling are becoming less frequent. This is exclusive of dog-legged or deviated holes or where failures are associated with notches and corrosion. It is due to the general practice of using sufficient drill collar weight so that the drill string is in tension down through the top two or three drill collars. Buoyancy and hole inclination must be considered when calculating drill collar weight to keep drill pipe in tension. Today the major factor in fatigue failures is the cyclic bending when pipe is rotated in a hole having a change in direction. This is commonly called a dog-leg and occurs in straight hole drilling as well as in directional drilling. Failure can occur even when proper drill collar weight is maintained, and there is no permanent set in the drill pipe. When pipe is deflected and rotated, it goes through cycles of stress from tension to compression on each side of the pipe with each rotation. It might be noted that drill pipe rotating at 100 rpm makes 144,000 revolutions per day if left on bottom continually. Hence in just 7 days there could be more than a million stress cycles on the pipe when rotating under conditions creating variable stress. Using the S-N curve in Figure B4-1, if the stress was 32,000 psi, the pipe would fail in that time.

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The portion of the string right above the drill collars is potentially most subject to bending. Drill collar mass will resist bending and deflection will occur above in the drill pipe. Also maximum stress on the drill pipe will occur from the runout point of the upset to approximately 20 inches from the tool joint. As above, the tool joint will not bend and the bending occurs in the relatively thin pipe wall. This change of cross section in the tool joint acts as a vise and becomes the fulcrum of the bending force. If the pipe could bend uniformly throughout its length, stress would be lower and cycles of stress to failure higher.

A. Extent of Fatigue Damage The amount of fatigue damage depends upon: 1. The tensile load in the pipe at the dog-leg. 2. The severity of the dog-leg. 3. The number cycles in the dog-leg of each portion of the pipe. 4. The dimensions and properties of the pipe. Since tension in the pipe is critical, a shallow dog-leg in a deep hole often becomes the source of difficulty. Also rotating off bottom below a dog-leg is not a good practice because of the additional load of the drill collars. Figures B4-3, Fogure B4-4, and Figure B4-5 from Hansford and Lubinski show conditions necessary for fatigue to occur.

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Figure B4-3 Fatigue Damage in abrupt doglegs for 3-1/2" 13.3 ppf Drill Pipe

Figure B4-4 Fatigue Damage in abrupt doglegs for 4-1/2" 16.6 ppf Drill Pipe

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Figure B4-5 Fatigue Damage in abrupt doglegs for 5" 19.5 ppf Drill Pipe

It is necessary to remain to the left of the fatigue curve to prevent fatigue damage. If these conditions are exceeded, a certain percentage of permanent damage will occur. The extent depends upon the number of cycles under the stressed conditions.

B. Cumulative Fatigue Methods are available for estimating the cumulative fatigue on joints of pipe which have been rotated through severe doglegs. The method portrayed in Figures B4-6 and 7 is a simple device to be used as a guide in the analysis of joints suspected of suffering fatigue damage. A correction formula to use for other penetration rates and rotary speed is: % Life Expended = % life expended from Figures 4-6 and 4-7 x (Actual RPM/100) x (10/Actual ft/hr) It must be emphasized that such damage is permanent even though the stress is relieved and/or the joint passes through the dogleg. Similar repetitive stresses on the joint will eventually cause failure. For example, from Figure B4-6, a tension of 70,000 lbs on 3-1/2 inch pipe in a 10 degree dogleg with 6000 ft of pipe below the dogleg will expend 35% of the life of the joint.

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Figure B4-6 Fatigue Damage in gradual doglegs in Non-Corrosive Environment

Figure B4-7 Fatigue Damage in gradual doglegs in a Corrosive Environment

If the joint passes through this or a similar dogleg with the same rotary speed and penetration rate three times it will

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fail. Three times the rotary speed at 1/3 the penetration rate will give the same effect. In the same regard, drill pipe may be damaged on one hole even though it does not fail. If it is placed near the top of the string on the same or next hole, it may or may not be able to withstand the very nominal bending stresses encountered. Thus, failures can occur later and far from the position in the string where the trouble started, or in subsequent wells. If doglegs of sufficient magnitude are known or suspected, it is good practice to string-ream the dogleg area. This reduces the severity of the hole angle change. When drill pipe in a dogleg is in tension, it is pulled to the inside of the bend with substantial force. The lateral force will increase the wear of the pipe and tool joints. When abrasion is a problem, it is desirable to limit the amount of lateral force to less than about 2000 lb on the tool joints by controlling the rate of change of hole angle. Values either smaller or greater than 2000 lb might be in order, depending on formation at the dogleg. Figures B4-8 through B4-11, developed by Lubinski, show lateral force curves for both tool joints and drill pipe for 3 popular sizes. The first three figures are for three pipe sizes, Range 2. Figure B4-11 is for 5", 19.5 lb per foot, Range 3 drill pipe.

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Figure B4-8 Lateral Forces on 3-1/2", 13.3 ppf R2 Drill Pipe with 4-3/4" Tool Joints

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Figure B4-9 Lateral Forces on 4-1/2", 16.6 ppf R 2 Drill Pipe with 6-1/4" Tool Joints

Figure B4-10 Lateral Forces on 5", 19.5 ppf R2 Drill Pipe with 6-3/8" Tool Joints

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Figure B4-11 Lateral Forces on 5", 19.5 ppf R3 Drill Pipe with 6-3/8" Tool Joints

a. For conditions represented by points located to the left of curve No. 1, such as Point A in Figure B4-8, only tool joints not drill pipe between tool joints, contact the wall of the hole. This should not be construed to mean the drill pipe body does not wear at all, as Figure B4-8 is for a gradual and not for a abrupt dogleg. In an abrupt dogleg, drill pipe does contact the wall of the hole half way between tool joints, and the pipe body is subjected to wear. This lasts until the dogleg is rounded off and becomes gradual. b. For conditions represented by points located on Curve No. 1, theoretically the drill pipe contacts the wall of the hole with zero force at the midpoint between tool joints. c. For conditions represented by points located between Curve No. 1 and Curve No. 2, theoretically the drill pipe still contacts the wall of the hole at midpoint only, but with a force which is not equal to zero. This force increases from Curve No. 1 toward Curve No. 2. Practically, of course, the contact between the drill pipe and the wall of the hole will be along a short length located near the midpoint of the joint. For conditions represented by points located to the right of Curve No. 2, theoretically the drill pipe contacts with the wall of the hole -- not at one point, but along an arc with the increasing length to the right of Curve No. 2. On each of the Figures B4-8 through B4-11, there are in addition to curves No. 1 and No. 2, two families of curves: one for the force on tool joint, and the other for the force on drill pipe body. As an example, consider Figure B4-8, Point B indicates that if the buoyant weight suspended below the dogleg is 170,000 lb, and if dogleg severity (hole curvature) is 10.1 degrees per 100 feet, then the force on tool joint is 6,000 lb, and the force on drill pipe body is 3,000 lb.

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Tool joints which are rotated under high lateral force against the wall of the hole may be damaged as a result of friction heat checking. The heat generated at the surface of the tool joint by friction with the wall of the hole when under high radial thrust loads may raise the temperature of the tool joint steel above its critical temperature. Metallurgical examination of such joints has indicated affected zones with varying hardness as much as 3/16 inch below OD surface. If the radial thrust load is sufficiently high, surface heat checking can occur in the presence of drilling mud alternately being heated and quenched as it rotates. This action produces numerous irregular heat check cracks often accompanied by longer axial cracks and sometimes extending through the full section of the joint and washouts may occur in the splits or windows. Maintaining hole angle control so that 2000 lb lateral force is not exceeded will minimize or eliminate heat checking of tool joints. (See Figure B3-38.) Roll and pitch of a drilling vessel results in bending of the kelly and the first joint of drill pipe. Two major factors which are specific to drilling from a floater that contribute to fatigue of drill are as follows: a. The rotary table is not centered at all times exactly above the subsea borehole. b. The derrick is not always vertical but follows the roll and pitch motions of the floater. This text pertains to prevention of fatigue due to factor b, above. When the derrick is inclined during a part of the roll or pitch motion, the upper extremity of the drill string is not vertical while the drill pipe at some distance below the rotary table remains vertical. Thus the drill string is bent. As drill pipe is much less rigid than the kelly, most of the bending occurs in the first length of drill pipe below the kelly. This subject is studied in a paper titled: "Effect of Drilling Vessel Pitch or Roll on Kelly and Drill Pipe Fatigue", by John E. Hansford and Arthur Lubinski<1>. Based on the Hansford and Lubinski paper, the following practices are recommended to minimize bending and, therefore, fatigue of the first joint of drill pipe, due to roll and/or pitch of a floater. a. Multiplane bushings should not be used. Either a gimbaled kelly bushing, or a one-plane roller bushing is preferable. b. An extended length kelly should be used in order to relieve the severe bending of the limber drill pipe through less severe bending of the rigid kelly extension. This extension may be accomplished by any of the following means: 1. For Range 2 drill pipe, use a 54-foot kelly which is ordinarily used with Range 3 pipe, rather than the usual 40foot kelly. 2. Use a specially made kelly at least 8 feet longer than the standard length. 3. Use at least 8 feet of kelly saver subs between the kelly and drill pipe. c. If b, above, is not implemented, avoid rotating off bottom with the kelly more than half way up for long periods of time if the maximum angular vessel motion is more than 5 degrees single amplitude. In this text, long periods of time are: 1. More than 30 minutes for large hookloads. 2. More than 2 hours for light hookloads. d. If conditions prevent implementing b or c, above, the first joint of drill pipe below the kelly should be removed from the string at the first opportunity and discarded. <1> Hansford, John E. and Lubinski, Arthur: "The effect of Drilling Vessel Pitch or Roll on Kelly and Drill Pipe Fatigue," -- Transactions of AIME, 1964, Vol. 231.

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II. Fatigue Caused by Other Factors A. Notch Fatigue After understanding the mechanism of fatigue failure, i.e., a progressive propagation of a minute crack, let us examine the effect of surface discontinuities upon the fatigue strength. Surface imperfections, either mechanical or metallurgical, depending upon their location, orientation, shape, and magnitude, greatly affect the fatigue limit. Aside from providing the initial distortion of the grain of steel, the notch raises the stress level and concentrates the breaking down of the metal structure. If a notch occurs upon a portion of the drill pipe which is not subject to stress, it will have little effect; but if located within 20 inches of the tool joint where maximum bending moments occur, it can form the nucleus of a fatigue break. A longitudinal notch is fairly harmless, but if circumferential (in the direction of applied stress) will lead to failure. A relatively extensive saucer shaped notch with a rounded bottom will distribute the stress and be harmless while fight beside it will be a minute scratch with a sharp bottom to act as a stress raiser and lead to failure. The shape of the bottom of the notch is a of prime importance. Perhaps this can be understood more readily by considering the problem of cutting a glass pane. If a new glass cutter with a sharp roller is employed, a very light stroke with the cutter gives a clean break on bending the pane. If a dull cutter wheel is employed, giving a round bottom notch, the bending stress is distributed and the break will follow planes of weakness in the glass and not the score. As most mechanical notches contain cold worked microstructure (with low ductility and consequent low fatigue limit), the magnitude of the notch affects the fatigue limit. Some steels are more sensitive to notches than other steels. This is referred to as notch sensitivity and is related to the ductility of the steel. Various surface conditions which can, or do, result in notch fatigue failures are noted as follows: 1. Steel stencilling on drill pipe. 2. Electric arc burns. 3. Rubber protector grooves. 4. Tong marks. 5. Slip marks. 6. Formation and "Junk" cuts. 1. Steel Stencilling on Drill Pipe Inasmuch as any transverse mark can be a dangerous stress concentration point, it is not surprising that steel stencil marks can be the start of fatigue when parts of the letter are transverse to the pipe and the steel stamp is in the wrong place. This is illustrated in Figure B4-12 with the crack starting in the cross-bar of the Letter A. The mud eroded crack has started in the horizontal line of the Numeral 7.

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Figure B4-12 Notch Fatigue Failures from Stencil Marks

Figure B4-12. Notch fatigue failures can occur from steel stencil marks placed on the body of the pipe. Drill pipe should never be stamped on the body of the pipe. 2. Electric Arc Burns Though of infrequent occurrence, the attaching of ground lead to the pipe rack instead of the material being welded does happen. This is particularly dangerous in that the subsequent arcing between the rail and the pipe goes unnoticed and the pits, though small, are surrounded by a wide band of burnt metal that is glass hard and very prone to rapid fatigue failure. 3. Rubber Protector Grooves A cause of notch fatigue is the occurrence of a circumferential groove at the top of the rubber drill pipe protectors. Modern protectors are designed to minimize this condition. This situation occurs when the rubber protectors are left in storage. The protector rubbers should be removed during the storage period, Figure B3-46. 4. Tong Marks Deep tong marks are probably the worst looking surface defects ever produced on drill string in the field. The are long and deep and frequently quite sharp, yet being longitudinal, they are in the direction of applied stress and seldom lead to failures. This perfectly longitudinal direction is important as a very slight deviation from the vertical can become a stress concentration point. The application of tongs to the body of the pipe instead of to the tool joint is considered bad practice due to the possibility of crushing the pipe, Figure B4-13.

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Figure B4-13 Tongs can Crush Pipe and Leave Tong Marks

Figure B4-13. Tongs applied to the body of the pipe can crush the pipe and cause failure through tong marks. 5. Slip Marks Rotary table slips are made with fine serrations which ordinarily do leave injurious marks on the drill pipe. However, the slips if mistreated, worn, or carelessly handled, can score the pipe. Slips with worn, mismatched, incorrect size, or improperly installed gripping elements can allow one or two teeth or portions of teeth to catch the full load of the drill string causing deep notching, cold work, and. potential failure, Figure B4-14.

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Figure B4-14 Pipe Failure from Pipe Body Slip Marks

Figure B4-14. Pipe body slip marks can cause failure. The practice of rotating drill string with the slips can, if any slippage occurs, leave a dangerous transverse notch in the drill pipe. The making up or breaking out of drill strings without back-up tongs can also cause slippage and potentially dangerous notches. Back-up tongs should always be used. Also see Figure B4-15 for other causes of drill pipe scars.

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Figure B4-15 Scars on Pipe from Broken Off Tooth from Mill Tooth Bit

Figure B4-15. Broken off milled tooth bit causes scars and indentations.

B. Crooked Pipe Fatigue The importance of not running crooked drill pipe cannot be overemphasized. A crooked joint is always a potential failure. A crooked kelly can cause bending in the first joint of drill pipe below the rotary table. If the stress is high enough failure will occur. Having a crown block off center can cause failure. This throws bending stresses in the kelly and drill pipe.

C. Corrosion Fatigue Corrosion fatigue, or fatigue in a corrosive environment, is probably the most common cause of fatigue failures in drill pipe. The fatigue life of drill pipe is dependent upon the corrosivity of the environment. As shown in Figure B4-16, drill pipe stressed at 27,500 psi in a non-corrosive environment (air) will not fail by fatigue; will have a fatigue life of 2,300,000 cycles in a mildly corrosive environment (salt water); a fatigue life of 1,300,000 cycles in a corrosive environment (magnesium chloride solution); and a fatigue life of 500,000 cycles in a very corrosive environment (hydrochloric acid).

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Figure B4-16 S-N Curve for Drill Pipe

Figure B4-16. Typical S/N Curves for Drill Pipe in Various Media. In the presence of hydrogen sulfide, if the drill pipe strength is sufficiently high for sulfide stress cracking to occur, the fatigue life will be further reduced. See Section B5, below for a discussion of the effects and how to control them.

III. Critical Rotary Speed Critical rotating speeds in drill strings cause vibrations and arc often the cause of crooked drill pipe, excessive wear, and rapid deterioration and fatigue failure. Critical speeds will vary with length and size of drill stem and collars and hole size. There is evidence in field tests that excessive power is required at the rotary to maintain a constant speed at critical conditions. This power indicator, plus surface evidence of vibration, should warn the crew that they are in the critical range. Various types of vibration may occur. The pipe between each tool joint may vibrate in nodes, as a violin string. Another type of vibration is of the spring pendulum type. Other types of vibrations may occur. Each vibration type has critical speeds at which they occur. Presently no generally accepted method exists to accurately predict critical rotary speeds.

IV. Collapsed Pipe -- From Drill Stem Test and BOP Test In carrying out various information tests, drill pipe is run empty in the well and set into the formation being tested before the valve at the bottom is opened. This subjects the bottom lengths to the full hydrostatic pressure of the drilling fluid, and has been known to cause collapse. Worn pipe can contribute to collapse failures in drill stem testing.

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During BOP tests, using a test string, be certain that the annulus is vented if a ram is closed beneath another closed ram or annulus. Failure to do this could result in collapsed pipe since there is no place for the fluid being displaced by the operating rod to go.

V. Transition from Drill String to Drill Collars Frequent failure in the joints of drill pipe just above the drill collars suggests abnormally high bending stresses in these joints. When joints arc moved from this location and rotated to other sections, the effect is to lose identity of these damaged joints. When these joints later fail through accumulation of additional fatigue damage, every joint in the string becomes suspect. One practice to reduce failures at the transition zone and to improve control over the damaged joints is to use nine or ten joints of heavy wall pipe, or smaller drill collars, just above the collars. These joints arc marked for identification, and used in the transition zone. They are inspected more frequently than regular drill pipe to reduce the likelihood of service failures. The use of heavy wall pipe reduces the stress level in the joints and ensures longer life in this severe service condition.

VI. Maximum Allowable Pull and Rotary Torque Pure tension failures are involved while pulling on stuck drill pipe. As the pull on the pipe exceeds the yield point (minimum area yield), the metal distorts in a characteristic "necking down" of the weakest area of the pipe wall or smallest cross sectional area. The minimum yields are shown in Tables B1-1 through B1-4, and B2-1 through B2-3. Table B1-1 Tool Joints on Standard Weight Drill Pipe - Grade 75 Table B1-2 Tool Joints on Light Weight Drill Pipe - Grade 75 Table B1-3 Tool Joints on Heavy Weight Drill Pipe - Grade 75 Table B1-4 Tool Joints on High Strength Drill Pipe Table B2-1 New DP - Torsion, Tension, Collapse, Internal Pressure Table B2-2 Used DP - Torsion, Tension, Collapse, Internal Pressure Table B2-3 Class 2 DP - Torsion, Tension, Collapse, Internal Pressure If pull is further increased to exceed the ultimate strength, the string will part, Figure B4-17.

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Figure B4-17 Bottleneck Failure - Ultimate Tensile Strength Exceeded

Note: Drill pipe will bottleneck when pulled above its yield strength and will part when pulled to its ultimate tensile strength. Such failures normally occur near the top of the string which is subject to the pull plus the weight of the string. When drill .pipe is stuck, the yield or ultimate strengths may be exceeded due to errors in weight indicators. The above should be a caution that such pulls should be tempered with good judgment, proper safety factors or fact that an emergency does exist. Tension figures in the above mentioned tables are for new pipe and reductions in cross sectional area based on the IADC-API used pipe classification system. Safety factors should be applied and account taken for wear since purchase or last grading of the pipe. Unless there is an area of concentrated tension loading, damage can occur by a uniform lineal yielding or stretch of the pipe and downgrading of the entire string. If a drill string is suspected of having been pulled beyond the yield point, all the upper part of the string should be examined closely to see whether the lengths have been stretched. This can be done by comparing the "before and after" length tally or by checking the outside diameter with calipers. Dangerous elongation can be detected readily and such lengths discarded. However, it is hard to define "dangerous" elongation. The stretching or distortion causes work hardening of metal with a consequent loss in ductility. Also, there is danger that the stretch has not been as uniform as it seems. This would give an area of Low ductility and reduced cross section not discernible by eye or measurement. In addition, another phenomena has taken place which is not measurable. This is called the "Bauschinger effect." Simply stated, this means that steel which has been overstressed in tension has a reduced yield point in compression. Thus a piece of stretched drill pipe will not again yield to a tension load until the previous tension load has been exceeded but has a reduced compressive yield strength. Such a joint at the bottom of the drill string where compressive loading occurs is dangerous. Thus it is good practice to discard all stretched lengths, or at least to downgrade them to less severe service.

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Drill string torque will reduce the tensile yield. This must be considered when drilling, tripping (back reaming with top drive) and fishing as in washover operations or working stuck pipe. Allowable pull and torque combinations for drill string may be determined by the use of the following formula:

Where: QT = Minimum Torsional Yield Strength Under Tension, lb-ft J

= Polar Moment of Inertia = 0.1 (D4 - d4 ) for tubes

D = Outside Diameter, inches d = Inside Diameter, inches YM = Minimum Unit Yield Strength, psi SM = Minimum Unit Shear Strength - psi; (SM = 0.577 YM) P = Total Load In Tension - pounds A = Cross Section Area - inches An example of the torque which may be applied to the pipe which is stuck while imposing a tensile load is as follows: Assume: 3-1/2 inch O.D. 13.30 lb Grade E-75 drill pipe w/

3-1/2" IF tool joints

Stuck point: 4000 feet; Tensile pull: 100,000 pounds New drill pipe Then:

= 17,216 ft-lb For further information on allowable hookloads, torque application, and pump pressure use, refer to Stall and Blenkarn: "Allowable Hook Load and Torque Combinations for Stuck Drill Strings."<2>

VII. Make up Torque versus Drilling Torque Use the proper thread lubricant and manufacturers recommended make up torque. API RP7G Now recommends make up torque equal to 60% of tool joint torsional yield strength. Sometimes down hole make up occurs in spite of the use of proper thread lubricant and recommended make up torque. Downhole make up causes tight breaks and can result in damaged threads and sealing shoulders. Several things can be done to prevent downhole makeup: 1. Limit rotating torque to 80 % of recommended makeup torque using rotary table torque limiting devices. 2. Increase make up torque to 70% of tool joint torsional yield strength. Never exceed 70% of yield.

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VIII. Fishing Operations A. Pulling on Stuck Pipe It is normally not considered good practice to pull on stuck drill pipe beyond the limit derived from the API-IADC used Drill Pipe Classification System. These limits are given in Tables B2-1 through B2-3. Table B2-1 New DP - Torsion, Tension, Collapse, Internal Pressure Table B2-2 Used DP - Torsion, Tension, Collapse, Internal Pressure Table B2-3 Class 2 DP - Torsion, Tension, Collapse, Internal Pressure It must be assumed that the pipe is near the minimum cross sectional area of its class and will fail in tension if the load is excessive. For example, assuming a string of 5 inch, 19.5 lb/ft Grade E-75 drill pipe is stuck, the following approximate values for maximum hook load would apply: Premium Class = 311,540 lbs;

Class 2 = 270,430 lbs

The stretch in the drill pipe due to its own weight suspended in a fluid should be considered when working with drill pipe and the proper formulas to use for stretch when free or stuck should be used. Example 1 Determine the stretch in a 10,000 ft string of drill pipe freely suspended in 10 lb/gal drilling fluid.

= {(10,000)2 / (9.625 X 107)} x [65.44 - 1.44 x 10]

= 53.03 inch

Where: L1 = length of free drill pipe, feet Wg = weight of drilling fluid, lb/gal e = total elongation, inches Example 2: Determine the free length in a 10,000 ft. string of 4-1/2" inch O.D. 16.60 lb/ft drill pipe which is stuck, and which stretches 49 inch due to a differential pull of 80,000 lbs.

= 735,294 x 49 x 16.60 / 80,000 = 7,476 ft Where: L1 = length of free drill pipe, feet e = total elongation, inches Wdp = weight of drill pipe, pounds per foot P

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B. Jarring It is common practice during fishing, testing, coring and other operations to run rotary jars to aid in freeing stuck assemblies. Normally, the jars are run below several drill collars which act to concentrate the blow at the fish. It is necessary to take the proper stretch to produce the required blow. The momentum of the moving mass of drill collars and stretched drill pipe returning to normal causes the blow after the jar hammer is tripped. A hammer force of three to four times the excess of pull over pipe weight is possible depending on type and size of pipe, number (weight) of drill collars, drag, jar travel, etc. This force may be large enough to damage the stuck drill pipe and should be considered when jarring operations are planned.

C. Torque in Washover Operations Although little data are available on torque loads during washover operations, they are significant. Friction and drag on the wash pipe cause considerable increases in torque on the tool joints and drill pipe, and should be considered when pipe is to be used in this type of service. This is particularly true in directionally drilled wells and deep straight holes with small tolerances. The effect of torque on maximum allowable pull should be considered.

IX. Dynamic Loading of Drill Pipe during Tripping A. When running a strand of drill pipe into or out of the hole, the pipe is subjected not to its static weight, but to a dynamic load. B. The dynamic load oscillates between values which are greater and smaller than the static load (the greater values may exceed the yield), which results in fatigue, i.e., shortening of pipe life. C. Dynamic loading exceeding yield may occur only in long strings, such as 10,000 ft. D. Dynamic loading increases with the length of drill collar string. E. In the event the smallest value of the dynamic load tries to become negative, the pipe is kicked off the slips, and the string may be dropped into the hole. F. The likelihood of dynamic loading resulting in a jumpoff (kicking of the slips) increases as the drill pipe string becomes shorter and the collar string becomes longer. G. For a long drill pipe string, such as 10,000 ft a jumpoff is possible only if drill pipe, after having been pulled from the slips, is dropped to a very high velocity, such as 16 ft/sec. H. Dynamic phenomena are severe only when damping is small, which may be the case in exceptional holes, in which there are no dogleg, the deviation is small, the cross-sectional area of the annulus is large, and the mud viscosity and weight are small. I. In case of small damping, the running of a stand of drill pipe should not be less than 15 seconds. For a more detailed study of the phenomena the following references are given: 3. Arthur Lubinski "Dynamic Loading of Drill Pipe During Tripping" Journal of Petroleum Technology (August, 1988). 4. Same as above but presented at 1988 IADC/SPE Drilling Conference Paper No. 17211.

X. Biaxial Loading of Drill Pipe The effects of combination of loop stress (Collapse and Burst) and axial stress (Tension and Compression) on drill pipe yield is discussed in RP7G Section 9. Only the following practical comment is made in this text:

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In carrying out various formation tests, drill pipe is run empty in the well and set into the formation being tested before the valve at the bottom is opened. This subjects the bottom lengths to the full hydrostatic pressure of the drilling fluid, and has been know to cause collapse. Worn pipe can contribute to collapse failures in drill stem testing.

XI. Drill String Design The drill string is required to serve three basic functions: 1. Transmit and support axial loads. 2. Transmit and support torsional loads. 3. Transmit hydraulics. The design parameters and a step-by-step procedure of designing a string is given in API RP7G, Section 5. Another recommended source document is: 5. G. K. McKown: "Drill String Optimization for High Angle Wells", 1989 SPE/IADC Drilling Conference Paper No. 18650.

XII. References 1. Hansford, John E. and Lubinski, Arthur: "The effect of Drilling Vessel Pitch or Roll on Kelly and Drill Pipe Fatigue," -- Trans. AIME, 1964, Vol. 231. 2. J. C. Stall and K. A. Blenkarn, "Allowable Hook Load and Torque Combinations for Stuck Drill String," - Mid Continent API Dist. Meet. Paper No. 851-36M (April 6, 1962). 3. Arthur Lubinski "Dynamic Loading of Drill Pipe During Tripping" Journal of Petroleum Technology (August, 1988). 4. Same as above but presented at 1988 IADC/SPE Drilling Conference Paper No. 17211. 5. G. K. McKown: "Drill String Optimization for High Angle Wells", 1989 SPE/IADC Drilling Conference Paper No. 18650.

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B5. Drill String Corrosion I. Introduction One of the most prevalent causes of premature drill stem failures is the damage resulting from corrosion, corrosion fatigue, and sulfide stress cracking. The section will briefly describe the manner in which the damage occurs, how to detect it, and how to control it. However, because of the complexity of the problem, and its serious economic and safety effects, expert technical advice should be obtained when such damage is evident or suspected.

Il. Corrosion A. Corrosive Agents. Corrosion may be defined as the alteration and degradation of material by its environment. The principal corrosive agents affecting drill stem materials in water-base drilling fluids are dissolved gases (oxygen, carbon dioxide, and hydrogen sulfide), dissolved salts, and acids. 1. Oxygen Oxygen is the most common corrosive agent. In the presence of moisture, it causes rusting of steel, the most common form of corrosion. Oxygen causes uniform corrosion and pitting, leading to washouts, twistoffs, and fatigue failures. Since oxygen is soluble in water, and most drilling fluid systems are open to the air, the drill stem is continually exposed to potentially severe corrosive conditions.

2. Carbon Dioxide Carbon Dioxide dissolves in water to form a weak acid (carbonic acid) that corrodes steel in the same manner as other acids (by hydrogen evolution), unless the pH is maintained above 6. At high pH values, carbon dioxide corrosion damage is similar to oxygen corrosion damage, but at a slower rate. When carbon dioxide and oxygen are both present, however, the corrosion rate is higher than the sum of the rates for each alone. Carbon dioxide in drilling fluids may come from the makeup water, gas bearing formation fluid inflow, thermal decomposition of dissolved salts and organic drilling fluid additives, or bacterial action on organic material in the makeup water or drilling fluid additives. 3. Hydrogen Sulfide Hydrogen Sulfide dissolves in water to form an acid somewhat weaker and less corrosive than carbonic acid, although it may cause pitting, particularly in the presence of oxygen and/or carbon dioxide. A more significant action of hydrogen sulfide is its effect on a form of hydrogen embrittlement known as Sulfide Stress Cracking (See Part. III in this section for details). Hydrogen sulfide in drilling fluids may come from the makeup water, gasbearing formation fluid inflow, bacterial action on dissolved sulfates, or thermal degradation of sulfur-containing drilling fluid additives. 4. Dissolved Salts Dissolved Salts (chlorides, carbonates, and sulfates) increase the electrical conductivity of drilling fluids. Since most corrosion processes involve electrochemical reactions, the increased conductivity may result in higher corrosion rates. Concentrated salt solutions are usually less corrosive than diluted solutions, however, due to decreased oxygen solubility. Dissolved salts also may serve as a source of carbon dioxide or hydrogen sulfide in drilling fluids. Dissolved salts in drilling fluids may come from the makeup water, formation fluid inflow, drilled formation, or drilling fluid additives.

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5. Acids Acids corrode metals by lowering the pH (causing hydrogen evolution) and by dissolving protective films. Dissolved oxygen appreciably accelerates the corrosion rates of acids, and dissolved hydrogen sulfide greatly accelerates hydrogen embrittlement. Organic acids (formic, acetic, etc.) can be formed in drilling fluids by bacterial action or by thermal degradation of organic drilling fluid additives. Organic acids and mineral acids (hydrochloric, hydrofluoric, etc.) may be used during workover operations or stimulating treatments.

B. Factors Affecting Corrosion Rates. Among the many factors affecting corrosion rates of drill stem materials the more important are: 1. pH. This is a scale for measuring hydrogen ion concentration. The pH scale is logarithmic; i.e. each pH increment of 1.0 represents a ten-fold change in hydrogen ion concentration. The pH of pure water, free of dissolved gases, is 7.0. pH values less than 7 are increasingly acidic, and pH values greater than 7 are increasingly alkaline. In the presence of dissolved oxygen, the corrosion rate of steel in water is relatively constant between pH 4.5 and 9.5; but it increases rapidly at lower pH values, and decreases slowly at higher pH values. Aluminum alloys, however, may show increasing corrosion rates at pH values greater than 8.5. 2. Temperature. In general, corrosion rates increase with increasing temperature. 3. Velocity. In general, corrosion rates increase with higher rates of flow. 4. Heterogeneity. Localized variations in composition or microstructure may increase corrosion rates. "Ringworm" corrosion, that is sometimes found near the upset areas of drill pipe or tubing that has not been properly heat treated after upsetting, is an example of corrosion caused by nonuniform grain structure. 5. High Stresses. Highly stressed areas may corrode faster than areas of lower stress. The drill stem just above drill collars often shows abnormal corrosion damage, partially due to higher stresses and high bending moments.

C. Corrosion Damage (Forms of Corrosion). Corrosion can take many forms and may combine with other types of damage (erosion, wear, fatigue, etc.) to cause extremely severe damage or failure. Several forms of corrosion may occur at the same time, but one type will usually predominate. Knowing and identifying the forms of corrosion can be helpful in planning corrective action. The forms of corrosion most often encountered with drill string materials are: 1. Uniform or General Attack. During uniform attack, the material corrodes evenly, usually leaving a coating of corrosion products. The resulting loss in wall thickness can lead to failure from reduction of the material's load-carrying capability. 2. Localized Attack (Pitting). Corrosion may be localized in small, well defined areas, causing pits, Figure B5-1.

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Figure B5-1 Drill Pipe Washout from Pitting Corrosion - West Texas

Their number, depth, and size may vary considerably; and they may be obscured by corrosion products. Pitting is difficult to detect and evaluate, since it may occur under corrosion products, mill scale and other deposits, in crevices or other stagnant areas, in highly stressed areas, etc. Pits can cause washouts and can serve as points of origin for fatigue cracks. Chlorides, oxygen, carbon dioxide, and hydrogen sulfide, and especially combinations of them, are major contributors to pitting corrosion. 3. Erosion, Corrosion. Many metals resist corrosion by forming protective oxide films or tightly adherent deposits. If these films or deposits are removed or disturbed by high velocity fluid flow, abrasive suspended solids, excessive turbulence, cavitation, etc., accelerated attack occurs at the fresh metal surface. This combination of erosive wear and corrosion may cause pitting, extensive damage, and failure. 4. Fatigue in a Corrosive Environment (Corrosion Fatigue). Metals subjected to cyclic stresses of sufficient magnitude will develop fatigue cracks that may grow until complete failure occurs. The limiting cyclic stress that a metal can sustain for an infinite number of cycles is known as the fatigue limit, Figure B5-2.

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Figure B5-2 SN Curve of Steel in Air and Salt Water

In a corrosive environment no fatigue limit exists, since failure will ultimately occur from corrosion, even in the absence of cyclic stress. The cumulative effect of corrosion and cyclic stress (corrosion fatigue) is greater than the sum of the damage from each. Fatigue life will always be less in a corrosive environment, even under mildly corrosive conditions that show little or no visible evidence of corrosion.

D. Detecting and Monitoring Corrosion. The complex interactions between various corrosive agents and the many factors controlling corrosion rates make it difficult to accurately assess the potential corrosivity of a drilling fluid. Various instruments and devices such as pH meters, oxygen meters, corrosion meters, hydrogen probes, chemical test kits, test coupons (corrosion rings), etc. are available for field monitoring of corrosion agents and their effects. The monitoring systems described in API RP 13B: Standard Pipe Procedure for Testing Drilling Fluids, can be used to evaluate corrosive conditions. Preweighed test rings (corrosion ring coupons) can be placed in recesses at the back of tool joint box threads at selected locations throughout the drill stem, exposed to the drilling operation for a period of time, then removed, cleaned, and reweighed. The degree and severity of pitting observed, and the type of corrosion by-products, may be used to determine corrective action. The chemical testing of drilling fluids (See API RP 13B) should be performed in the field whenever possible, especially test for pH, alkalinity, and the dissolved gases (oxygen, carbon dioxide, and hydrogen sulfide).

E. Procurement of Samples of Laboratory Testing. When laboratory examinations of drilling fluid is desired, representative samples should be collected in a 1/2 to 1 gallon (2 to 4 liter) clean container, allowing an air space of approximately 1% of the container volume and sealing tightly with a suitable stopper. Chemically resisting glass, polyethylene, and hard rubber are suitable materials for most drilling fluid samples. Samples should be analyzed as soon as possible, and the elapsed time between collection and analysis reported. See ASTM (American Society for Testing Materials) D3370, Standard Practices for Sampling Water, for guidance on sampling and shipping procedures.

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When laboratory examination of corroded or failed drill stem material is required, use care in securing the specimens. If torch cutting is needed, do it in a way that will avoid physical or metallurgical changes in the area to be examined. Specimens must not be cleaned, wire brushed, or shot blasted in any manner; and should be wrapped and shipped in a way that will avoid damage to the corrosion products or fracture surfaces. Whenever possible, both fracture surfaces should be supplied.

F. Drill Pipe Coatings. Internally coating the drill pipe and attached tool joints can provide effective protection against corrosion in the pipe bore. In the presence of corrosive agents, however, the corrosion rate of the drill stem OD may be increased. Drill pipe coating is a shop operation in which the pipe is cleaned of all grease and scale, sand or grit blasted to white metal, plastic coated, and baked. After baking, the coating is examined for breaks or holidays.

G. Corrective Measures to Minimize Corrosion in Water-Base Drilling Fluids. The selection and control of appropriate corrective measures is usually performed by competent corrosion technologists and specialists. Generally, one or more of the following measures is used, but certain conditions may require more specialized treatments. 1. Control the drilling fluid pH. When practical to do so without upsetting other desired fluid properties, the maintenance of a pH of 9.5 or higher will minimize corrosion of steel in water-base systems containing dissolved oxygen. In some drilling fluids, however, corrosion of aluminum drill pipe increases at pH values higher than 8.5. 2. Use inhibitors and/or oxygen scavengers. The use of inhibitors and/or oxygen scavengers will minimize weight loss due to corrosion. This is particularly helpful with low pH, Low solids drilling fluids, inhibitors must be carefully selected and controlled, since different corrosive agents and different drilling fluid systems (particularly those used for air or mist drilling) require different types of inhibitors. The use of the wrong type of inhibitor, or the wrong amount, may actually increase corrosion. 3. Use plastic coated drill pipe. Care must be exercised to prevent damage to the coating. Note: Plastic coating does not prevent sulfide stress cracking. 4. Use degassers and desanders Use degassers and desanders to remove harmful dissolved gases and abrasive material. 5. Limit oxygen intake Limit oxygen intake by maintaining tight pump connections and by minimizing pit-jetting. Close the mud hopper throat valve when not mixing sack material. 6. Limit gas-cutting and formation fluid inflow Limit gas-cutting and formation fluid inflow by maintaining proper drill fluid weight. 7. Wash out all drilling fluid residues When the drill string is laid down, stored, or transported; wash out all drilling fluid residues with fresh water, clean out all corrosion products and coat all surfaces with a suitable corrosion preventive. While generally not affecting corrosion rates, the following measures will extend corrosion fatigue by lowering the cyclic stress intensity or by increasing the fatigue strength of the material:

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a. Use thicker walled components. b. Reduces high stresses near connections by minimizing doglegs and by maintaining straight hole conditions, insofar as possible. c. Minimize stress concentrators such as slip marks, tong marks, gouges, notches, scratches, etc.

III. Sulfide Stress Cracking "Sulfide Stress Cracking" a form of hydrogen embrittlement, is a frequent cause of drill stem failures. It is called Sulfide Stress Cracking, since both stress and hydrogen absorption in the presence of hydrogen sulfide are involved. This section will discuss its various aspects in more detail.

A. How Sulfide Stress Cracking Occurs. Atomic hydrogen (H), the smallest of atoms, is one of the products of most corrosion reactions. It can be absorbed by and diffused through steel and other metals. Normally, the hydrogen atoms quickly combine to form molecular hydrogen (H2) that is too large to be absorbed by the metal lattice, and it bubbles off as a gas. In the presence of sulfide, however, the hydrogen remains in the atomic form for a considerably longer time, and therefore has a greater probability of being absorbed. After being absorbed, the hydrogen tends to accumulate in the area of maximum stress and when a critical concentration is reached, a small crack forms. the hydrogen accumulates at the top of the crack and the crack grows. This process continues until the remaining metal cannot sustain the applied load, and sudden brittle failure occurs. The degree of this effect on a piece of steel due to this phenomena is determined by the concentration of hydrogen, the strength of the steel, applied stress on the steel and time of exposure. Therefore, tool joints are more frequently attached than other components of drill stem. Failures occur at the last engaged thread of the pin or at the base of the pin, or a longitudinal split in a worn box will occur. Failures in the threads of drill collars, subs, core barrels and at the run out of the upset in the body of drill pipe have been recorded. Failures are characteristically perpendicular to the principal stress with a flat brittle fracture, Figure B5-3. Figure B5-3 Brittle Fracture from Hydrogen Embrittlement

B. Mechanism of Sulfide Stress Cracking (SSC). In the presence of hydrogen sulfide (H2S), tensile-loaded static stresses, (not dynamic or cyclic as discussed earlier) drill stem components may suddenly fail in a brittle manner at a fraction of their nominal load-carrying capability after performing satisfactorily for extended periods of time. Failure may occur even in the apparent absence of corrosion, but is more likely if active corrosion exists. Embrittlement of the steel is caused by the absorption and diffusion of atomic hydrogen and is much more severe when H2S is present. The brittle failure of tensile-loaded steel in the presence of H2S is termed sulfide stress cracking (SSC).

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C. Materials Resistant to SSC. The latest revision of NACE (National Association of Corrosion Engineers) Standard MR-0175-90 "Sulfide Stress Cracking Resistant Metallic Material for Oil Field Equipment", should be consulted for materials that have been found to be satisfactory for drilling and well servicing operations. Other chemical compositions, hardness, and heat treatments should not be used in sour environments without fully evaluating their SSC susceptibility in the environment in which they will be used. Susceptibility to SSC depends upon: 1. Strength of the Steel. The higher the strength (hardness) of the steel, the greater is the susceptibility to SSC. In general, steels having strengths equivalent to hardness up to 22 HRC maximum are resistant to SSC. If the chemical composition is adjusted to permit the development of a well tempered, predominantly martensitic microstructure by proper quenching and tempering; steels having strengths equivalent to hardness up to 26 HRC maximum are resistant to SSC. When strengths higher than the equivalent of 26 HRC are required, corrective measures (as shown in a later section) must be used; and, the higher strength required, the greater the necessity for the corrective measures. 2. Total Tensile Load (Stress) on the Steel. The higher the total tensile load on the component, the greater is the possibility of failure by SSC. For each strength of steel used, there appears to be a critical or threshold stress below which SSC will not occur; however, the higher the strength, the lower the threshold stress. 3. Amount of Atomic Hydrogen and H2S. The higher the amount of atomic hydrogen and H2S present in the environment, the shorter the time before failure. The amounts of atomic hydrogen and H2S required to cause SSC are quite small, but corrective measures to control their amounts will minimize the atomic hydrogen absorbed by the steel. 4. Time. Time is required for atomic hydrogen to be absorbed and diffused in steel to the critical concentration required for crack initiation and propagation to failure. By controlling the factors referred to above, "time to failure" may be sufficiently lengthened to permit the use of marginally susceptible steels for short duration drilling operations. 5. Temperature. The severity of SSC is greatest at normal atmospheric temperatures, and decreases as temperature increases. At operating temperatures in excess of approximately 135°F (57°C), marginally susceptible materials (those having hardnesses higher than 22 to 26 HRC) have been used successfully in potentially embrittling environments. The higher the hardness of the material, the higher the required safe operating temperature. Caution must be exercised, however, since SSC failure may occur when the material returns to normal temperature after it is removed from the hole.

D. Corrective Measures to Minimize SSC in WaterBase Drilling Fluids. The selection and control of appropriate corrective measures is usually performed by a competent corrosion technologists and specialists. Generally, one or more of the following measures is used, but certain conditions may require more specialized treatments. 1. Control the drill fluid pH. When practical to do so without upsetting other desired fluid properties, maintain a pH of 10 or higher.

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Note: In some drilling fluids, aluminum alloys show slowly increasing corrosion rates at pH values higher than 8.5; and the rate may become excessive at pH values higher than 10.5. Therefore, in drill strings containing aluminum drill pipe, the pH should not exceed 10.5. 2. Limit gas-cutting and formation fluid inflow Limit gas-cutting and formation fluid inflow by maintaining proper drilling fluid weight. 3. Minimize corrosion Minimize corrosion by the corrective measures shown in Section B5, Part II, paragraph G. Note: While use of plastic coated drill pipe can minimize corrosion, plastic coating does not protect susceptible drill pipe from SSC. 4. Chemically treat for hydrogen sulfide inflows Chemically treat for hydrogen sulfide inflows, preferably prior to encountering the sulfide. 5. Use the lowest strength drill pipe to satisfy conditions Use the lowest strength drill pipe capable of withstanding the required drilling conditions. At any strength level, properly quenched and tempered drill pipe will provide the best SSC resistance. 6. Reduce unit stresses Reduce unit stresses by using thicker walled components. 7. Reduce high stresses at connections Reduce high stresses at connections by maintaining straight hole conditions, insofar as possible. 8. Minimize stress concentrators Minimize stress concentrators such as slip marks, tong marks, gouges, notches, scratches, etc. 9. Use care in tripping out of the hole After exposure to a sour environment, use care in tripping out of the hole, avoiding sudden shocks and high loads. 10. Remove absorbed hydrogen by aging in open air After exposure to a sour environment, remove absorbed hydrogen by aging in open air for several days to several weeks (depending upon conditions of exposure) or bake at 400° to 600°F (204° to 316°C) for several hours. Note: Plastic coated drill pipe should not be heated above 400°F (204°C) and should be checked subsequently for holidays and disbonding. The removal of hydrogen is hindered by the presence of corrosion products, scale, grease, oil, etc. Cracks that have formed (internally or externally) prior to removing the hydrogen will not be repaired by the baking or stress relief operations. 11. Limit drill stem testing in sour environments Limit drill stem testing in sour environments to as brief a period as possible, using operating procedures that Will minimize exposure to SSC conditions.

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IV. Drilling Fluids Containing Oil A. Use of Oil Muds for Drill Stem Protection. Corrosion and SSC can be minimized by the use of drilling fluids having oil as the continuous phase. Corrosion does not occur if metal is completely enveloped and wet by an oil environment that is electrically nonconductive. Oil systems used for drilling (oil-base or invert emulsion muds) contain surfactants that stabilize water as emulsified droplets and cause preferential oil-wetting of the metal. Agents that cause corrosion in water (dissolved gases, dissolved salts, and acids) do not damage the oil-wet metal. Therefore, under drilling conditions that cause serious problems of corrosion damage, erosion-corrosion, or corrosion fatigue, drill stem life can be greatly extended by using an oil mud.

B. Monitoring Oil Muds for Drill Stem Protection. An oil mud must be properly prepared and maintained to protect drill stem from corrosion and SSC. Water will always be present in an oil mud, whether added intentionally, incorporated as a contaminant in the surface system, or from exposed drill formations. Corrosion and SSC may occur if this water is allowed to become free and to wet the drill stem. Factors to be evaluated in monitoring an oil mud include: 1. Electrical Stability. This test measures the voltage required to cause current to flow between electrodes immersed in the oil mud (see API RP 13B for details). The higher the voltage, the greater the stability of the emulsion, and the better the protection provided to the drill stem. 2. Alkalinity. The acidic dissolved gases (carbon dioxide and hydrogen sulfide) are harmful contaminates for most oil muds. Monitoring the alkalinity of an oil mud can indicate when acidic gases are being encountered so that corrective treatment can be instituted. 3. Corrosion Test Rings. Test rings placed in the drill stem bore are used to monitor the corrosion protection afforded by oil muds (See API RP 13B for details). A properly functioning oil mud should show little or no visual evidence of corrosion on the test ring.

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B6. Drill String Inspection And Classification I. Purpose Drill pipe failures quite frequently add to the cost of drilling. These cause costly fishing jobs, loss of material, lost time and occasionally abandoning all or portions of the hole. The threat of this potential loss requires constant attention by the drilling crews to the conditions of the drill string. Also many operators, using contractors pipe, require inspection and classification of the pipe prior to accepting a contract for drilling their well. Thus, the purpose of the inspection of used drill pipe is to determine if its usable for the job. Suitability for the job involves whether the pipe is strong enough and free from internal and external defects which may cause failure. On these bases, the Drilling Technology Committee of the IADC devised a method of classifying drill string and this is now a recommended practice of the API. Much of the information contained in this section is extracted from American Petroleum Institute (API) Recommended Practice (RP) 7G, Section 10, Fourteenth Edition, dated August 1, 1990.

II. Drill String Marking and Identification It is recommended that data regarding the pipe, as shown in Fig. B1-3 be stencilled at the base of the pin by the tool joint manufacturer for identification of drill string components. Figure B1-3a Tool Joint Markings for Component Identification Figure B1-3b Pipe Mills & Pipe Processors Figure B1-3c Identification of Standard Weight High Strength Drill Pipe Figure B1-3d Identification of Heavy Weight Grade E-75 Drill Pipe Figure B1-3e Identification of Heavy Weight High Strength Drill Pipe Figure B1-3f Identification of Tool Joint Manufacturers Registered Trademarks It is also recommended that drill string other than standard weight Grade E-75, be marked using the mill slot and groove method for identifying grade and weight of drill pipe as shown in Figure B1-4. Figure B1-4 RP for Mill Slot and Groove Drill Pipe Identification In the latter method, the pipe grade and weight code symbols are stamped in the mill slot of specified dimensions and specified location on the tool joint.

III. Drill Pipe And Tubing Work Strings A. Inspection Standards. Through efforts of joint committees of API and IADC, inspection standards for the classification of used drill pipe have been established. The procedure outlined in Table B6-1A was adopted as a tentative API specification at the 1964 Standardization Conference and was revised and approved as standard at the 1968 Standardization Conference.

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Table B6-1A Classification of Used Drill Pipe

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Notes on Table B6-1A 1. The premium classification is recommended for service where it is anticipated that torisional or tensile limits for Class 2 drill pipe and tubing work strings will be exceeded. These limits for Premium Class and Class 2 drill pipe are specified in Tables B2-2 and B2-3 respectively. Premium Class shall be identified with two white bands, plus one center punch mark on the 35° sloping shoulder of the tool joint pin (or the 18 sloping shoulder of the pm, if the 18 angle is furnished.) 2. Inspection of this condition should be made to detect presence of longitudinal and transverse cracks inside and outside. 3. Remaining wall shall not be less than the value in I.E.2, defects may be ground out providing the remaining wall is not reduced below the value shown in I.E.1 of this table and such grinding to be approximately faired into outer contour of the pipe. 4. In any classification where cracks or washouts appear, the pipe will be identified with the red band and considered unfit for further drilling service. 5. An API RP 7G inspection cannot be made with drill pipe rubbers on the pipe. 6. Average adjacent wall is determined by measuring the wall thickness on each side of the cut or gouge adjacent to the deepest penetration. Additional revisions were made at the 1970 Standardization Conference to add Premium Class. At the 1971 Conference it was determined that the drill pipe classification procedure be removed from an appendix to API Spec 7 and placed in API RP 7G as a recommended practice. At the 1979 API Standardization Conference, these guidelines were revised to also cover classification of used tubing work strings. See Table B6-1B.

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Table B6-1B Classification of Used Tubing Work Strings

Notes on Table B6-1B

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The guidelines established in this Recommended Practice have been in use for several years. Use of the practice and classification guide have apparently been successful when applied in general application. There may be situations where additional inspections are required and/or more specific engineering design is required to accommodate higher stress or a more corrosive environment.

B. Limitations of Inspection Capability. Most failures of drill pipe result from some form of metal fatigue. A failure is one which originates as a result of repeated or fluctuating stresses having maximum values less than the tensile strength of the material. Fatigue fractures are progressive, beginning as minute cracks that grow under the action of the fluctuating stress. The rate of propagation is related to the applied cyclic load and under certain conditions may be extremely rapid. The failure does not normally exhibit extensive plastic deformation and is therefore difficult to detect until such time as considerable damage has occurred. There is no accepted means of inspecting to determine the amount of accumulated fatigue damage or the remaining life of the pipe at a given stress level. Presently accepted means of inspection are limited to location of cracks, pits, and other surface marks; measurement of remaining wall thickness; measurement of outside diameter; and calculation of remaining cross sectional area. Recent industry statistics confirm that a major percentage o f tube body in-service failures occur near the upset runout or within the slip area. Special attention to these critical failure areas may be required during inspection to facilitate crack detection in some drill strings. Drill pipe which has just been inspected and found free of cracks may develop cracks after very short additional service through the addition of damage to previously accumulated fatigue damage.

C. Definition of a Crack. A crack is a single line rupture of the pipe surface. The rupture shall (1) be of sufficient length to be shown by magnetic iron particles used in magnetic particle inspection or (2) be identifiable by visual inspection of the outside of the tube and/or by optical/ultrasonic shear-wave inspection of the inside of the tube.

D. Measurement of Pipe Wall. Tube body conditions will be classified on the basis of the lowest wall thickness measurement obtained and the remaining wall requirements contained in Table B6-1A for drill pipe and Table B6-1B for tubing. The only acceptable wall thickness measurements are those made with pipe-wall micrometers, ultrasonic instruments, or gamma-ray devices that the operator can demonstrate to be within 2 per cent accuracy by use of test blocks sized to approximate pipe wall thickness. When using a highly sensitive ultrasonic instrument, care must be taken to ensure that detection of an inclusion or lamination is not interpreted as a wall thickness measurement.

E. Determination of Cross Section Area (Optional). Determine cross sectional area by use of a direct indicating instrument that the operator can demonstrate to be within 2 percent accuracy by use of a pipe section approximately the same as the pipe being inspected. In the absence of such an instrument, integrate wall thickness measurements taken at 1 inch intervals around the tube.

F. Procedure. Used drill pipe should be classified according to the procedure of Table B6-1A and as illustrated in Figure B6-1 dimension A.

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Figure B6-1 Identification of Lengths Covered by Inspection Standards

Maximum allowable hook loads for New, Premium and Class 2 drill pipe are listed in Table B6-2.

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Table B6-2 Hook Load at Min. Yield for New, Premium, and Class. 2 Drill Pipe

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Values recommended for minimum OD and make-up torque of weld-on tool joints used with the New, Premium and Class 2 drill pipe are listed in Table B1-7. Maximum allowable hook loads for New, Premium and Class 2 tubing work strings (also classified in accordance with Table B6-1B) are listed in Table B6-3. Figure B6-3 Hook Load at Min. Yield for New, Premium, and Class. 2 Tubing

G. Inspection Classification Marking. A permanent mark or marks signifying the classification of the pipe (for example, refer to Table B6-1A, Note 1) should be stamped: a. On the 35 degree sloping shoulder of the tool joint pin (or on the 18 degree sloping shoulder of the pin, if the 18 degree angle is furnished). b. On the end of the tool joint pin on flush OD drill pipe. c. Or in some other low-stressed section of the tool joint where the marking will normally carry through operations. d. Cold steel stenciling should be avoided on outer surface of drill pipe tubes.

IV. Tool Joints A. Color Coding. The classification system for used drill pipe outlined in Table B6-1A includes a color code designation to identify the drill pipe class. The same system is recommended for tool joint class identification. In addition, it is recommended that the tool joint be identified as (1) field repairable, or (2) scrap or shop repairable. The color code system for tool joints and for drill pipe is shown in Figure B6-2.

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Figure B6-2 DP and TJ Color Code Identification

B. Required Tool Joint Inspection 1. Outside Diameter Measurement. Measure tool joint outside diameter at a distance of 1 inch from the shoulder and determine classification from data in Table B1-7. Minimum shoulder width should be used when tool joints are worn eccentrically. 2. Shoulder Conditions. Check shoulders for galls, nicks, washes, fins, or any other matter which would affect the pressure holding capacity of the joint and conditions which may affect joint stability.

C. Optional Tool Joint Inspection 1. Shoulder Width. Using data in Table B1-7 determine minimum shoulder width acceptable for tool joint in class as governed by the outside diameter. 2. Thread Profile. Careful inspection will pick up indication of overtorque, insufficient torque, lapped threads, galled threads, and stretching. A lead gage of the type illustrated in Figure B3-26 should be employed to determine the amount of stretch.

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Figure B6-3 Tong Space and Bench Mark Position

3. Box Swell and/or Pin Stretch. These are indications of over-torquing and their presence greatly affects the future performance of the tool joint. On used tool joints, it is recommended that pins having stretch which exceeds .006 inch in 2 inches should be recut. All pins which have been stretched should be inspected for cracks. It is recommended that used boxes having more than .031 inch (1/32nd inch) measurable swell be recut. It is recommended that the box counterbores (Qc), API Spec 7, Table 9.1, be checked. If the Qc diameter is more than 0.031 inch (1/32 inch) outside the allowed tolerance, then the box should be recut. 4. Minimum Tong Space. Refer to Figure B6-3. The recommended minimum tong space for pins is 75% of the OD but not less than 4 inches. The recommended minimum tong space for non-hardfaced boxes is the measured Lbc + 1 inch. On hardhanded joints, the space may need to be longer to provide adequate gripping space for tongs. 5. Magnetic Particle Inspection a. If evidence of pin stretching is found, magnetic particle inspection should be made of the entire pin threaded area, especially the last engaged thread area, to determine if transverse cracks are present. b. Longitudinal or irregular orientation of cracking may occur as a result of friction heat checking or abnormal box swell. In that case magnetic particle inspection of both box and pin tool joint OD surfaces should be performed, with an emphasis on detection of longitudinal cracks. c. In highly stressed drilling environments or if evidence of fatigue damage is noted, magnetic particle inspection should be made of the entire box threaded area, especially the last engaged thread area, to determine if transverse cracks are present. d. The wet fluorescent magnetic particle method is preferred.

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D. General 1. Gauging. Thread wear, plastic deformation, mechanical damage and lack of cleanliness may contribute to erroneous figures when plug and ring gages are applied to used connections. Therefore, ring and plug standoffs should not be used to determine rejection or continued use of rotary shouldered connections. Sealing shoulders are more critical to joint operation than gage standoff. 2. Repair of Damaged Shoulders a. When refacing a damaged tool joint shoulder, a minimum of material should be removed. It is good practice not to remove more than 1/32 inch from a box or pin shoulder at any one refacing and not more than 1/16 inch cumulatively. b. It is suggested that a bench mark be provided for the determination of the amount of material which may be removed from the tool joint shoulder. This bench mark should be stencilled on a new or recut tool joint after facing to gage. The form of the bench mark should be a 3/16 inch diameter circle with a bar tangent to the circle parallel to the shoulder. The distance from the shoulder to the bar should be 1/8 inch. The positioning of the bench mark in the box counterbore and on the base of the pin is shown in Figure B6-3. Figure B6-3 Tong Space and Bench Mark Position Figure B6-1, dimension A, indicates the length covered under the drill pipe classification system recommend in Par. III-F. Figure B6-1 Identification of Lengths Covered by Inspection Standards Figure B6-1, dimension B, indicates the length covered under the tool joint inspection standard in Par. IV-B. The length not covered by inspection standards is indicated under a caution heading by dimension C, Fig. B6-1. Figure B6-1 Identification of Lengths Covered by Inspection Standards

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B7. Aluminum Drill String Introduction Drill string with aluminum drill pipe may be used where its physical characteristics, less weight and greater flexibility, can be an advantage. These areas are: 1. Extended Reach Drilling 2. Horizontal Drilling 3. Directional Drilling 4. Helicopter Rig Drilling 5. Deep Drilling with Small Rigs

I. Tool Joints Tool Joints for aluminum drill pipe are made from steel which meets API requirements. The tool joint to pipe connection is a shrunk on heavy interference fit based on the Super Shrink Grip. This design seals on the outer land, the threads, and on the end of the tube. On aluminum pipe, this shrunk on design is now referred to as Alstan. The normal Alstan OD matches the comparable API tool joint used on standard weight steel E-75, while the tool joint bore matches the bore of the aluminum tube. The usual working connection on each nominal size aluminum pipe is: Pipe

Tool Joint

TJ OD x ID

3-1/2"

NC38

4-3/4" x 2-21/32"

4"

NC46

6" x 3-1/4"

4-1/2"

NC50

6 -3/8" x 3-19/32"

5"

5-1/2" FH

7" x 4-3/32"

II. Installation and Removal of Tool Joints The installation of the shrunk on Alstan tool joints on new or used aluminum drill pipe requires special tools, gauges, and a knowledge of the correct procedures. Each drill string assembly is pressure tested after tool joint installation. Worn Alstans can be removed from pipe; the pipe may be re-used but the Alstans are destroyed. It is possible to salvage an Alstan but this ruins the pipe for further use. If tool joint wear is expected to limit drill string life, then hardfacing for boxes (and pins) should be considered. Alstans cannot be hardfaced safely after they are installed on aluminum drill pipe. The heat of welding will erase the hoop stress which secures the tool joint to the pipe. Longer than standard tong lengths for boxes and pins should be considered if your plan is to hardface both tool joint members.

III. Aluminum Drill Pipe Physical characteristics of the aluminum ahoy 2014-T6 presently in use are: Minimum Yield Strength

58 000 PSI

Minimum Ultimate Strength

64 000 PSI

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Minimum Elongation in 2"

7%

Brinell Hardness

135

Modulus of Elasticity

10.6 x 106

Specific Gravity

2.7984

Weight

23.33 lbs/gal, or 0.101 lb/cu in Figure B7-1 Aluminum Drill Pipe Dimensions

Table B7-P1 Physical Properties of Aluminium Drill Pipe

MAXIMUM TENSILE LOAD (POUNDS) New and Used Aluminum Drill Pipe Nominal Pipe

Premium Class

Class 2

New (80% Nom. Wall) (70% Nom. Wall)

3-1/2"

297 660

230 490

198 300

4"

313 490

244 640

211 350

4-1/2"

373 520

291 570

251 890

5"

442 420

345 910

299 160

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MAXIMUM

TORSIONAL LOAD (ft-lbs)

3-1/2"

20 160

15 360

13 130

4"

25 480

19 690

16 930

4-1/2"

33 310

25 740

22 150

5"

44 750

34 690

29 890

IV. Drill String Care and Handling Experience has shown that all drill string gives better service when recommended care and handling procedures are followed. This surely applies to drill string with aluminum drill pipe.

A. Hardness The typical Brinell hardness of aluminum drill pipe is 135 while grade E-75 steel is approximately 200 BHN. Careless handling can mark both tubes. Aluminum is more easily marked because it is softer. 1. Drill String with aluminum drill pipe should be transported on a float bed truck with not less than three supporting spacers on each layer. 2. Loading and unloading drill string should be controlled and quiet. Loud noises frequently indicate mishandling and subsequent damage. Aluminum is more easily damaged than steel but these guidelines apply to both. 3. Avoid hooks in handling all drill string. Choker slings with not less than 10' separation on a strong back or spacer bar are recommended. 4. Aluminum drill pipe is likely to show more wear and/or erosion when drilling formations that are hard and abrasive. The nicks and gouges that appear in aluminum pipe rarely lead to fatigue problems unless the marks are very deep.

B. Tongs Two tongs should be used to make and break connections on all drill string, both aluminum and steel.

C. Slips Most aluminum drill pipe has a long tapered external upset zone immediately below the tool joint box. This is to minimize failures caused by slip damage by fatigue. This requires slips with the same taper as the pipe in use (standard straight slips on this tapered portion are likely to create deep slip marks and stress concentrations). At times it may be necessary to set slips on the cylindrical body (middle portion of the tube). Straight slips should be used. The use of tapered slips on the straight body are likely to create deep slip marks and stress concentrations. The damage that results from improper slips depends on the weight suspended below the slips and the speed with which that load is set on the slips. Slip dies for aluminum pipe are modified for minimum penetration and maximum power. Slips should never be used to stop the downward motion of drill string, whether the pipe is aluminum or steel. Using slips for brakes will subject the pipe to abnormal loading and may cause crushing or other damage in the slip area. Slips should be set so connections for makeup or breakout are close to the rotary table. This is to minimize pipe bending during these operations. Formulas for calculating maximum box height above the table are shown in API RP7G. If the conditions on your job differ from those shown, do calculate heights carefully so you do not put end kinks in your drill string. ALWAYS USE TWO TONGS ON MAKEUP OR BREAKOUT !!!

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D. Blowout Preventers The OD of external upset aluminum drill pipe is slightly larger than steel pipe of the same nominal size. If rams for steel pipe are used on aluminum, the aluminum pipe is likely to be damaged severely.

E. Elevators Tool joints on aluminum drill pipe have 18 degree shoulders on both boxes and pins. The weld neck diameters (DTE or DPE from API Spec 7, Table 4.2) are: Nominal Pipe

DTE DPE

OD and Upset

Max. Dia.

3-1/2 EU

3.875

4 EU

4.625

4-1/2 EU

5.031

5 EU

5.688

You must use elevators with cylindrical "bores which will clear these DTE DPE diameters.

V. Drill String Maintenance A. Coating It is recommended that drill string with aluminum drill pipe be plastic coated internally when new and that this be replaced as necessary during the string life. Plastic coating improves hydraulics and reduces the erosive or corrosive effects of drilling fluids.

B. Worn Rotary Tables and Bushings Rotary tables, bushings, slip segments must be maintained according to original specifications. See Section B3, XII-B, for check of worn elements.

C. Straightening Aluminum Drill Pipe Slightly bowed pipe tends to straighten under the stretching effect of the drill collar load in a normal drilling operation. End-to-end bow appears to be the major deformation of importance. This can occur with: 1. Abnormal temperature changes when on the rack. 2. Transport without adequate spacers under the tie-downs. 3. Running drill string in compression with high RPM and high torque and without rubber protectors. (This may also abrade metal from the crest of the bow).

VI. Drill String Operating Limits A. Elasticity The modulus of elasticity of aluminum is 10.6 x 106 compared with 29 x 106 for steel. Aluminum has much greater flexibility and requires about twice as many turns to reach the same torque level.

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The effects on operations include: 1. The limberness or flexibility of aluminum drill pipe cause the drill string to behave differently during handling on the rig. It will help if several joints of aluminum are picked up at the same time; remember to use double choker slings separated about 10' on a strong back or spacer bar. 2. The stretch of aluminum is greater in air or in muds lighter than 12 pounds per gallon (ppg). When the mud weighs more than 12 ppg, the stretch of aluminum is less than steel. Calculate the stretch of aluminum carefully when pulling stuck drill string, setting a liner, or when steel pipe is below aluminum. You must also calculate carefully to determine the additional turns necessary to achieve the equivalent torque in these and other operations. 3. On the positive side, the flexibility of aluminum drill pipe gives it excellent fatigue resistance. Experience has shown that fatigue life generally exceeds wear life. Thus, aluminum drill pipe can be most useful when operating in crooked hole country, when drilling extended reach wells or horizontal completions, or in all cases where pipe is subjected to severe bending during rotation. Short radius bends and rapid bends seldom occur because of the resiliency of aluminum. When bends and bows which require straightening do occur, please consider cross roller straightening. If gag press must be used, try to usc many straightening force positions in lieu of one position in the middle of the bow. At present, spin straightening is not acceptable for aluminum drill pipe.

B. Mixed Strings of Aluminum and Steel To extend the capacity of rigs or reduce tensile and or torsional loads, mixed strings of aluminum and steel may be used. The main recommendation is that the aluminum comprise not less than 5% of the total and this minimum amount should be added at one time. (This is to prevent abnormal axial loading due to operational string vibrations from being concentrated in the aluminum). Aluminum may be run in the top of the string but care should be taken to keep loading within recommended limits.

C. Stuck Drill Pipe and Fishing The general procedures in fishing for stuck aluminum drill pipe are similar to those for steel with these exceptions: 1. Electro-mechanical free point indicators are necessary because of aluminum's non-magnetic quality. 2. The OD of external upset aluminum drill pipe is larger than the equivalent size steel pipe; this, plus the long taper on each end means that overshot assemblies must be selected to fit over the fish. Standard overshots with a 3 or 4 foot extension or a joint long enough to reach over the next tool joint are normally satisfactory. 3. The spring back energy of aluminum pipe is greater than steel. On a heavy pull, safety precautions should be exercised to prevent injury to personnel. 4. If circulation is lost, or if fish is without circulation when temperatures are above 300 degrees F, high torsional and/or tensile load should be avoided until pipe temperatures can be reduced. 5. The consistent lengths of aluminum drill pipe offer greater accuracy when using free point indicators, placing backoff shots or other instruments, checking pipe tallies and determining if pipe has been stretched. 6. Care should be taken that tensile yield is not exceeded. Measure mid-length pipe diameters frequently so the person in charge knows the load his pipe can safely carry. Refer to Table B7-P4

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Table B7-P4 Tension & Torque Tables for Aluminium Drill Pipe

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B-8 Glossary Of Drill String Terms AMBIENT TEMPERATURE - The temperature of the surroundings. ATOMIC HYDROGEN - A single atom of the gaseous element hydrogen. AUSTENITE - A solid solution formed when carbon and certain alloying elements dissolve in gamma iron. Gamma iron is formed when steel is heated above a critical temperature and the ferrite (alpha iron with a body-centered crystal structure) is transformed to a face-centered crystal structure. BAUSCHINGER EFFECT - The phenomena by which steel overstressed in tension has a reduced compressive yield strength or overstressed in compression has a reduced tension yield strength. Named for the discoverer of the phenomena. BELLED BOX - A tool joint box which has been subjected to a torque which has resulted in permanent enlargement of the box diameter. This normally occurs adjacent to the box sealing shoulder. BOLSTERS - A horizontal rail or sill of wood on which pipe is laid. BORESCOPE - An optical arrangement of lenses and light to permit inspection of inside surfaces, i.e. inside of pipe. BRINELL HARDNESS - A method of testing the hardness of metal by pressing a hardened steel ball into the metal to be tested using a standard load. The standard test uses a 10 mm ball with a 3,000 kg load. The Brinell hardness number is the quotient of the applied load and the surface area of the indentation. BRITTLE FAILURE - A failure in which there is no evidence of ductility or deformation. Characterized by an irregular cleavage fracture with shiny crystalline appearance. CARBON STEEL - Steel which owes its properties chiefly to various percentages of carbon without substantial amounts of other alloying elements. CASE HARDENING - A process of hardening a ferrous alloy that the surface layer, or case, is made substantially harder than the interior or core. Typical processes are carburizing and quenching, cyaniding, nitriding, induction hardening and flame hardening. COEFFICIENT OF FRICTION - The ratio of the force required to move one surface over the other to the total force pressing the two surfaces together. COLD-WORK - Plastic deformation of metal at a temperature low enough to insure or cause permanent strain. COMPRESSIVE YIELD STRENGTH - The maximum stress a metal, subjected to compression, can withstand without a predefined amount of permanent deformation. CORROSION - A chemical or electrochemical attack on metal by the atmosphere, moisture, or other agents. CRACK - A stress induced separation of the metal which without influences is insufficient in extent to cause complete rupture of the material. CRYSTALLIZATION - The formation of crystals by the atoms assuming definite positions in a crystal lattice. This occurs as a molten metal solidifies. DENT - A small depression made by striking or pressing. DING - Colloquial expression used in tubular industry to describe a dent. DUCTILITY - The property that permits permanent deformation before fracture.

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ELASTIC DEFORMATION - Temporary changes in dimensions caused by stress. The material returns to the original dimensions after removal of the stress. ELASTIC LIMIT - The maximum stress which a material is capable of sustaining without any measurable change of dimension after complete release of the stress. ELECTROLYTE - A solution which conducts an electric current. ENDURANCE - The ability of material to withstand repeated reversals of stress. ENDURANCE LIMIT - The maximum stress that a metal will withstand without failure during a specified large number of cycles of stress. The cycles of stress are usually such as to produce complete reversals of flexural stress. FATIGUE - The tendency for a metal to fail under conditions of repeated cyclic stressing considerably below the ultimate tensile strength. FATIGUE CRACK OR FAILURE - A fracture starting from a nucleus where there is an abnormal concentration of cyclic stress and propagating through the metal. Fracture surface is smooth and frequently shows concentric (sea shell or half moon) markings with a nucleus as a center. FATIGUE LIMIT - The maximum stress that a metal will withstand without failure for a specified large number of cycles of stress. Usually synomous with endurance limit. GALLING - The result of the freezing of two mating surfaces of steel, not protected by a film of lubricant, and tearing due to lateral displacement. Can also be caused by mechanical damage of one surface. GALVANIC CELL - The "battery" effected by two areas of different potential connected by an electrolyte. HARDNESS - (1) The temper of a wrought product. HARDNESS - (2) Resistance to indentation. HARDNESS - (3) Resistance to abrasion. HEAT-AFFECTED ZONE - That portion of the base metal which was not melted during brazing, cuffing or welding, but whose microstructure and physical properties were altered by the heat. HEAT CHECKS - A network of shallow cracklike ruptures which result from repeated surface friction heating and rapid quenching. HEAVY WEIGHT DRILL PIPE - Drill pipe fabricated with thick wall tube. Frequently used in place of drill collars to apply weight on the drill bit in small diameter holes. Handles like normal drill string in drilling operations. Used in the transition zone between the stiffer drill collars and limber drill pipe. INCLUSIONS - Particles of non-metallic impurities usually oxides, sulfides, silicates, and such which are trapped in steel during solidification. INTERGRANULAR - Between the grains of steel. ION - An atom or a combination of atoms in solution carrying either a positive or negative electric charge. JOINTER - Two short pieces of pipe coupled to make a standard length. MAGNETIC FLUX - The number of magnetic lines of force passing through a magnetic circuit or field. MAGNETIC TESTING - A method of testing for defects which is carried out by magnetizing the steel and sprinkling a magnetic powder on the surface to detect flaws or defects. MAGNETIC PERMEABILITY - The ratio of the magnetic induction to the intensity of the magnetizing field.

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MARTENSITE - A microconstituent or structure in a quenched steel charterized by an acicular or needle-like pattern on the surface of the polish. It is the first and hardest of the decomposition products of austenite. MECHANICAL PROPERTIES - Those properties of a material that reveal the elastic and inelastic reaction when force is applied, or that involve the relationship between stress and strain; for example, modulus of elasticity, tensile strength, and fatigue limit. Also called physical properties. MICROSTRUCTURE

The arrangement of the constituents of steel as viewed through a microscope.

NECKING DOWN - The narrowing, or constricting to a small cross sectional area, which occurs at a localized place under a tension load. pH - A measure of the amount of hydrogen ions in a water-containing environment. The lower the pH, the greater the number of hydrogen ions present, and the more acidic the environment. PLASTIC DEFORMATION - Permanent distortion of a material under the action of applied stress. POTENTIAL, ELECTRIC - The charge on a body as compared to another charged body or a standard such as the earth with zero potential. Sometimes called IR drop and measured in electrostatic units or in volts. PROPORTIONAL LIMIT - The greatest stress a material is capable of sustaining without a deviation from the law of proportionality of stress and strain. If the load is removed for any stress up to this point the material will assume its original dimension. QUENCH CRACK - A fracture resulting from thermal stresses induced during rapid cooling or quenching. ROCKWELL HARDNESS - The Rockwell hardness test measures the depth of residual penetration by a steel ball (Rockwell B) or a diamond cone (Rockwell C) upon the surface of the material to be tested by a minor load, dial is zeroed, and the major load applied. The reading on the scale after major load is released measures the residual penetration. SCALE - An oxide of iron which forms on the surface of hot steel. SEAM - On the surface of metal a discontinuity that has been closed but not welded. SLIP PLANE - The crystallographic plane in which slip occurs within a crystal. S-N CURVE - Curves that are obtained by plotting the number of cycles (N) against the load per square inch (S) applied to the test specimen. STRESS - The load per unit of area. STRETCHED PIN - A tool joint pin which has been subjected to loading which has caused permanent lengthening of the threaded length of the pin. This condition generally results from excessive torque rather than tensile loads. SULFIDE STRESS CRACKING (SSC) - The brittle failure of metals by cracking under the combined action of tensile stress and corrosion in the presence of water and hydrogen sulfide. TEMPILSTIK - A crayon composed of waxes with controlled melting points. TENSILE STRENGTH - The value obtained by devising the maximum load observed during tensile straining until breaking occurs, by the specimen cross-sectional area before straining. Also called ultimate strength. TOOL JOINT NOMENCLATURE TORQUE - Force applied in a radial direction tending to rotate material around its longitudinal axis. Measured in foot-pounds with the length of the lever arm in feet and force in pounds. TORSION - Strain created in a material by a twisting action. Correspondingly, the stress within the material resisting the twisting.

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TORSIONAL STRENGTH - The torque or twisting force required to produce permanent dimensional change or fracture. ULTIMATE STRENGTH - The maximum stress a metal can withstand without fracture. ULTRASONIC - The use of high frequency sound waves to probe for thickness or the presence of defects. WORK HARDENING - Hardness developed in metals as a result of cold-working. YIELD POINT - In medium carbon steels, the stress at which a marked increase in deformation occurs without an increase in the load. Also the point where permanent set OCCURS. YIELD STRENGTH - The stress at which a material exhibits a specified limiting deviation from proportionality of stress to strain.

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Chapter C Casing and Tubing

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Table of Contents - Chapter C Casing and Tubing I. Care And Use Of Casing ....................................................................................................................... C-4 Introduction ........................................................................................................................................ C-4 I. Transportation ................................................................................................................................. C-4 II. Preparation And Inspection Before Running .................................................................................... C-4 III. Rig Equipment .............................................................................................................................. C-4 IV. Pre-running Preparations ............................................................................................................... C-5 V. Running Casing ............................................................................................................................... C-6 VI. Causes Of Casing Troubles ......................................................................................................... C-16 VII. Recovery Of Casing .................................................................................................................. C-19 VIII. Reconditioning ......................................................................................................................... C-20 IX. Field Welding Of Attachments On Casing .................................................................................... C-20 II. Care And Use Of Tubing .................................................................................................................... C-24 Introduction ...................................................................................................................................... C-24 I. Transportation ............................................................................................................................... C-24 II. Preparation And Inspection Before Running .................................................................................. C-24 III. Rig Equipment ............................................................................................................................ C-24 IV. Pre-running Preparations ............................................................................................................. C-25 V. Running ........................................................................................................................................ C-26 VI. Pulling Tubing ............................................................................................................................. C-36 VII. Causes Of Tubing Troubles ........................................................................................................ C-37 VIII Reconditioning .......................................................................................................................... C-37

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Chapter C Casing And Tubing The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study.

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I. Care And Use Of Casing Introduction This section is based on API RP 5C1, Care and Use of Casing and Tubing. Additional Data is included in Subsection VI B.

I. Transportation Reference is made to Section B4-1 regarding transportation of drill pipe. The same principles apply to the care and handling during transportation of all threaded tubular goods including casing and tubing.

II. Preparation And Inspection Before Running A. Inspection New casing is delivered free of injurious defects as defined in API Spec. 5D and within the practical limits of the inspection procedures therein prescribed. Some users have found that, for a limited number of critical well applications, these procedures do not result in casing sufficiently free of defects to meet their needs for such critical applications. Various nondestructive inspection services have been employed by users to assure that the desired quality of casing is being run. In view of this practice, it is suggested that the individual user: 1. Familiarize himself with inspection practices specified in the standards and employed by the respective mills, and with the definition of "defect" contained in the standards. 2. Thoroughly evaluate any nondestructive inspection to be used by him on API tubular goods to assure himself that the inspection does in fact correctly locate and differentiate injurious defects from other variables which can be and frequently are sources of misleading "defect" signals with such inspection methods.

B. Thread Protectors All casing, whether new, used, or reconditioned, should always be handled with thread protectors in place. Casing should be handled at all times on racks or on wooden or metal surfaces free of rocks, sand, or dirt other than normal drilling mud. When lengths of casing are inadvertently dragged in the dirt, the threads should be recleaned and serviced again as outlined in Par. IV-A.

III. Rig Equipment Slip elevators are recommended for long strings. Both spider and elevator slips should be clean and sharp and should fit properly. Slips should be extra long for heavy casing strings. The spider must be level. Note: Slip and tong marks are injurious. Every possible effort should be made to keep such damage at a minimum by using proper up-to-date equipment. If Collar-pull elevators are used, the bearing surface should be carefully inspected for: 1) uneven wear which may produce a side lift on the coupling with danger of it jumping off, and 2) uniform distribution of the load when applied over the bearing face of the coupling. Spider and elevator slips should be examined and watched to see that all lower together. If they lower unevenly, there is danger of denting the pipe or badly slip-cutting it.

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Care must be exercised, particularly when running long casing strings, to insure that the slip bushing or bowl is in good condition. Tongs should be examined for wear on hinge-pins and hinge-surfaces. The back-up line attachment to the back-up post should be corrected if necessary to be level with the tong in the back-up position, so as to avoid uneven load distribution on the gripping surfaces of the casing. The length of the back-up line should be such as to cause minimum bending stresses on the casing to allow full stroke movement of the make-up tong.

IV. Pre-running Preparations A. Thread Preparation The following precautions should be taken in the preparation of casing threads for makeup in the casing strings: 1. Immediately before running, remove thread protectors from both field and coupling ends and clean the threads thoroughly, repeating as additional rows become uncovered. 2. Carefully inspect the threads. Those found damaged, even slightly, should be laid aside unless satisfactory means are available for correcting thread damage. 3. The length of each piece of casing shall be measured prior to running. A steel tape calibrated in decimal feet to the nearest 0.01 ft should be used. The measurement should be made from the outermost face of the coupling or box to the position on the externally threaded end where the coupling or the box stops when the joint is made up powertight. On round thread joints, this position is to the plane of the vanish point on the pipe; on buttress thread casing, this position is to the base of the triangle stamp on the pipe; and, on extreme line casing, to the shoulder on the externally threaded end. The total of the individual lengths so measured will represent the unloaded length of the casing string. The actual length under tension in the hole can be obtained by consulting graphs which are prepared for this purpose and which are available in most pipe handbooks. 4. Check each coupling for makeup. If the standoff is abnormally great, check the coupling for tightness. Tighten any loose couplings after thoroughly cleaning the threads and applying fresh compound over entire thread surfaces, and before pulling the pipe into the derrick. 5. Before stabbing, liberally apply thread compound to the entire internally and externally threaded areas. It is recommended that high pressure modified thread compound as specified in API Bul. 5A2: Bulletin on Thread Compounds be used, except in special cases where severe conditions are encountered, it is recommended that high pressure silicone thread compound as specified in Bul. 5A2 be used. 6. Place clean thread protector on the field end of the pipe so that the thread will not be damaged while rolling pipe on the rack and pulling into the derrick. Several thread protectors may be cleaned and used repeatedly for this operation. 7. If a mixed string is to be run, check to determine that appropriate casing will be accessible on the pipe rack when required according to the program. 8. Connectors used as tensile and lifting member should have their thread capacity carefully checked to assure that the connector can safely support the load. 9. Care should be taken when making up pup joints and connectors to assure that the mating threads are of the same size and type.

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B. Drifting of Casing It is recommended that each length of the casing be drifted for its entire length with mandrels just before running as follows: Casing size, inch

Drift Mandrel Size, inc. Length Diameter, min.

8-5/8 and smaller

6

d - 1/8

9-5/8 to 13-5/8

12

d - 5/32

16 and larger

12

d - 3/16

C. Handling from Rack to Floor Lower or roll each piece of casing carefully to the walk without dropping. Use rope snubber if necessary. Avoid hitting casing against any part of derrick or other equipment. Provide a hold-back rope at window. For mixed or unmarked strings, a drift or "jack rabbit" should be run through each length of casing when it is picked up from the catwalk and pulled onto the derrick floor, to avoid running a heavier length or one with a lesser inside diameter than called for in the casing string.

V. Running Casing A. Stabbing Do not remove thread protector from field end of casing until ready to stab. If necessary, apply thread compound over entire surface of threads just before stabbing. The brush or utensil used in applying thread compound should be kept free of foreign matter and the compound and the compound should never be thinned. In stabbing, lower casing carefully to avoid injuring threads. Stab vertically, preferably with assistance of a man on the stabbing board. If the casing stand tilts to one side after stabbing, lift up, clean, and correct any damaged thread with three-cornered file, then carefully remove any filings and reapply compound over the thread surface. After stabbing, the casing should be rotated very slowly at first to insure that threads are engaging properly and not cross-threading. If spinning line is used, it should pull close to the coupling.

B. Make-up, Power Tongs The use of power tongs for making up casing made desirable the establishment of recommended torque values for each size, weight, and grade of casing. Early studies and test indicated that torque values are affected by a large number of variables, such as: variations in taper, lead, thread height and thread form, surface finish, type of thread compound, length of thread, weight and grade of pipe, etc. In later studies on make-up torque, it was observed that the API round thread joint pullout strength formula in API Bul. 5C3 contains several of the variables believed to affect make-up torque. Through investigations, it was found that the torque values obtained by dividing the calculated pullout values by 100, were generally comparable to those values obtained by field make-up tests where the API modified thread compound was used. This procedure was therefore used to establish the optimum make up torque values listed in Table C1-1.

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Table C1-1a 8-Rd ST Casing Make-up Torque

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Table C1-1b 8-Rd LT Casing Make-up Torque

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Minimum torque values listed are 75% of optimum values and maximum values listed are 125% of optimum values. All values are rounded to the nearest 10 foot pounds. These values must necessarily be considered a guide only, due to the very wide variations in torque requirements that can exist for a specific connection. Because of this, it is essential that torque be related to made-up position as outlined in the following: a. It is advisable when starting to run casing from each particular mill shipment to make up sufficient joints to determine the torque necessary to provide proper make-up see Par. V-C for proper number of turns beyond handtight position. These values may indicate that a departure from the recommended optimum values listed in Table C1-1 is advisable. If other optimum values are chosen, the minimum torque should be not less than 75 per cent of the optimum selected. The maximum torque should be not more than 125 per cent of the optimum torque. b. The power tong should be provided with a reliable torque gage of know accuracy. In the initial stages of makeup, any irregularities of make-up or in speed of make-up should be observed, since these may be indicative of crossed threads, dirty or damage threads, or other unfavorable conditions. c. Continue the make-up, observing both the torque gage and the approximate position of the coupling face with respect to the last scratch position. d. The optimum torque values shown in the following tabulation have been selected to give optimum make-up under normal conditions and should be considered as satisfactory providing the face of the coupling is flush with the last scratch or within two thread turns plus or minus of the last scratch. e. If the make-up is such that the last scratch is buried two thread turns and the minimum torque shown in Table C1-1 is not reached, the joint should be treated as a questionable joint as provided under Par. V.D. If several threads remain exposed when the optimum torque is reached, apply additional torque up to the maximum shown in Table C1-1. If the standoff (distance from face of coupling to the last scratch) is greater than three thread turns when the maximum torque is reached, the joint should be treated as a questionable joint as provided under Par. V.D. g. Make-up torque values for buttress thread casing connections should be determined by carefully noting the torque required to make up each of several connections to the base of the triangle, then using the torque value thus established, make up balance of the pipe of that particular weight and grade in the string.

C. Make-up, Conventional Tongs When conventional tongs are used for casing make-up, tighten with tongs to proper degree of tightness. The joint should be made up beyond the hand-tight position at least 3 turns for sizes 4-1/2 through 7 inch, and at least 3-1/2 turns for sizes 7-5/8 inch and larger, except 9-5/8 inch and 10-3/4 inch grade P-110 and 20 inch grade J-55 and K55 which should be made up 4 turns beyond hand-tight position. When using a spinning line it is necessary to compare handtightness with spin-up tightness. In order to do this, make up the first few joint to the handtight position, then back off and spin up joints to the spin-up tight position. Compare relative position of these two makeups and use this information to determine when the joint is made up the recommended number of turns beyond handtight.

D. Questionable Make-up Joints that are questionable as to their proper tightness should be unscrewed and the casing laid down for inspection and repair. When this is done, the mating coupling should be carefully inspected for damaged threads. Parted joints should never be reused without shopping or regaging, even though the joints may have little appearance of damage.

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If casing has a tendency to wobble unduly at its upper end when making up, indicating that the thread may not be in line with the axis of the casing, the speed of rotation should be decreased to prevent galling of threads. If wobbling should persist despite reduced rotational speed, the casing should be laid down for inspection. Serious consideration should be given before using such casing in a position in the string when a heavy tensile load is imposed. In making up the field joint it is possible for the coupling to make up slightly on the mill end. This does not indicate that the coupling on the mill end is too loose, but simply that the field end has reached the tightness with which the coupling was screwed on at the mill.

E. Lowering Casing Casing strings should be picked up and lowered carefully, and care exercised in setting slips to avoid shock loads. Dropping a string even a short distance may loosen couplings at the bottom of the string. Care should be exercised to prevent setting casing down on bottom, or otherwise placing it in compression because of the danger of buckling, particularly in that part of the well where hole enlargement has occurred. Definite instructions should be available as to the design of the casing string, including the proper location of the various grades of steel, weights of casing, and types of joint. Care should be exercised to run the string in exactly the order in which it was designed. If any length cannot be clearly identified, it should be laid aside until its grade, weight, and the type of joint can be positively established. To facilitate running and to assure adequate hydrostatic head to contain reservoir pressures, the casing should be periodically filled with mud while being run. A number of things govern the frequency with which filling should be accomplished: weight of pipe in the hole, mud weight, reservoir pressure, etc. In most cases, filling every 6-10 lengths should suffice. In no case should the hydrostatic balance of reservoir pressure be jeopardized by too infrequent filling. Filling should be done with mud of the proper weight, using a conveniently located hose of adequate size to expedite the filling operation. A quick-opening/closing plug valve on the mud hose will facilitate the operation and prevent overflow. If rubber hose is used, it is recommended that the quick-closing valve be mounted where the hose is connected to the mud line, rather that at the outlet end of the hose. It is also recommended that at least one other discharge connection be left open on the mud system to prevent build-up of excessive pressure when the quick closing valve is closed while pump is still running. A copper nipple at the end of the mud hose may be used to prevent damaging of the coupling threads during the filling operation. Note: The foregoing mud fill-up practice will be unnecessary if automatic fill-up casing shoes and collars are used.

F. Casing Landing Procedure Definite instructions should be provided for the proper string tension, also on the proper landing procedure after the cement has set. The purpose is to avoid critical stresses or excessive and unsafe tensile stresses at any time during the life of the well. In arriving at the proper tension and landing procedure, consideration should be given to all factors such as well temperature and pressure, temperature developed due to cement hydration, mud temperature and changes of temperature during producing operations. The adequacy of the original tension safety factor of the string as designed will influence the landing procedure and should be considered. If after due consideration it is not considered necessary to develop special land procedure instructions (and this probably applies to a very large majority of the wells drilled), then the procedure should be followed of landing the casing in the casing head at exactly the position in which it was hanging when the cement plug reached its lowest point or "as cemented".

VI. Causes Of Casing Troubles A. General The more common causes of casing troubles are as follows:

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1. Improper selection for depth and pressures encountered. 2. Insufficient inspection of each length of casing or of field-shop threads. 3. Abuse in mill, transportation, and field handling. 4. Non-observance of good rules in running and pulling casing. 5. Improper cutting of field-shop threads. 6. The use of poorly manufactured couplings for replacements and additions. 7. Improper care in storage. 8. Excessive torquing of casing to force it through tight places in the hole. 9. Pulling too hard on string (to free it). This may loosen the couplings at the top of the string. The should be retightened with tongs before finally setting the string. 10. Rotary drilling inside casing. Setting the casing with improper tension after cementing is one of the greatest contributing causes of such failures. 11. Wire-line cutting, by swabbing or cable-tool drilling. 12. Buckling of casing in an enlarged, washed-out uncemented cavity if too much tension s released in landing. 13. Dropping a string, even a very short distance. 14. Leaky joints, under external or internal pressure, are a common trouble, and may be due to: a. Improper thread compound. b. Under-tonging. c. Dirty threads. d. Galled threads, due to dirt, careless stabbing, damaged threads, too rapid spinning, over-tonging, or wobbling during spinning or tonging operations. e. Improper cutting of field-shop threads. f. Pulling too hard on string. g. Dropping string. h. Excessive making and breaking. i. Tonging too high on casing, especially on breaking out. This gives a bending effect which tends to gall the threads. j. Improper joint make-up at mill. k. Casing ovality of out-of-roundness. l. Improper landing practices which produces stresses in the threaded joint in excess of the yield point.

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B. Casing Wear - Drilling Operations 1. Definition. Casing Wear may be defined as localized removal of metal from casing ID as a result of metal to metal contact between the drill stem assembly and the casing during various drilling operations, by a combination of rotation and longitudinal movement. As covered in Section B1, page 1, the drill stem assembly is defined as the drill string (drill pipe plus tool joints), plus all other components, as may be described in a "packed hole" assembly. This includes the Kelly, drill collars (round, square, or spiral), stabilizers, reamers, and the bit. Longitudinal movement would include complete tripping of the drill string in and out of the hole, reaming, drilling of a whipstock, directional drilling procedures, the action of the wire line for inside tools involving surveys, coring milling, fishing, etc. To maintain the necessary close OD tolerance, all blades and cutting edges must have the most wear resistant materials economically available. This is coarse particle tungsten carbide, with proper matrix or binding materials and techniques of application. 2. History. From 1942 to 1961 both operators and contractors utilized tungsten carbide hardfacing on their tool joints all over the free world in directional holes as well as crooked holes, and little or no casing wear problems were experienced. Only after these higher lateral thrust loads from greater weights, higher rpm, the introduction of the "packed hole" assembly concept, and more sharply deflected holes, did operators experience severe casing wear. This severe wear in the casing could be pinpointed at these sharp angles or changes in direction. All these facts and proven data provide sufficient proof to support the conclusion that casing wear can and does occur with or without hardfacing and that there are numerous factors, other than hardfacing, which must be considered when we analyze the various causes of casing wear. Many of the same factors which contribute to casing wear may also contribute to "heat checking" of the tool joints, Section B-2. 3. Investigations. Manufacturers of both tungsten carbide and alloy hardfacing materials for commercial use have developed information which ties in closely with that developed by tool joint manufacturers. Field performance data, combined with laboratory data, shows that continuous, smooth, uniform deposits of fine particle tungsten carbide will provide a reasonably good bearing. 4. Rotation and Tripping. There is sufficient data from laboratories and field to prove that most casing wear occurs relatively high in the hole, and generally at a dog leg, after substantial hole is drilled below. Casing wear can. occur either from rotation or tripping, or from both. Variables which control the degree of casing wear are the magnitude of lateral thrust loads, rpm, surface conditions of the drill stem members (hard or soft, rough or smooth), vertical alignment of the Kelly, and, of course, the amount and quality of drilling mud between the surfaces of the drill stem members and casing. Specimens of worn casing often times show deep longitudinal marks, scratches, and grooves from such tripping. 5. Other Contributing Factors. Deep grooves from wire lines are most convincing evidence of cutting action by longitudinal movement inside casing. It can be shown also that following a complete trip of the drill stem some of these longitudinal scratches and grooves can and often are wiped out by rotation of the drill string. Observations also show that the maximum wear area of most of these worn specimens is generally the radius of the drill pipe itself. Therefore, when we consider that there is over 30' of drill pipe and 17' of tool joint OD length, and only 3" of this may or may not be hardfaced, we must conclude that the drill pipe itself can and often does produce more wear inside the casing than some of these other members of the drill stem assembly. The very fact that most drill pipe shows

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substantially more body wall wear in directional holes, key seats, and dog legs is indicative that drill pipe contacts the casing or the formation with substantial lateral thrust loading. Sufficient field and laboratory data is also available to show that under the above conditions OD and body wall wear is one of the greatest limiting factors in the life of the drill string. The degree or amount of casing wear also depends to a very great extent upon the amount of abrasive and sand particles in the mud. Rough surfaces or soft surfaces have a greater tendency to hold sand in position and cut casing more rapidly. Some operators have experienced holes worn in casing where external flush drill pipe no external tool joint OD - was used in directional drilling operations. It has been shown repeatedly in lab investigations that rough, non-hardfaced tool joints can and do cut casing when subjected to certain lateral thrust loads and in combination with relatively high rpm. Specimens with softer surfaces show a higher percent increase in casing cutting tendency than harder surfaces. 6. Suggested Controls. There are no foolproof methods for complete elimination of casing wear or "heat checking" as described above. However, the following are worth serious consideration: a. Keep the Kelly and drill pipe as straight as possible. b. Double check proper vertical alignment of the Kelly over well head. The Kelly must be straight. c. Utilize data in Lubinski's work in "Maximum Permissible Dog Legs", as to the rate of change of angles. d. Wipe out all known key seats or sharp dog legs. e. Control of OD wear of tool joints by the proper use of a continuous, smooth application of fine particle tungsten carbide hardfacing. This also provides a better bearing against the casing. The OD of the tool joint is the main controlling factor in its torsional strength with respect to the drill pipe to which it is at tached. f. Avoid critical speeds which can contribute to increased casing wear, heat checking, and other costly performance problems. g. Control sand content of drill fluid. h. Drill pipe run inside casing should be equipped with suitable drill pipe protectors. 7. Conclusions. Most operators agree with the concept that casing wear occurs because a combination of rotation and tripping. Some operators have evidence that above critical rotary speed and lateral thrust load, casing cutting increases quite rapidly. This is particularly true where relatively high lateral thrust loads are involved.

VII. Recovery Of Casing Break-out tongs should be positioned close to the coupling but not too close since a slight squashing effect where the tong dies contact the pipe surface cannot be avoided especially if the joint is tight and/or the casing is light. Keeping a space of 1/3 to 1/4 of the diameter of the pipe between the tong and the coupling should normally prevent unnecessary friction in the threads. Hammering the coupling to break the joint is an injurious practice. If tapping is required, use the flat face, never the peen face of the hammer, and under no circumstances should a sledge hammer be used. Tap lightly near the middle and completely around the coupling, never near the end nor on the opposite sides only. Great care should be exercised to disengage all of the threads before lifting the casing out of the coupling. Do not jump casing out of coupling.

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All threads should be cleaned and lubricated or should be coated with a material that will minimize corrosion. Clean protectors should be placed on the casing before it is laid down. When casing is being retrieved because of a casing failure, it is imperative to future prevention of such failures that a thorough metallurgical study be made. Every attempt should be made to retrieve the failed portion in the "as failed" condition. When thorough metallurgical analysis reveals some facet of pipe quality to be involved in the failure, the results of the study should be reported to the API office in Dallas, Texas. Casing stacked in the derrick should be set on a firm wooden platform and without the bottom thread protector since the design of most protectors is not such as to support the joint or stand without damage to the field thread.

VIII. Reconditioning Tubular good which have become damaged through use or abuse may often be reconditioned to advantage. This should be done only in accordance with API specifications. The acceptability of reconditioned threads should always be confirmed by gaging and inspection, in accordance with API Std 5B: Specification for Threading, Gaging and Thread Inspection of Casing, Tubing and Line-Pipe Threads.

IX. Field Welding Of Attachments On Casing A. Introduction The selection of steel for use in casing is governed by important considerations dictated by the service the casing must perform. Steels most suitable for field welding do not have these performance properties. Therefore, field weldability cannot be primary consideration in the selection of steel for the manufacture of casing. As a result, unless precautions are taken welding may have adverse effects on may of the steels used in all grades of casing, especially J55 and higher. The heat from welding may affect the mechanical properties of high-strength casing steels. Cracks and brittle areas are likely to develop in the heat affected zone. Hard areas of cracks can cause failure, especially when the casing is subjected to tool-joint battering. For these reasons, welding on high-strength casing should be avoided if possible. Practices and equipment that will eliminate welding are recommended. For example, cements or locking attachments might be used rather than welding bottom joints to prevent them from unscrewing. Similarly, use of mechanical means for attachment of centralizers and scratchers is encouraged. Although welding on high-strength casing is not recommended as the best practice, it is recognized that under certain circumstances the user may elect to do so. In such cases, there are certain practices which, if followed, will minimize the deleterious effects of welding. The intent here is to outline practices that will serve as a guide to field personnel. Welding is not recommended on those critical portions of the casing string where tension, burst, or collapsestrength properties must not be impaired. If welding is necessary, it should be restricted to the lowermost portions of the cemented interval at the bottom of the casing string. Shoe-joint welding of couplings, when necessary, must be used with extreme caution and with full use of procedures herein outlined. The responsibility for welding lies with the user and results are largely governed by the welder's skill. Weldability of the various makes and grades of casing varies widely, thus placing added responsibility on the welder. Transporting a qualified welder to the job rather than using a less-skilled man who may be at hand, will in most cases prove economical. The responsible operating representative should ascertain the welder's qualifications and, if necessary, assure himself by instruction or demonstration, that the welder is able to perform the work satisfactorily.

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B. Requirements of Welds Welds should have sufficient mechanical strength to prevent joints from backing off or to hold various attachments to casing. In service welds are called upon to withstand impact, pounding, vibration and other sever service conditions to which casing is subjected. Ability to withstand bending forces is also often important. To accomplish this, ductile welds free from cracks, and brittle or hard spots are desired. Leak resistance is not a factor in welds covered by procedures herein outlined. The purpose of the welds is to make attachments or to prevent joints from unscrewing. Where welding is done on joints, the weld is not intended as a seal to prevent leakage, but rather as a means of preventing the joint from backing off. Leak resistance is obtained by the joint itself. Leak resistance is required for the seal weld in casing hangers. Recommended procedures for accomplishing this are contained in Appendix B of API Std. 6A: Specification for Wellhead Equipment.

C. Process Welding is currently being done by the metal-arc or oxyacetylene processes. Brazing alloys melting at 1200°F or lower, which posses good mechanical properties, are available for application by the oxyacetylene or oxypropane torch. They can be used to avoid brittle areas or cracks which may occur in ahoy casing when welded; but when so subjected to this temperature, a reduction in strength may result.

D. Filler for Arc Welding When using the shielded metal-arc welding (SMAW) process, low-hydrogen electrodes should be used. These include classes E7015 and E7016 of AWS A5.1: Carbon Steel Covered arc-Welding Electrodes* (latest edition), and E7015-A1, E7016-A1, E8016-C1**, and E8016-C2**, of ASW A5.5: Low Alloy Steel Covered arc-Welding Electrodes* (latest edition). Low-hydrogen iron powder electrodes of some types also are suitable. Low-hydrogen electrodes should not be exposed to the atmosphere until ready for use. * Obtainable from the American Welding Society, 2501 N.W. 7th Street, Miami, Florida 33125. ** Electrodes E8016-C1 and E8016-C2 do not meet NACE STANDARD MR-01-75 for Sour Gas Service.

E. Preparation of Base Metal The area to be welded should be dry and brushed or wiped free of any excess paint, grease, scale, rust or dirt.

F. Preheating and Cooling Preheating is considered essential for welding all grades of casing. At least 3 inches on each side of weld locations should be preheated to 400 to 600°F. Preheat temperature should be maintained during welding. (Use "Tempilstik" or equivalent crayon to check temperature.) Rapid cooling must be avoided. To assure slow cooling, welds should be protected from extreme weather conditions (cold, rain, high winds, etc.) Welds made on the casing as it is being run should be cooled in air to below 250°F (measured with a "Tempilstik") prior to lowering the weld into the hole. The required cooling usually takes about 5 minutes.

G. Post-heating When welding casing or attachments of alloy steels such as AISI 4140, it is desirable to temper the weld area by post-heating. Post-heating will reduce the susceptibility to cracking the affected zone. The weld area should be reheated to 1000-1100°F after the weld has cooled below 250°F. CAUTION: Post-heating to 1000-1100°F may cause a reduction in the yield strength of some high strength casing such as P-110. The post-heat temperature must be controlled by some positive means (such as "Tempilstik") to insure that the casing is not overheated. The

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cooling rate after post-heat is not critical if cooled in air.

H. Welding Technique The weld should be started as soon as the specified preheat temperature has been attained. The welding operation should be shielded from strong winds, blowing dust and sand, and rain. Where metal-are welding is used, electrodes 3/16-inch in diameter or smaller should be used. Two pass welds are preferred, provided the second pass can be controlled so that it will overlay only the weld metal and not extend to the casing. The function of the second pass temper or anneal the underlying weld and adjacent metal. This purpose is defeated if the second pass extends onto the casing. The second pass should be laid on very quickly after cleaning the first bead so as to prevent the metal heated by the first pass from cooling quickly enough to become brittle. Weaving should be kept to a minimum, and the current should be on the low side of the range recommended by the electrode manufacturer. Every effort should be made to avoid undercutting. All slag or flux remaining on any welding bead should be removed by chipping or grinding before depositing the next bead. Attachments should fit as closely as possible to the casing surface. The arc must not be struck on the casing, as every arc burn results in a hard spot and damage to the casing. Cracks have frequently resulted from striking the arc on the casing. The arc should be struck on the attachment, which is made from steel not so susceptible to damage. If necessary to strike the arc on the casing, it should be struck in the area to be welded. Care should be taken to insure that the welding cable is properly grounded to the casing, but ground wire should not be welded to the casing. Ground wire should be firmly clamped to the casing, or fixed in position between pipe slips. Bad contact may cause sparking, with resultant hard spots beneath which incipient cracks may develop. The welding cable should not be grounded to steel derrick, rotary table base, or casing rack. As much welding as possible should be done on the rack instead of the rig floor or while the casing is hanging in the well. This procedure has the two-fold advantage of (1) welding under more favorable conditions, and (2) the weld cooling rate can be slower and more closely controlled. Do not ground the rack, but firmly clamp ground to the casing being welded. If couplings, float collars, and guide shoes are welded, sufficient metal should be deposited to prevent them backing out. If the top side of the float collar and casing collars are welded while the casing is in the rotary or if the practice is not to make a complete weld, three 3-inch welds should be placed at 120-deg intervals around 9-5/8inch casing, three 4-inch welds should be placed on larger casing, and three 2-inch welds on smaller casing. If welds longer than 4-inch to 6-inch are made, back-stepping is advantageous. For example: If 6-inch of weld has been deposited as a stringer bead from left to right, then the operator should start about 6-inch to the left of the weld deposited and weld up to the starting point of the previously deposited weld. Complete fillet welds should have approximately equal leg dimensions. Care should be taken to avoid under cutting. Two passes are preferred. (Welds should be cleaned between passes.) When lugs are welded to casing, the weld should extend around the lug ends. It is good practice to strike the arc near the lug end, weld the end, and bring the weld back to about the lug center. The arc is momentarily broken so that the lug can be cut or burnt to length and the unwelded end hammered down against the casing. The weld is then continued around the second end, bringing the are back on the weld before breaking. In this manner, ends are welded without either striking or breaking the arc at the ends. When centralizers and scratchers are welded to casing, welds should be minimum length of 2-inches at 2-inch intervals.

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When rotating scratchers are welded to casing, full-length welds on each end, with 3/4-inch welds at two equal spacings on the front edge and one 3/4-inch weld on the center of the rear or trailing edge, have found satisfactory.

NOTE: The torque values listed in Table C-1 apply only to casing with zinc plated couplings. When making up connections with tin plated couplings, 80% of the listed value can be used as a guide.

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II. Care And Use Of Tubing Introduction This section is based on API RP 5C1, Care and Use of Casing and Tubing.

I. Transportation Reference is made to Section B4-1 regarding transportation of drill pipe. The same principles apply to the care and handling during transportation of all threaded tubular goods including casing and tubing.

II. Preparation And Inspection Before Running A. Inspection New tubing is delivered free of injurious defects as defined in API Spec. 5CT and within the practical limits of the inspection procedures therein prescribed. Some users have found that for a limited number of critical well applications, these procedures do not result in tubing sufficiently free of defects to meet their needs for such critical applications. Various nondestructive inspection services have been employed by users to assure that the desired quality of tubing is being run. In view of this practice, it is suggested that the individual user: 1. Familiarize himself with inspection practices specified in the standards and employed by the respective mills, and with the definition of "defect" contained in the standards. 2. Thoroughly evaluate any nondestructive inspection to be used by him on API tubular goods to assure himself that the section does in fact correctly locate and differentiate defects from other variables which can be and frequently are sources of misleading "defect" signals with such inspection methods. CAUTION: Due to the permissible tolerance on the outside diameter immediately behind the tubing upset, the user is cautioned that difficulties may occur when wraparound seal type hangers are installed on tubing manufactured on the high side of the tolerance; therefore, it is recommended that the user select the joint of tubing to be installed at the top of the string.

B. Thread Protectors All tubing, whether new, or reconditioned, should always be handled with thread protectors in place. Tubing should be handled at all times on racks or on wooden or metal surfaces free of rocks, sand, or dirt other than normal drilling mud. When lengths of tubing are inadvertently dragged in the dirt, the threads should be recleaned and serviced again as outlined in Par. IV A.

C. Drifting Before running in the hole for the first time, tubing should be drifted with an API drift mandrel to insure passage of pumps, swabs and packers. Mandrels will have the following size: Tubing size

Drift Length

Mandrel Size, Min. Diameter, inchs

2-7/8 and smaller

42

d-3/32

3-1/2 and larger

42

d-1/8

III. Rig Equipment Elevators should be in good repair and should have links of equal length.

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Slip type elevators are recommended when running special clearance couplings, especially those beveled on the lower end. Elevators should be examined to note it latch fittings is complete. Spider slips which will not crush the tubing should be used. Slips should be kept sharp. Tubing tongs which will not crush the tubing should be used on the body of the tubing and should fit properly to avoid unnecessary cutting of the pipe wall. Tong dies should fit properly and conform to the curvature of the tubing. The use of pipe wrenches is not recommended. NOTE: Slip and tong marks are injurious. Every possible effort should be made to keep such damage at a minimum by using proper up-to-date equipment.

IV. Pre-running Preparations A. Thread preparations The following precautions should be taken in the preparation of tubing threads: 1. Immediately before running, remove protectors from both the field end and the coupling end, and clean the threads thoroughly, repeating as additional rows of casing become uncovered. 2. Carefully inspect the threads. Those found damaged, even slightly, should be laid aside unless satisfactory means are available for correcting thread damage. 3. The length of each piece of tubing shall be measured prior to running. A steel tape calibrated in decimal feet to the nearest 0.01 ft should be used. The measurement should be made from the outermost face of the coupling or box to the position on the externally threaded end where the coupling or the box stops when the joint is made up powertight. The total of the individual lengths so measured will represent the unloaded length of the tubing string. The actual length under tension in the hole can be obtained by consulting graphs which are prepared for this purpose and which are available in most Oil Field Country Tubular pipe handbooks. 4. Place clean protectors on field end of the pipe so that threads will not be damaged while rolling pipe onto the rack and pulling into the derrick. Several thread protectors may be cleaned and used repeatedly for this operation. 5. Check each coupling for makeup. If the standoff is abnormally great, check the coupling for tightness. Loose couplings should be removed, the threads thoroughly cleaned, fresh compound applied over the entire thread surfaces, then the couplings replaced and tightened before pulling the tubing into the derrick. 6. Before stabbing, liberally apply thread compound to the entire internally and externally thread areas. It is recommended that high pressure modified thread compound as specified in API Bul. 5A2: Bulletin on Thread Compounds be used, except in special cases where severe conditions are encountered, it is recommended that high pressure silicone thread compound as specified in Bul. 5A2 be used. 7. Connectors used as tensile and lifting members should have their thread capacity carefully checked to assure that the connector can safely support the load. 8. Care should be taken when making up pup joints and connectors to assure that the mating threads are of the same size and type.

B. Additional Preparations For high-pressure or condensate wells, additional precautions should be taken to insure tight joints as follows:

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1. Couplings should be removed, and both the mill-end pipe thread and coupling thread thoroughly cleaned and inspected. To facilitate this operation, tubing may be ordered with couplings handling tight, which is approximately one turn beyond hand-tight, or may be ordered with the couplings shipped separately. 2. Thread compound should be applied to both the external and internal threads and the coupling should be reapplied handling tight. Field-end threads and the mating coupling threads should have thread compound applied just before stabbing. 3. When tubing is pulled into the derrick, care should be taken that the tubing is not bent, or couplings or protectors bumped.

V. Running A. Stabbing Do not remove thread protector from field end of tubing until ready to stab. If necessary, apply thread compound over entire surface of threads just before stabbing. The brush or utensil used in applying thread compound should be kept free of foreign matter and the compound should never be thinned. In stabbing, lower tubing carefully to avoid injuring threads. Stab vertically, preferably with assistance of man on stabbing board. If the tubing tilts to one side after stabbing, lift up, clean, and correct any damaged thread with three-cornered file, then carefully remove any filings and reapply compound over thread surface. Care should be exercised, especially when running doubles or thribbles, to prevent bowing and resulting in errors in alignment when the tubing is allowed to rest too heavily on the coupling threads. Intermediate supports may be placed in the derrick to limit bowing of the tubing.

B. Make-Up 1. After stabbing, start screwing by hand or apply regular or power tubing tongs slowly. Power tubing tongs are recommended for high-pressure or condensate wells to insure uniform make-up and tight joints. Joints should be made up tight, approximately two turns beyond the hand-tight position, with care being taken not to gall the threads. When the additional preparation and inspection precautions for high-pressure or condensate wells are taken, the coupling will "float" or make up simultaneously at both ends until the proper number of turns beyond the hand-tight position have been obtained. The hand-tight position may be determined by checking several joints on the rack and noting the number of threads exposed when a coupling is made up with a torque of 50 ft-lb. 2. Field Make Up. Joint life of tubing under repeated field make-up is inversely proportional to the field make-up torque applied. Therefore, in wells where leak resistance is not a great factor, minimum field make-up torque values should be used to prolong joint life. The use of power tongs for making up tubing made desirable the establishment of recommended torque values should be used to prolong joint life. The use of power tongs for making up tubing made desirable the establishment of recommended torque values for each size, weight, and grade of tubing. Table C2-1 contains recommended optimum make-up torque values for non-upset, external upset, and integral joint tubing, based on 1% of the calculated joint pullout strength determined from the joint pullout strength formula for 8-round-thread casing in API Bul. 5C3.

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Table C2-1a Non-Upset Tubing Make-up Torque

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Table C2-1b Upset Tubing Make-up Torque

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Table C2-1c Integral Joint Tubing Make-up Torque

For Full Size Image of This Table Click Here

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Minimum torque values listed are 75% of optimum values and maximum torque values listed are 125% of optimum values. All values are rounded to the nearest 10 foot-pounds. NOTE: The torque values listed in Table C-2 apply only to tubing with zinc plated couplings. When making up connections with tin plated couplings, 80% of the listed value can be used as a guide.

C. Landing Finding bottom should be accomplished with extreme caution. Do not set tubing down heavily.

VI. Pulling Tubing A caliper survey prior to pulling a worn string of tubing will provide a quick means of segregating badly worn lengths for removal. Break-out tongs should be positioned close to the coupling. Hammering the coupling to break the joint is an injurious practice. When tapping is required, use the flat face, never the peen face, of the hammer, and tap lightly at the middle and completely around the coupling, never near the end or on opposite sides only. Great care should be exercised to disengage all the threads before lifting the tubing out of the coupling. Do not jump tubing out of the coupling. Tubing stacked in the derrick should be set on a firm wooden platform and without the bottom thread protector since the design of most protectors is not such as to support the joint or stand with damage to the field thread. Protect threads from dirt or injury when the tubing is out of the hole. Tubing set back in the derrick should be properly supported to prevent undue bending. Tubing 2-3/8 inch OD and larger, preferably should be pulled in stands approximately 60 ft. long or in doubles of range 2. Stands of tubing 1.900-inch OD or smaller, and stands longer than 60 ft, should have intermediate support. Before leaving location, always firmly tie a setback of tubing in place. Make sure threads are undamaged, clean and well coated with compound before re-running. Distribute joint and tubing wear by moving a length from the top of the string to the bottom each time the tubing is pulled. In order to avoid leaks, all joints should be retightened occasionally. When tubing is stuck, the best practice is to use a calibrated weight indicator. Do not be misled, by stretching of the tubing string, into the assumption that the tubing is free. After a hard pull to loosen a string of tubing, all joints pulled on should be retightened. All threads should be cleaned and lubricated or should be coated with a material that will minimize corrosion. Clean protectors should be placed on the tubing before it is laid down. Before tubing is stored or re-used, pipe and threads should be inspected and defective joints marked for shopping and regaging. When tubing is being retrieved because of tubing failure, it is imperative to future prevention of such failures that thorough metallurgical study be made. Every attempt should be made to retrieve the failed portion in the "as failed" condition. When thorough metallurgical analysis reveals some facet of pipe quality to be involved in the failure, the results of the study should be reported to the API office in Dallas, Texas.

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VII. Causes Of Tubing Troubles The more common causes of tubing troubles are as follows: a. Improper selection for strength and life required, especially of non-upset tubing where upset tubing should be used. b. Insufficient inspection of finished product at the mill and in the yard. c. Careless loading, unloading and cartage. d. Damaged threads resulting from protectors loosening and falling off. e. Lack of care in storage to give proper protection. f. Excessive hammering on couplings. g. Use of worn-out and wrong types of handling equipment, spiders, tongs, dies and pipe wrenches. h. Non-observance of proper rules in running and pulling tubing. i. Coupling wear and rod cutting. j. Excessive sucker rod breakage. k. Fatigue, which often causes failure at the last engaged thread. There is no positive remedy, but using externalupset tubing in place of non-upset tubing greatly delays the start of this trouble. l. Replacement of worn couplings with non-API couplings. m. Dropping a string, even a short distance. This may loosen the couplings at the bottom of the string. The string should be pulled and rerun, examining all joints very carefully. n. Leaky joints, under external or internal pressure, are a common trouble, and may be due to: 1. Improper thread compound and/or improper application. 2. Dirty threads, or threads contaminated with coating material used as protection from corrosion. 3. Under-tonging or over-tonging. 4. Galled threads due to dirt, careless stabbing, damaged threads, poor or diluted thread com pound. 5. Improperly cut field threads. 6. Couplings that have been dented by hammering. 7. Pulling to hard on string. 8. Excessive re-running.

VIII Reconditioning Tubular goods which have become damaged through use or abuse may often be reconditioned to advantage. This should be done only in accordance with API specifications. The acceptability of reconditioned threads should always be confirmed by gaging and inspection, in accordance with API Spec. 5B: Specification for Threading, Gaging and Thread Inspection of Casing, Tubing and Line-Pipe Threads.

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Chapter D Drill Collars, Kellys, Subs and Heavy Weight Drill Pipe

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Table of Contents - Chapter D Drill Collars, Kellys, Subs and Heavy Weight Drill Pipe Preface ............................................................................................................................................... D-3 D1. Drill Collars: Specifications & Usage .................................................................................................. D-4 I. Specifications .................................................................................................................................. D-4 D2. Drill Collars: Care And Maintenance ................................................................................................ D-36 I. Recommended Drill Collar Care And Maintenance ........................................................................ D-36 D3. Kellys: Specifications ....................................................................................................................... D-59 I. Specifications ................................................................................................................................ D-59 D4. Kellys: Care And Maintenance ......................................................................................................... D-66 I. Care And Maintenance .................................................................................................................. D-66 D5. Drill Stem Subs: Specifications ......................................................................................................... D-71 I. Class And Type ............................................................................................................................. D-71 II. Dimensions For Type A & B Subs ................................................................................................ D-77 III. Dimensions For Type C (Swivel) Subs ........................................................................................ D-79 IV. Mechanical Properties Of Drill Stem Subs ................................................................................... D-79 V. Kelly Saver Subs .......................................................................................................................... D-80 D6. Kelly Valves: Specifications .............................................................................................................. D-81 I. Upper Kelly Cocks ....................................................................................................................... D-81 II. Lower Kelly Cocks ...................................................................................................................... D-85 III. Automatic Mud Saver Valves ...................................................................................................... D-87 IV. Kelly Saver Subs ........................................................................................................................ D-87 D-7 Specifications Of Heavy Weight Drill Pipe ........................................................................................ D-88 Care and Maintenance of HWDP ..................................................................................................... D-89 D8 - Glossary of Drill String Terms ......................................................................................................... D-90

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Chapter D Drill Collars, Kellys, Subs and Heavy Weight Drill Pipe The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study. The following industry representatives have contributed to the development and updating of this chapter: MEMBERS OF THE TASK GROUP: John Altermann Reading & Bates Drilling Company Doyle Brinegar Sii Drilco Gerald Wilson

Prideco, Inc.

Tom Winship

OMSCO Industry, Inc.

Preface This chapter of the IADC Drilling Manual, formerly the Tool Pushers' Manual, is concerned with the specifications, operating data, care and handling, and trouble-shooting of drill collars, heavy weight drill pipe, kellys and associated valves and subs and drill stem subs. A committee was appointed to prepare a manual on the care and handling of these tools. The original committee, chaired by Russell Lewis and consisting of Howard Lorenz of Oilfield Machine Supply Company, Moak Rollins, Drilco Oil Tools, John Willis, Hughes Tool Company and Roy McGrann, U.S. Steel, prepared the original draft There have been many contributors to Chapter D over the years, too many to mention in space available. The present revision to the chapter has been the responsibility of Doyle Brinegar, Sii Drilco, Gerald E. Wilson, Prideco Inc., Tom Winship, OMSCO Industry Inc. and John Altermann, Reading & Bates. Some of the information included in this chapter is extracted from the latest API Specification 7 and RP 7G, and is that which is believed to be of the most value to users and designers of drillstem components.

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D1. Drill Collars: Specifications & Usage I. Specifications A. Size Drill collars should be furnished in the sizes and dimensions shown in Table D1-1 or as specified on the purchase order.

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Table D1-1 Drill Collar Dimensions

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Notes on Table D1-1 * The drill collar number (column 1) consists of two parts separated by a hyphen. The first part is the connection number in the NC style. The second part, consisting of 2 (or 3) digits, indicates the drill collar outside diameter in units and tenths of inches. The connections shown in parentheses in column 1 are not a part of the drill collar number; they indicate interchangeability of drill collars made with the standard (NC) connections as shown. If the connections shown in parentheses in column 1 are made with the V-0.038R thread, the connections and drill collars, are identical with those in the NC style. Drill collars with 8-1/4 and 9-1/2 inches outside diameters are shown with 6-5/8 and 7-5/8 REG connections, since there are no NC connections in the recommended bending strength ratio range. The drill collar sizes listed in Table D1-1 were adopted in order to provide a full range of collars with improved connections, as replacement for the collars with the various connections specified in previous editions of API Spec 7. Purchase orders for collars with the improved connections should state the drill collar number or size and style, bore and length. Purchase orders for collars with optional connections should state the outside diameter, bore, length, connection size and style, and bevel diameter.

B. Mechanical Properties The mechanical properties of drill collars, as manufactured, should not be lower than the minimum values shown in Table D1-2. Table D1-2 Mechanical Properties and Tests of New Drill Collars

Notes on Table D1-2 NOTE 1: Tensile properties shall be determined by tests on cylindrical specimens conforming to the requirements of the current ASTM A-370, .2% offset method. NOTE 2: Tensile specimens from drill collars shall be taken within 3 feet of the end of the drill collar in a longitudinal direction, having the centerline of the tensile specimen 1 inch from the outside surface or midwall, whichever is less. NOTE 3: Hardness test shall be on OD of drill collar using Brinell Hardness (Rockwell-C acceptable alternative) test methods in compliance with current ASTM A-370 requirements.

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The latest edition of API Spec 7 should be consulted for method and location of tests.

C. Bores All drill collar bores should be gaged with a drift mandrel 10 foot long. The drift mandrel should have a minimum diameter equal to the specified bore of the drill collar (standard or optional) minus 1/8 inch.

D. Connections Drill collars should be furnished with box-and-pin connections in the sizes and styles stipulated in Table D1-1 and should conform with the requirements of API Spec 7, Section 9. Table D1-1 Drill Collar Dimensions

E. OD Tolerances Drill collars having "hot rolled, mill finished" outside diameters should meet the following stipulations: 1) Outside Diameter: the outside diameter shall comply with the tolerances of Table D1-3. Table D1-3 Drill Collar OD Tolerances

Notes on Table D1-3 * Out-of-Roundness is the difference between the maximum and minimum diameters of the bar, measured at the same cross-section, and does not include surface finish tolerances outlined in API Spec 7. 2) Surface Finish: The external surface of "hot rolled, mill finished" drill collars is to be the typical finish of hot rolled steel bars. Surface imperfections may be present, and may be removed by grinding. The removal of such imperfections should not result in stock removal in excess of that shown in Table D1-4.

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Table D1-4 Drill Collar Surface Imperfection Removal

3) Straightness: the external surface of "hot rolled, mill finished" drill collars should not deviate from the straight linc extending from end-to-end of the collar when placed adjacent to the surface by more than 1/160 inch per foot of drill collar length. Example: On a 30 foot long drill collar, the maximum deviation from a straight line is: 30 x 1/160 = 3/16 inches.

F. Weights Table D1-5 contains steel drill collar weights for a wide range of OD and ID combinations, in both API and nonAPI sizes.

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Table D1-5 Drill Collar Weight (Steel DCs)

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Values in the table may be used to provide the basic information required to calculate the weights of drill collar strings.

G. Stress-Relief Features for Drill Collar Connections Table D1-6 Stress-Relief Features for Drill Collar Connections

Notes on Table D1-6 * Numbered connections 23, 26 and 31 (2-3/8 IF and 2-7/8 IF) do not have sufficient metal to accommodate stress-relief features. Also See Figure D1-2a DC Connections - Stress Relief Features in Box Also See Figure D1-2b DC Connections - Stress Relief Features in Pin

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H. Cold Working Thread Roots Gage standoff will change after cold working of threads. This will not affect the interchangeability of connections and will improve connection performance. It is therefore permissible for a connection to be marked with the API monogram if it meets the API specification before cold working. In such event, the connection should also be stamped with a circle enclosing 'CW' to indicate cold working after gaging.

I. Selection of Connections Many drill collar connection failures are a result of bending stresses rather than torsional stresses. Following are bending strength ratio charts (Figures D1-3 through D1-9) which may be used for determining the most suitable connection to be used on new drill collars or for selecting the new connection to be used on collars which have been worn down on the outside diameter.

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Figure D1-1 Drill Collars

Figure D1-2 Connection Stress-Relief Features

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Figure D1-3 Bending Strength Ratios of 1-1/2" and 1-3/4" Drill Collars

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Figure D1-4 Bending Strength Ratios of 2" and 2-1/4" Drill Collars

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Figure D1-5 Bending Strength Ratios of 2-1/2" Drill Collars

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Figure D1-6 Bending Strength Ratios of 2-13/16" Drill Collars

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Figure D1-7 Bending Strength Ratios of 3" Drill Collars

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Figure D1-8 Bending Strength Ratios of 3-1/4" Drill Collars

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Figure D1-9 Bending Strength Ratios of 3-1/2" Drill Collars

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B.S.R. Guidelines: 1) For small drill collars 6" (152.4 mm) OD and below, try to avoid B.S.R.'s above 2.75:1 or below 2.25:1. 2) For high rpm, soft formations, and when drill collar OD is small compared to hole size (Example: 8" (203.2 mm) OD in 12-1/4" (311.2 mm) hole, 6" (152.4 mm) OD in 8-1/4" (209.6 mm) hole, avoid B.S.R.'s above 2.85:1 or below 2.25:1. 3) For hard formations, low rpm and when drill collar OD is close to hole size (Example: 10" (254.0 mm) OD in 121/4" (311.2 mm) hole, 8-1/4" (209.6 mm) OD in 9-7/8" (250.8 mm) hole, avoid B.S.R.'s above 3.20:1 or below 2.25:1. However, when low torque features are used on large drill collars, B.S.R.'s as large as 3.40:1 will perform satisfactorily. 4) For very abrasive conditions where loss of OD is severe, favor combinations of 2.50:1 to 3.00:1.

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K. Identification of Connections. 5) For extremely corrosive environments, favor combinations of 2.50:1 to 3.00:1. A connection that has a bending strength ratio of 2.50:1 is generally accepted as an average balanced connection. However, the acceptable range may vary from 3.20:1 to 1.90:1 depending upon the drilling conditions. As the outside diameter of the box will wear more rapidly than the pin inside diameter, the resulting bending strength ratio will be reduced accordingly. When the bending strength ratio falls below 2.00:1, connection troubles may begin. These troubles may consist of swollen boxes, split boxes, or fatigue cracks in the boxes at the last engaged thread. The minimum bending strength ratio acceptable in one operating area may not be acceptable in another. Local operating practices experience based on recent predominance of failures and other conditions should be considered when determining the minimum acceptable bending strength ratios for a particular area and type of connection. Certain other precautions should be observed in using these charts. It is imperative that adequate shoulder width and area at the end of the pin be maintained. The calculations involving bending strength ratios are based on standard dimensions for all connections. Minor differences between measured inside diameter and inside diameters listed in the charts are of little significance; therefore, select the chart with the inside diameter closest to measured inside diameter.

J. Connection Interchangeability Many connections have the same thread form, taper, lead, and pitch diameters but are identified by various common names. If all of the above are the same on two connections, they are interchangeable.

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Table D1-7 Interchangeability List of Rotary Shouldered Connections

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Notes on Table D1-7 * Connections with two thread forms shown may be machined with either thread form without affecting gaging or interchangeability. ** Numbered connections (N.C.) may be machined only with the V-0.038 radius thread form.

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Table D1-8 Pin Connection - Identification of Dimensions

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Figure D1-10 Pin Connection - Identification of Dimensions

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Table D1-9 Box Connection - Identification of Dimensions

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Figure D1-11 Box Connection - Identification of Dimensions

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Table D1-10 Drill Collar Dimensions - Ideal Range

Notes on Table D1-10 * The minimum size drill collar, calculated from the Lubinski and Hock equation, with the specific sizes of hole and casing combination, is too large for conventional fishing tools. When the minimum drill collar diameter is too large to washover and/or catch with an overshot, other steps should be taken. Some of the possibilities are as follows: - Use turned down casing couplings. - Use integral joints on casing. - Underream the hole. - Run smaller size casing. - Use a packed hole assembly instead of a pendulum.

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** Not API standard size drill collar.

L. Drill Collar Size Selection Woods (with Hughes) and Lubinski (with Amoco) pointed out that an unstabilized bit with small drill collars can cause an undersized or misaligned hole, making it difficult or impossible to run the casing. They determined that the actual drift, or useful diameter, of the hole would be equal to the bit diameter plus the drill collar diameter divided by two (refer to Figure D1-12). Figure D1-12 Effective Hole Size vs Drill Collar Size

Drift Diameter = 0.5 (Bit OD + Drill Collar OD) Therefore, they recommended larger drill collars near the bit. Robert S. Hock (Research Engineer with Phillips Petroleum Co.) rewrote the above equation to solve for the minimum size drill collars needed to ensure the running of their casing. Min. Drill Collar OD= 2 (Casing Coupling O.D.) - Bit O.D. This is the minimum size drill collar near the bit, but what is the maximum size? Drill collars the same size as the hole would be ideal but this is not practical. Clearance is needed for circulation of drilling fluid and fishing, should the drill collars become stuck. (See Table D1-10, which shows ideal drill collar sizes based on the Hock equation and the ability to fish them out of the hole.)

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Before selecting drill collars, it is always a good idea to make sure fishing tools are available. If not, you may need to bring fishing tools into the area or reduce drill collar size to match the fishing equipment that is available.

M. Tapered Drill Collar Strings Experience has shown that too much change in size going from large drill collars to the drill pipe or smaller drill collars can cause rapid fatigue damage and failures. A rule of thumb is to never reduce the diameter more than two inches or the connection more than one size and always run at least one stand of the smaller size.

N. Rig Equipment for Running Drill Collars Having the proper equipment on the rig to make-up and run drill collars is equally as important as selecting the correct size. The following equipment must be checked to match the desired drill collar sizes: rotary table, bushings, insert bowls, slips, safety clamp and tongs. Note: Tables matching this equipment to drill collar sizes can be found in Section P of the Drilling Manual All of this rig equipment must be checked for wear and must be in a good working condition before making-up and running drill collars. This can be a very dangerous operation and all safety precautions should be taken.

O. Drill Collar Weight Needed The following equation can be used to calculate the required drill collar weight: Drill Collar = Bit Weight Required x Safety Factor Weight in Air Buoyancy Factor x Cosine of Hole Angle Example: Requirements: Bit Weight Required = 55,000 lbs. Buoyancy Factor for 12 lb/gal = 0.82 15% Safety Factor = 1.15 Vertical Hole = 0 degrees inclination (Cosine 0 = 1) From the Equation: Drill Collar Weight in Air = 55,000 x 1.15/(0.82) = 77,134 lbs. Example If nine 8-inch drill collars weighing 4,650 lbs. each (total weight of 41,850 lbs), are to be run - how many 6-3/4 inch weighing 3,000 lbs. each would be needed to give 77,134 total air weight? 77,134 - 41,850 = 35,284 lbs. required weight of 6-3/4 drill collars 35,284 divided by 3,000 lbs/each = 11.76 or 12 drill collars Note: This problem can be solved without any calculations by using one of the nomographs (Figure D1-13 or Figure D1-14).

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Figure D1-13 Drilling Weight Planner, 0-35 Kips on Bit

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Figure D1-14 Drilling Weight Planner, 0-70 Kips on Bit

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P. Weight Available in Directional Holes The nomograph makes it possible to select any combination of drill collars and heavy weight drill pipe with any mud weight and any hole angle to make-up the required weight for the bit. For example, enter the nomograph (Figure D1-14) at point A on the bottom left-hand side at 55,000 lb weight on bit. Draw a vertical line up to the zero degree hole inclination line (vertical hole). Draw a horizontal line over to point C, 12 lb/gal drilling mud. Draw a perpendicular line through point C from the top of the page to the bottom. The weight of drill collars in air (77,134 lb) can be read at both the top and bottom at point D. The buoyed weight of all the collars can be read at point E (63,250 lb). This would be the weight of the collars hanging in the elevators with the hole full of mud. Select the 8 inch drill collar line and scale off nine 8 inch drill collars between points 1 and 2. Draw a perpendicular line up to the 6-3/4 inch drill collar line and count the number of 6-3/4 inch drill collar needed between point 3 and 4, at the intersection of the 63/4 inch drill collar line with the perpendicular line that goes through point C. As can be seen, the line goes from 13-1/2 to 25-1/2 for a total of twelve 6-3/4 inch drill collars. This is the same number calculated mathematically. For directional holes, point B would not be 0 degrees but would be the degrees of inclination from vertical anticipated. A directionally drilled hole requires that a correction be made in total drill collar weight, because only a portion of the total weight will be available to the bit (Figure D1-15). Figure D1-15 Bit Weight Available in Directional Holes

Using the equation in Figure D1-15, (P = W x Cos B) for a 45 deg hole:

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P = 0.7071 x W

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for a 60 deg hole: P = 0.5 x W for a 90 deg hole: P = 0 x W = 0 Cos Q = P/W Where : Deg. Inclination W = total weight P = partial weight available for bit P = W x Cos Q From the equation, in a 60 degree hole deviation, only half of the drill collar weight is available for the bit, so twice as many drill collars would be required over the number needed in a vertical hole, to load the bit with the same weight, without placing some of the drill pipe in compression. A safety factor of 15% is built into the nomograph, so no additional weight adjustment is necessary. The drilling weight planner shows the available weight for the bit, but should not be confused with the actual weight on the bit. Once the driller tags bottom, with the pump running, the amount of indicated weight slacked off is the actual drilling weight. When only a fixed number of drill collars are available, the nomograph can be worked backwards to determine the amount of drilling weight available for the bit. When drilling high angle holes, it is possible to use less than the 15% safety factor on the chart, as the drill pipe will lie on the low side of the hole, and thus requires a greater compressive load to cause a helical buckle.

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D2. Drill Collars: Care And Maintenance I. Recommended Drill Collar Care And Maintenance A. Picking Up Drill Collars 1) Bail type cast-steel thread protectors provide a means of lifting the collar into the "V" door and protecting the shoulders and threads. Remember that the pin should be protected. 2) Connections should be cleaned thoroughly with a solvent and wiped dry with a clean rag. Inspect carefully for any burrs or marks on the shoulders. 3) A thread compound containing 40-60% by weight of finely powdered metallic zinc or 60% by weight of finely powdered metallic lead with not more than 0.3% total sulfur by weight, should be applied thoroughly to all threads and shoulders. Note: New compounds without lead or zinc are being used today. When using these thread compounds, be sure to correct the make-up torque depending on the friction factor as explained in API RP 7A1. 4) Lift sub pins should be cleaned, inspected, and lubricated on each trip. If these pins have been damaged and go unnoticed, they will eventually damage all of the drill collar boxes.

B. Initial Make Up 1) A new drill collar connection should be very carefully lubricated. Any metal to metal contact may cause galling. 2) Good rig practice is to "walk in" the drill collar joint using chain tongs. Some experienced drillers will "walk in", make up, break out and relubricate a new connection on the initial make up. After the drill collar is broken in, a chain may be used to spin in the drill collars if the crew is careful not to get the chain caught between the shoulders. A drill collar spinner may also be used at a slow RPM.

C. Torque Control 1) Torque is the measure of the amount of twist you apply to two members as you screw them together. The product of the tong ann length in feet and the line pull in pounds is foot-pounds of torque.

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2) A recently calibrated line-pull measuring device should be used in making up drill collars. It is important that the line-pull be measured when the line is at right angle (90 degrees) to the tong handle, if the tong arm is to be fully effective, Figure D2-1 and Figure D2-2. Figure D2-1 Fully Effective Tong Arm

EFFECTIVE TONG ARM TORQUE = 4 ft x 3,000 lb = 12,000 ft-lb 3) With a 4 foot tong arm and 3,000 lb line pull at the end of the tong, you produce 4 ft times 3,000 lbs, or a total of 12,000 ft-lbs of torque, when measured at 90 degrees, Figure D2-1.

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Figure D2-2 Ineffective Tong Arm

INEFFECTIVE TONG ARM TORQUE = 3 ft x 3,000 lb = 9,000 ft-lb 4) When the line pull is not measured at 90 degrees, the same tong length / line pull combination will yield less torque, Figure D2-2. The examples (1 through 15, below) show various hook-ups and how to measure and figure the torque applied. 5) When applying line-pull to the tongs, apply a long steady pull rather than jerking the line.

D. Rig Maintenance of Drill Collars 1) It is a good practice to break different connections on each trip, giving the crew an opportunity to look at each pin and box every two or three trips. Inspect the shoulders for galls, and possible "wash outs". 2) Thread protectors should be used on both pin and box when laying the drill collars down.

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3) Before storing, the drill collars should be cleaned, shoulder refaced with a shoulder refacing tool if necessary, fins removed and shoulders rebeveled, and a good rust preventative applied.

E. Field Inspection of Drill Collars The purpose of drill collar field inspection is to keep connections in service as long as possible and at the same time minimize down hole failures. This practice has been exceptionally successful in accomplishing both of these goals. The reasons: Fatigue is usually a slow process, therefore, frequency of inspection intervals does not need to be so often as to become impractical. The interval of time between such inspections may best be determined from experience. A one month interval is fairly typical; however, adjustments should be considered depending on how many cracks are found or if failures continue to occur in the hole. Ideally, when one to three cracks are found, the inspection interval is about right. If more than three cracks are found, inspections should be more often. If no cracks are found, inspections should be reduced. Fatigue cracks will almost always occur in a small localized area in the thread toots. Very close attention can be given these critical areas to detect cracks and the work can still be done at a reasonable cost. When an indication of a crack is found, it should be polished with a very fine grinding disc and re-inspected. Sometimes rolled over metal will give an indication of a crack. If it is a crack it can be removed by grinding but do not grind below the depth of the adjacent thread. This will enable the collars to remain in service for a little longer if no other collars are available. Drill collar inspection should be more than just looking for cracks. Thread profile should be checked with a profile gage to detect stretched pins and worn threads. Boxes should be checked for swelling and shoulders should be inspected for leaks or conditions that may cause leaks. Minor repairs can be performed in the field to keep the collars running. Shoulders can be polished with refacing tools if the damage is not too severe. Small indentations on the shoulder are not disastrous as long as they are not continuous across the face. Remember, this shoulder surface is the only seal. Any raised places cannot be tolerated. Fins, burrs and small galls can be removed with a small grinder or file.

F. Recommended Make-Up Torque Recommended make-up torque values for rotary shouldered drill collar, RS DC, connections are listed in Table D2-1.

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TD2-1a MU Torque for RS DC Connections, API NC23 -- 3-1/2 MO

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TD2-1b MU Torque for RS DC Connections, 3-1/2 IF -- 4-1/2 MO

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TD2-1c MU Torque for RS DC Connections, 4-1/2 H90 -- 6-5/8 API Reg

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TD2-1d MU Torque for RS DC Connections, 6-5/8 H90 -- 7-5/8 API Reg

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TD2-1e MU Torque for RS DC Connections, 7-5/8 H90 -- 8-5/8 H90

Notes on Tables TD2-1* * NOTE 1: Torque figures preceded by an asterisk indicate that the weaker member for the corresponding outside diameter (OD) and bore is the BOX. For all other torque values the weaker member is the PIN. * NOTE 2: In each connection size and type group, torque values apply to all connection types in the group, when used with the same drill collar outside diameter and bore, i.e. 2-1/8 API IF, API NC 26, and 2-7/8 Slim Hole connections used with 3-1/2 x 1-1/4 drill collars all have the same minimum make-up torque of 4600 ft. lb., and the BOX is the weaker member. 1) Basis of calculations for recommended make-up torque assumed the use of a thread compound containing 4060% by weight of finely powdered metallic zinc or 60% by weight of finely powdered metallic lead, with not more than 0.3% total active sulfur, applied thoroughly to all threads and shoulders and using the modified Screw Jack formula in Appendix A, paragraph A.8 of API RP 7G, and a unit stress of 62.500 psi in the box or pin, whichever is the weaker. 2) Normal torque range is the tabulated value plus 10%. Higher torque values may be used under extreme conditions. 3) Make-up torque for 2-7/8 PAC connection is based on 87,500 psi stress and other factors listed in footnote 1). 4) Make-up torque for H-90 connection is based in 56,200 psi stress and other factors listed in footnote 1). These values are listed for various connection styles and for commonly used drill collar OD and ID sizes. The table also includes a designation of the weak member (pin or box) for each connection size and style. For a 6-3/4 OD X 2-13/16 ID with NC50 connections, the table indicates a torque of 32,000 ft-lbs. Type Conn.

O.D.

2-1/4

NC50

6-3/4

36,000 35,500 32,000

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2-1/2

2-13/16

3 30,000

3-1/4 26,500

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It should be emphasized that the torque values shown in the tables are minimum requirements. The range of torque values is the tabulated figure plus 10%. From the example above, the required torque range is {32,000 + (32,000 x 10%)} or 32,000 to 35,200 ft-lbs. HERE IS THE WAY TO FIGURE THE DRILL COLLAR MAKE-UP TORQUE YOU NEED As discussed in Section D2-C, you must use the proper amount of make-up torque and this amount must be measured. There are two steps that must be worked out for all hook-ups: Step #1 Look up, in the appropriate Torque Tables, D2-1, above, and find the amount of make-up torque recommended for your size drill collars and type of connections. Step #2 Divide this amount by the number of feet* in the effective length of your tong arm. This will give you the total line pull at the end of the arm. * For 36" Tongs, Divide by 3 * For 48" Tongs, Divide by 4 * For 54" Tongs, Divide by 4.5 Example:

EXAMPLE: For collars with 6-3/4" O.D. X 2-13/16 I.D. and 5" E.H. connections, the tables recommend 32,000 foot pounds of make-up torque. Let's say your "effective" tong arm length is 48." See Figure - An Example of a Tong Arm 32,000 divided by 4 = 8,000 (pounds of line pull) The 8,000 pounds of line pull is the total pull required on the end of your 48" tong. This may or may not be the amount of line pull reading on your Torque Indicator, as this depends on the location of the indicator in your hookup.

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Following are 15 examples of hook-ups used to make-up drill collar connections. Select the one that is best for you and follow the steps outlined. Figure Tong Arm - Example 1

The amount of cathead pull will be the same as the line-pull reading on your Torque Indicator. Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. The answer is pounds pull reading for the linepull indicator when in this position. Figure Tong Arm - Example 2

The amount of cathead pull will be the same as the line-pull reading on your Torque Indicator.

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Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. The answer is pounds pull reading for the linepull indicator when in this position. Figure Tong Arm - Example 3

The amount of cathead pull will be the same as the line-pull reading on your Torque Indicator. Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. The answer is pounds pull reading for the line-pull indicator when in this position. Figure Tong Arm - Example 4

The amount of cathead pull will be 1/2 of the line-pull reading on your Torque Indicator.

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Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. The answer is pounds pull reading for the line-pull indicator when in this position. Figure Tong Arm - Example 5

The amount of cathead pull will be 1/3 of the line-pull reading on your Torque Indicator. Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. The answer is pounds pull reading for the line-pull indicator when in this position.

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Figure Tong Arm - Example 6

The amount of cathead puli will be 1/2 of the line-pull reading on your Torque Indicator. Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. The answer is pounds pull reading for the line-pull indicator when in this position.

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Figure Tong Arm - Example 7

The amount of cathead pull will be 1/3 of the line-pull reading on your Torque Indicator. Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. The answer is pounds pull reading for the line-pull indicator when in this position.

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Figure Tong Arm - Example 8

The amount of cathead pull will be the same as the line-pull reading on your Torque Indicator. Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. Step No. 3 Divide this by 2. This will be the pounds pull reading for the line-pull indicator when in this position. Figure Tong Arm - Example 9

The amount of cathead pull will be the same as the line-pull reading on your Torque Indicator.

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Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. Step No. 3 Divide this by 2. This will be the pounds pull reading for the line-pull indicator when in this position. Figure Tong Arm - Example 10

The amount of cathead pull will be the same as the line-pull reading on your Torque Indicator. Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. Step No. 3 Divide this by 2. This will be the pounds pull reading for the line-pull indicator when in this position.

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Figure Tong Arm - Example 11

The amount of cathead pull will be 2/3 of the line-pull reading on your Torque Indicator. Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. Step No. 3 Divide this by 2. This will be the pounds pull reading for the line-pull indicator when in this position.

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Figure Tong Arm - Example 12

The amount of cathead pull will be the same as the line-pull reading on your Torque Indicator. Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. Step No. 3 Divide this by 3. This will be the pounds pull reading for the line-pull indicator when in this position.

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Figure Tong Arm - Example 13

The amount of cathead pull will be 1/2 of the line-pull reading on your Torque Indicator. Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. Step No. 3 Divide this by 3, and multiply by 2. This will be the pounds pull reading for the line-pull indicator when in this position.

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Figure Tong Arm - Example 14

The amount of cathead pull will be 1/4 of the line-pull reading on your Torque Indicator. Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. Step No. 3 Divide this by 5, and multiply by 4. This will be the pounds pull reading for the line-pull indicator when in this position.

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Figure Tong Arm - Example 15

The amount of cathead pull will be 1/3 of the line-pull reading on your Torque Indicator. Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. The answer is pounds pull reading for the linepull indicator when in this position. GIVE THIS SOME THOUGHT... Each torque measuring device has a limit for the total amount of line pull it can accurately measure. Know the limit of the instrument you are using and work within the recommended range.

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Multiple line hook-ups can provide many times the normal make-up line pull. Great care should be taken to see that the lines do not become crossed, twisted or fouled. When it comes time for the "Big Pull", be sure everyone is in the clear. * Know the limit of your tongs and do not exceed the manufacturer's recommended capacity.

G. Drill Collar Repairs 1) Connections Eventually all drill collar connections will need to be repaired, even when they have received proper care, because they are a sacrificial element. Connections are weaker than the body of a drill collar, so therefore, most of the bending takes place in the connections, which causes fatigue cracks. When a connection is cracked, it must be cut off behind the crack before rethreading. When drill collars are re-threaded in a field repair shop, they should receive the same inspection they received initially by the manufacturer. This would require the use of ring and plug gauges, lead and taper gauges, profile gauge and dimensional checks of all pertinent dimensions shown in API Spec. 7. All newly-machined connections must be coated with zinc or manganese phosphate to prevent galling. 2) Stub Welding Eventually, drill collars will become too short to stand back in the derrick, at,er being re-threaded several times. This problem can be corrected by stub welding new material on the ends. A minimum of 30" should be added. If a collar is to be stubbed on the box end with slip and elevator recesses, it should have a minimum of 66" added so the slip and elevator grooves will not be machined in the stub weld. The same connections can be machined on the drill collar at, er stubbing if the outside diameter is not worn too much (not below 2.25 to I bending strength ratio, B.S.R.). If the collars are worn below this ratio, larger diameter material should be stubbed on the drill collar to give the connections a new B.S.R. of 2.75-3.00 to 1. Another alternative would be to reduce the connections by one size. When this is done, in some cases, the bore may be too large which would make the pin too weak. If this is the ease, material with a smaller bore should be stubbed to the pin end. 3) Reference Material a. W. R. Garrett and Gerald E. Wilson, "Proper Field Practices for Drill Collar Strings" 49th annual Fall meeting of SPE-AIME, Houston, Texas, October 6-9, 1974, SPE-5124. b. Gerald E. Wilson, "Factors to Consider for Selecting the Proper Bottom Hole Drilling Assembly", 1979 Drilling Technology Conference IADC, March 6-8, 1979, Denver, Colorado. c. D.W. Brinegar "What is the Condition of Your Downhole Tools and How Are They Being Repaired?", 1989 SPE/IADC 18702 Drilling Conference, February 28 - March 3, 1989, New Orleans, Louisiana. d. API Specification 7, Thirty-Seventh Edition, August 1, 1990. e. API Recommended Practice 7G, RP-7G, Fourteenth Edition, August 1, 1990. f. Sii Drilco Drilling Assembly Handbook, Latest Edition.

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D3. Kellys: Specifications I. Specifications A. Size, Type and Dimension Kellys are manufactured with one of two drive configurations, square or hexagonal. Dimensions are listed in Tables D3-1 and Tables D3-2.

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Table D3-1a Hexagon Kellys - Drive Section

Table D3-1b Hexagon Kellys - Upper Box Connection

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Table D3-1c Hexagon Kellys - Lower Box Connection

Figure D3-1 Hexagon Kellys

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Table D3-2a Square Kellys - Drive Section

Table D3-2b Square Kellys - Upper Box Connection

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Table D3-2c Square Kellys - Lower Box Connection

Figure D3-2 Square Kellys

Notes on Table D3-2 Square kellys are furnished as forged or machined in the drive section. Hexagonal or fully machined square kellys are machined from full length quenched and tempered round bars.

B. Selection of Type and Size The following criteria should be considered in selecting square or hexagonal kellys: 1) It may be noted from Table D3-3 that the drive section of the hexagonal kelly is stronger than the drive section of the square kelly when the appropriate kelly is selected for a given casing size.

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Table D3-3 Strength of Kellys

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Notes on Table D3-3 (1) All values have no safety factor and are based on 110,000 psi minimum tensile yield strength for connections and 90,000 psi minimum tensile yield for the drive section. Shear strength is based on 57.7% of the minimum tensile yield strength. (2) Clearance between protector rubber on kelly saver sub and casing inside diameter should also be checked. (3) Tensile area calculated at root of thread 3/4 inch from pin shoulder. Example: A 4-1/4 inch square kelly or a 5-1/4 inch hexagonal kelly would be selected for use in 8-5/8 inch casing. 1) It should be noted, however, that the connections on these two kellys are generally the same and unless the bores (inside diameters) are the same, the kelly with the smaller bore could be interpreted to have the greater pin tensile and torsional strength. 2) For a given tensile load, the stress level is less in the hexagonal section. 3) Due to the lower stress level, the endurance limit of the hexagonal drive section is greater in terms of cycles to failure for a given bending load. 4) Surface decarburization (decarb) is inherent in the as forged square kelly which further reduces the endurance limit in terms of cycles to failure for a given bending load. Hexagonal kellys and fully machined squares have machined surfaces and are generally free of decarb in the drive section. 5) It is impractical to remove the decarb from the complete drive section of the forged square kelly; however, the decarb should be removed from the corners in the fillet between the drive section and the upset to aid in the prevention of fatigue cracks in this area. Machining of square kellys from round bars could eliminate this undesirable condition.

C. Properties of Kellys Values in Tables D3-3 and D4-2 were calculated from formulas listed in Par. A.7, A.11 and A.12, Appendix A of API RP 7G. Also see Figure D3-1 Hexagon Kellys, and Figure D3-2 Square Kellys

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D4. Kellys: Care And Maintenance I. Care And Maintenance A. Drive Bushing Fit The life of the drive section is directly related to the kelly fit with the kelly drive. A square drive section normally will tolerate a greater clearance with acceptable life than will a hexagonal section. A diligent effort by the rig personnel to maintain minimum clearance between the kelly drive section and the bushing will minimize this consideration in kelly selection. New roller bushing assemblies working on new kellys will develop wear patterns that are essentially flat in shape on the driving edge of the kelly. Wear patterns begin as point contacts of zero width near the corner. The pattern widens as the kelly and bushing begin to wear until a maximum wear pattern is achieved. The wear rate will be the least when the maximum wear pattern width is achieved. Figure D4-1 illustrates the maximum width flat wear pattern that could be expected on the kelly drive flats if the new assembly has clearances as shown in Table D4-1. Figure D4-1 Maximum Wear Pattern Width on Kellys

NOTE on Figure D4-1: The Maximum Wear Pattern Width is the average of the Wear Pattern Widths based on calculations using minimum and maximum clearances and contact angles in Table D4-1 and is accurate within 5%.

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Table D4-1 Contact Angle between Kelly and Bushing for Wear Pattern

The information in Table D4-1, Figure D4-1 and Figure D4-2, may be used to evaluate the clearances between kelly and bushing.

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Figure D4-2 Wear Pattern on Kellys

This evaluation should be made as soon as a wear pattern becomes apparent after a new assembly is put into service. NOTE: Drive Edge will have a wide flat pattern with small contact angle. Example: At the time of evaluation, the wear pattern width for a 5-1/4 inch hexagonal kelly is 1.00 inches. This could mean one of two conditions exist: 1) If the contract angle is less than 8 degrees, 37 minutes, the original clearances were acceptable. The wear pattern is not fully developed. 2) If the contact angle is greater than 8 degrees, 37 minutes, the wear pattern is fully developed. The clearance is greater than is recommended and should be corrected.

B. Repair Techniques for extending life of kellys include remachining drive sections to a smaller size and reversing ends. 1) Remachining: Before attempting to remachine a kelly, it should be fully inspected for fatigue cracks and also dimensionally checked to assure that it is suitable for remilling. The strength of a remachined kelly should be compared with the strength of the drill pipe with which the kelly is to be used. (Reference Table D4-2 for drive section dimensions and strengths.)

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Table D4-2 Strength of Remachined Kellys

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Notes on Table D4-2 2) Reversing Ends: Usually both ends of the kelly must be butt welded (stubbed) for this to be possible as the original top is too short and the old lower end is too small in diameter for the connections to be reversed. the welds should be made in the upset portions on each end to insure the tensile integrity and fatigue resistance capabilities of the sections. Proper heating and welding procedures must be used to prevent cracking and to recondition the sections where welding has been performed.

C. Inspection The following inspection procedure for used kellys is recommended: 1) Follow all steps listed in Section D2-E for drill collar inspection procedure. 2) Examine junction between upsets and drive section for cracks. 3) Check corners of drive section for narrow wear surface particularly on hexagonal kellys. If wear surface does not extend at least 1/3 across flat, the kelly drive bushings should be adjusted if possible and/or examined for wear. See Figure D4-1 for comparison of wear pattern width to maximum possible for new kellys. NOTE on Figure D4-1: The Maximum Wear Pattern Width is the average of the Wear Pattern Widths based on calculations using minimum and maximum clearances and contact angles in Table D4-1 and is accurate within 5%. 4) Kelly straightness can be checked either of two ways: (a) By watching for excessive swing of the swivel and traveling block while drilling, or (b) By placing square kellys on level supports (one at each end of drive section), stretching a heavy cord from one end ora vertical face of the square to the other, measuring deflection, rolling kelly 90 degrees, and repeating procedure. On hexagon kellys, use the same method except kelly will need to be placed in 120 degree V-blocks so side face of drive section is vertical and deflection measurements taken on three successive sides (turning kelly through 60 degrees each time).

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D5. Drill Stem Subs: Specifications I. Class And Type Drill-stem subs are furnished in the classes and types shown in Table D5-1 and Figure D5-1.

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Table D5-1 Drill Stem Sub Applications

Figure D5-1 Drill Stem Subs

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Figure D5-2 Tool Joint Dimensions for Drill Pipe

Table D5-2 Surface Hardness for New Steel Drill Stem Subs

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Table D5-3b TJ Dim. for E, X, G, and S DP 4-1/2 IEU -- 5 IEU

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Table D5-3c TJ Dim. for E, X, G, and S DP 5 IEU -- 5-1/2 IEU

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Notes for Table D5-3 Table D5-4 Roller Rock Bit Connections

Table D5-5 Drag Blade Rock Bit Connections

II. Dimensions For Type A & B Subs A. Connections, Bevel Diameters and Outside Diameters: The connections, bevel diameters and outside diameters should conform to the applicable sizes, styles, dimensions and tolerances listed in the following Tables:

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Subs Connecting to Kellys: Tables D3-1 and D3-2 Table D3-1a Hexagon Kellys - Drive Section Table D3-1b Hexagon Kellys - Upper Box Connection Table D3-1c Hexagon Kellys - Lower Box Connection Table D3-2a Square Kellys - Drive Section Table D3-2b Square Kellys - Upper Box Connection Table D3-2c Square Kellys - Lower Box Connection Table D5-6 Diamond and PDC Rock Bit Connections

Note for Table D5-6 * Bevel diameter is the outer diameter of the contact face of the RSJ.

B. Inside Diameters: The inside diameter (d) of a sub should be equal to the inside diameter of the applicable connecting member with the smaller size and style connection.

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C. Inside Bevel Diameter: To prevent the hang-up of wire line tools on the end of the pin and to minimize mud flow turbulence through the connections, the inside diameter at the pin end of the sub should be beveled. The diameter of the bevel should be 1/ 8 to 3/16 inches larger than the inside diameter of the drill stem member connecting to the sub's pin end.

D. Length: Recommended lengths and tolerances are shown in Figure D5-1.

E. API Stress Relief Features: Laboratory fatigue tests and tests under actual service conditions have demonstrated the beneficial effects of stress-relief contours at the pin shoulder and at the base of the box thread. It is recommended that, where fatigue failures at points of high stress are a problem, relief grooved pins and bore backed boxes be provided and that the roots of the threads be cold worked after gaging to API specifications. Pin and box stress relief features should conform to the dimensions shown in Table D1-6 and Figure D1-2.

III. Dimensions For Type C (Swivel) Subs A. Connections, Bevel Diameters and Outside Diameters: Swivel subs have pin-up and pin-down, (both left hand) rotary shouldered connections. The lower connection size, style and bevel diameter (DB) conforms to the applicable sizes, styles, dimensions and tolerances specified in Tables D3-1 and D3-2 for upper kelly box connections. The upper connection is the size and style of the swivel stem box connection, i.e., 4-1/2, 6-5/8, 7-5/8 API Regular. the subs outside diameter and tolerances conform to the larger of either the kelly upper box connection or the swivel stem box connection outside diameter.

B. Inside Diameter: The maximum inside diameter (d) is the largest allowed for the kelly connection specified in Tables D3-1 or D3-2. In the case of step bored subs in which the bore through the upper pin is larger than the bore through the lower pin, the bore through the upper pin should not be so large as to cause the upper pin to have a lower tensile strength or lower torsional strength than the lower pin as calculated per Paragraph A.8.1 of the current edition of API RP-7G.

C. Inside Bevel Diameter: The inside diameter at each pin end should be beveled. An inside bevel diameter (dB) 3/16 to 5/16 inch larger than the sub's inside diameter has provided satisfactory performance.

D. Length: To provide adequate gripping space after minor thread repairs, new swivel subs should have a minimum tong space of 8 inches.

IV. Mechanical Properties Of Drill Stem Subs The material used to manufacture drill stem subs should have the same mechanical properties as the material used to manufacture drill collars. These material requirements are specified in Table D1-2. The surface hardness of the "as manufactured" diameter (Dr) of type B subs shall be measured per the current edition of ASTM A-370 and shall conform to the requirements listed in Table D5-2.

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V. Kelly Saver Subs A. Purpose: Kelly saver subs are intended for use between the lower end of the kelly and the upper end of the drill pipe. They serve as the make/break connection as drill pipe is added to the drill string. Rubber protectors installed into an OD groove are used to protect the inside of the BOP's and upper casing from abrasive wear of the drill pipe tool joints.

B. Sizes: Kelly saver subs are furnished to match the OD of the lower end of kelly and drill pipe tool joints.

C. Connections: Kelly saver subs are furnished with box up and pin down right hand rotary shouldered connections. The box connection must be the same as the lower kelly connection and the pin connection must match the drill pipe.

D. Rubber Protectors: Rubber protectors are furnished as slip-on types or as latch-on types. Protector manufacturers provide many different sizes to match the casing I.D. Depending on the size protector selected, the manufacturer should be consulted for groove dimensions.

E. Material: Kelly saver subs are manufactured from drill collar material. Therefore, the material must meet the mechanical specifications as defined in Table D1-2. NOTE: The kelly saver sub bore should never be larger than the bore of the kelly that it is used with.

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D6. Kelly Valves: Specifications Purpose: Kelly valves are manually operated valves run above and/or below the kelly to shut off back-flow in the drill stem in the case of a well kick.

I. Upper Kelly Cocks An upper kelly cock is intended for use between the lower end of the swivel sub and the upper end of the kelly. 1) Size: Upper kelly cocks are available for either square kellys or hexagon kellys and in the sizes as shown in Tables D6-1 and D6-2 respectively. 2) Connections: Upper kelly cocks are furnished with box up and pin down (both left hand) rotary shouldered connections in the size and style shown in Tables D6-1 and D6-2.

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Table D6-1 Upper Kelly Cocks for Square Kellys

Table D6-2 Upper Kelly Cocks for Hexagon Kellys

3) Tong Space and OD: On new valves, a tong space of 8 inches minimum length and with an outside diameter as shown in Figure D6-1 and column 4 and 5 of Tables D6-1 and D6-2 is recommended.

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Figure D6-1 Upper Kelly Cock

Figure D6-2 Lower Kelly Cock

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Figure D6-3 Automatic Mud Saver Sub

The exact location of the 8 inch long tong space is at the discretion of the manufacturer. 4) Outside Diameters, Bores and Bevel Diameters: the outside diameters, bores and bevel diameters on each end of upper kelly cocks conform to the dimensions shown in Tables D6-1 and D6-2. The OD and shape of the kelly cock body will vary with the manufacturer. 5) Pressure Rating: Upper kelly cocks are furnished in 5,000, 10,000 and 15,000 psi maximum working pressure ratings. 6) Hydrostatic Shop Testing: API requires that licensed manufacturers of upper kelly cocks subject each valve to a hydrostatic shop test pressure as shown in Table D6-3. Table D6-3 Hydrostatic Shell Test Pressure

The required manufacturer's hydrostatic shop pressure test consists of:

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A. A shell test at the appropriate hydrostatic shop test pressure of Table D6-3 with the valve in the open position, and B. A seat test at the appropriate working pressure of Table D6-3 applied to the pin end with the valve closed and with the box end open to the atmosphere. 7) Working Temperature: Upper kelly cocks have a working temperature rating of 180 degrees F maximum.

II. Lower Kelly Cocks A lower kelly cock (typical shown in Figure D6-2) is intended for use between the lower end of the kelly and the upper end of the drill pipe or upper end of the kelly saver sub. 1) Size: Lower kelly cocks are available for either square or hexagon kellys, and in the sizes shown in Tables D6-4 and D6-5 respectively. Table D6-4 Lower Kelly Cocks for Square Kellys

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Table D6-5 Lower Kelly Cocks for Hexagon Kellys

2) Connections: Lower kelly cocks are furnished with box up and pin down (both right hand) rotary shouldered connections in the sizes and styles shown in Tables D6-4 and D6-5. Notes for Table D6-4 and D6-5: 1) Obsolete connections are shown in parentheses in Tables D6-4 and D6-5. 2) Bevel Diameters shown in parentheses were optional with the manufacturer until June 1986, at which time 6-1/ 16 became standard. For the upper box and lower pin connections on lower kelly cocks used with 4-1/4 and 5-1/4 square kellys and 5-1/4 and 6 hexagonal kellys, two sizes and styles of connections are standard. the purchase order should state the size and style desired. 3) Tong Space: New lower kelly cocks are furnished in lengths sufficient to provide a minimum tong space of 8 inches after the box and pin connections have been recur at least once. 4) Outside Diameters: Lower kelly cocks may be furnished with outside diameters as large as operations in the well permit, in order to produce kelly cocks with a minimum strength in torsion, and in tension, at least as great as the respective strengths of the tool joints used in the string. 5) Pressure Rating: Routinely lower kelly cocks are furnished with 5000 psi maximum pressure ratings. Designs for higher working may be acquired from some manufacturers. 6) Hydrostatic Shop Testing: API requires that licensed manufacturers of lower kelly cocks subject each value to a 10,000 psi shop hydraulic test pressure. If higher test pressures are required, the manufacturer should be contacted to arrange the testing. the required manufacturers hydrostatic shop pressure test consists of: A. A shop shell test at the appropriate test pressure, with the valve in the open position, and B. A shop seat test at the appropriate working pressure applied to the pin end with the valve closed and the box end open to the atmosphere. 7) Working Temperature: the working temperature rating for lower kelly cocks is 180 degrees F.

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III. Automatic Mud Saver Valves Mud saver valves (typical shown in Figure D6-3) are proprietary valves designed to prevent the drilling mud contained in the kelly from running from the kelly when the lower connection is unscrewed. They are intended for usc between the lower end of the kelly and the upper end of the drill pipe.

A. Sizes: Mud saver valves are available in 4-3/4" and 6-1/2" OD's.

B. Connections: Mud saver valves are furnished with box up and pin down right hand rotary shouldered connections. Standard sizes and styles of connections are the NC38 (3-1/2" IF) on the 4-3/4" OD size and the NC50 (4-1/2" IF) on the 6-1/2" OD size.

C. Pressure Rating: Automatic mud saver valves are not designed to hold pressure from kicks in the drill stem. A back flow feature is designed into the valve to permit automatic bleed-off of pressure in the drill stem. Notes for TABLE D6-5 1) Obsolete connections are shown in parentheses in Table D6-4 and Table D6-5. 2) Bevel diameters shown in parentheses were optional with the manufacturer until June 1986, at which time 6-1/ 16 became standard.

IV. Kelly Saver Subs A. Purpose: Kelly saver subs are intended for use between the lower end of the kelly and the upper end of the drill pipe. They serve as the make/break connection as drill pipe is added to the drill string. Rubber protectors installed into an OD groove are used to protect the inside of the BOP's and upper casing from abrasive wear of the drill pipe tool joints.

B. Sizes: Kelly saver subs are furnished to match the OD of the lower end of kelly and drill pipe tool joints.

C. Connections: Kelly saver subs are furnished with box up and pin down right hand rotary shouldered connections. The box connection must be the same as the lower kelly connection and the pin connection must match the drill pipe.

D. Rubber Protectors: Rubber protectors are furnished as slip-on types or as latch-on types. Protector manufacturers provide many different sizes to match the casing I.D. Depending on the size protector selected, the manufacturer should be consulted for groove dimensions.

E. Material: Kelly saver subs are manufactured from drill collar material. Therefore, the material must meet the mechanical specifications as defined in Table D1-2. NOTE: The kelly saver sub bore should never be larger than the bore of the kelly that it is used with.

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D-7 Specifications Of Heavy Weight Drill Pipe Heavy weight drill pipe was developed in the mid 1960's as an intermediate weight drill string member. It was originally developed for three reasons: 1) As a transition member to be run between drill pipe and drill collars. 2) As a flexible weight member to be run in directional drilling. 3) As a weight member on small rigs, drilling small diameter holes. More recently with the advent of horizontal drilling, it has found a new application, being used in the curved portion of the hole below the drill collars. Heavy weight drill pipe is normally manufactured by attaching high alloy tool joints to a lower alloy tube. See Figure D7-1. Figure D7-1 Heavy Weight Drill Pipe

This attachment is normally done by inertia welding (although other methods have been used). Additionally, some heavy weight pipe has been produced using drill collar bar material and turning the bar to the finished dimensional profile. It is manufactured primarily in three sizes: 3-1/2'', 4-1/2'', and 5". Most manufacturers also make 4" size, with some 5-1/2" and even 6-5/8" size. (The size represents the tube diameter.) While being similar in appearance to drill pipe, heavy weight has the following different dimensional characteristics. 1) The tube wall is heavier, about 1" thick in most sizes. 2) The tool joint(s) are longer. 3) The tube section has a larger diameter at mid-length to protect the pipe from wear. 4) Some manufacturers provide spiral grooving in this larger section. It is said that this promotes hole cleaning and, resistance to differential wall sticking, among other advantages. 5) Hardbanding is normally standard on both box and pin tool joints with additional hardbanding on the center wear section.

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6) API pin stress relief features and API boreback box stress relief features are normally standard on sizes above 3-1/2". Most manufacturers offer the following recommendations for running heavy weight pipe: When run in vertical holes for weight: 1) Run the necessary number of joints to provide the required weight plus enough more joints to insure the transition point stays in the heavy weight pipe. 2) Do not run in compression where the hole size is more than 4" larger than the heavy weight tool joint size. When run in the transition zone between pipe and collars: 1) Run a minimum of 18 to 21 joints. 2) Utilize the manufacturers recommendations for the maximum drill dollar size to be run below the heavy weight. When run in directional holes for weight: 1) Run the necessary number of joints to achieve the desired weight on bit. (It is not uncommon to run as many as 60 joints in this application.)

Care and Maintenance of HWDP A. Inspection In addition to the normal inspection for connection fatigue cracks, users should also inspect the transition area between the tool joint and tube for evidence of fatigue cracking. In certain applications, fatigue cracks have been known to appear in this area.

B. Maintenance Users should maintain heavy weight drill pipe as they would any other tubular member. Connections should be inspected frequently and recut, if necessary. Wear of the tool joint and center upset area should be monitored. Each manufacturer normally establishes recommended wear limits for these areas. Some manufacturers recommend rebuilding the outside diameter of the tool joint by welding to restore this area to useable condition. Insure that the manufacturers recommendations are strictly adhered to when adopting this practice. Welding by unqualified individuals can result in disastrous results.

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D8 - Glossary of Drill String Terms Bottom Hole Assembly: Assembly composed of the bit, stabilizers, reamers, drill collars, subs, etc., used at the bottom of the drill string. Sometimes abbreviated as BHA. Drill Collars: Round, square, and triangular drill stem elements utilized to provide a load on the bit for the purpose of drilling. Drill Stem: The entire drilling assembly from the swivel to the bit composed of the kelly, drill string, subs, drill collars, and other downhole tools such as stabilizers and reamers. This assembly is used to rotate the bit and carry the drilling fluid to the bit. Drill String: The drill pipe with tool joints attached. Several sections or joints of drill pipe joined together. Fatigue Failure: A failure of a metal which originates as a result of repeated or fluctuating stresses having maximum values less than the tensile strength of the material. Hard Banding: A hard metal deposited on tool joints and other drill stem parts to resist abrasion from contact to the wall of the borehole. Heavy Weight Drill Pipe: Drill pipe fabricated with thick wall tube which is frequently used in place of drill collars to apply weight on the drill bit in small diameter holes. Handles like normal drill string in drilling operations. Used in the transition zone between the stiffer drill collars and limber drill string. Used in direction wells to reduce friction drag and to add weight to the bit. Kelly: The square or hexagonal shaped steel pipe connecting the swivel to the drill string. The kelly moves through the rotary table and transmits torque to the drill stem. Kelly Cock, Upper: A valve immediately above the kelly that can be closed to confine pressures inside the drill string. Kelly Cock, Lower: A full-opening valve installed immediately below the kelly, with outside diameter approximately equal to the tool joint outside diameter. Valve can be closed to remove the kelly under pressure and can be stripped in the hole for snubbing operations. Yield Strength: The stress level measured at room temperature, expressed in pounds per square inch of loaded area at which material plastically deforms and will not return to its original dimensions when the load is released.

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Chapter E Pipe Handling Equipment

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Table of Contents - Chapter E Pipe Handling Equipment E1. Pipe Handling Equipment .................................................................................................................... E-4 Introduction ........................................................................................................................................ E-4 I. Specifications .................................................................................................................................. E-4 E2. Bushings And Slips ............................................................................................................................. E-9 I. Specifications .................................................................................................................................. E-9 II. Care And Maintenance ................................................................................................................ E-13 E3. Elevators .......................................................................................................................................... E-23 I. Drill Pipe Elevators ........................................................................................................................ E-23 II. Drill Collar Elevators .................................................................................................................... E-25 E4 - Drill Collar Slips and Safety Clamps ................................................................................................ E-30 I. Drill Collar Slips ............................................................................................................................ E-30 II. Drill Collar Safety Clamps ............................................................................................................ E-30 E5. Elevator Links, Block, Hook And Swivel Specifications .................................................................... E-31

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Chapter E Pipe Handling Equipment The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study.

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E1. Pipe Handling Equipment Introduction The hoisting tools and rotary table and/or bushings are closely aligned and will be treated together in this section. Reference is also made to Section B4, Care and Handling of Steel Drill Pipe, for a discussion on damage of pipe caused by worn rotary tables, bushings and slips, and by improper use of slips.

I. Specifications A. Drive Sprocket. The distance between the center of the rotary table and the center of the first row of sprocket teeth shall be 53-1/ 4 in for machines that will pass a 20 in bit or larger. It shall be 44 in for machines that will not pass a 20 in bit, except that, by agreement between the manufacturer and the purchaser, the distance of 53-1/4 in may be used. The distance shall be 65 in for the 49-1/2 in rotary table opening.

B. Rotary Table Pinion-Shaft Extension. Rotary table pinion-shaft extensions shall be furnished in the sizes shown in Table E1-1, as specified on the purchase order, and shall conform to the dimensions and tolerances shown in Table E1-1 and Figure E1-1.

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Table E1-1 Rotary Table Pinion Shaft Extensions

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Figure E1-1 Rotary Table Pinion Shaft Extensions

C. Demountable Rotary Table Sprockets. Demountable rotary table sprockets to be mounted on the rotary table shafts are shown in Table E1-2 and Figure E1-2. The sprockets, single strand and double strand, have one common hub with identical bolt circle, number of bolts, and size of bolts. (See Table E1-2 and Figure E1-2 for shaft details).

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Table E1-2 Demountable Rotary Table Sprockets

Figure E1-2 Demountable Rotary Table Sprockets

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*10-3/4 is maximum hub diameter to allow for chain clearance. **11-1/4 inch counterbore dimension applies to sprockets with minimum number of teeth. This can be increased for sprockets with more than the minimum number of teeth to as much as the dimensions A minus B.

D. Master Bushing. Rotary Table openings for square drive master bushings and for pin drive master bushings shall conform to the requirements of Table E1-3 and Figure E1-3 (based on Section 13, API Spec 7, August 1, 1990). Figure E1-3 Rotary Table Openings

Table E1-3 Rotary Table Openings

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E2. Bushings And Slips I. Specifications A. Kelly Drive Bushings Square drive kelly bushing dimensions and pin drive kelly bushing dimensions shall be shown in Figure E2-1 and Table E2-1 (based on Section 13, API Spec 7, August 1990).

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Figure E2-1a Dimensions and Nomenclature of Master and Pin Drive Bushings

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Figure E2-1b Dimensions and Nomenclature of Master and Square Drive Bushings

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Table E2-1 Master and Kelly Drive Bushing Dimensions

B. Master Bushings Dimensions for square drive master bushings and for pin drive master bushing shall be shown in Figure E2-1 and Table E2-1 (based on Section 13 API Spec 7, August 1990).

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C. Pipe Slips Pipe slips shall have a taper of 4"/ foot on diameter and other suitable dimensions to permit operation in standard master bushings. Figure E2-2 Drill Pipe Slips Taper

II. Care And Maintenance A. Kelly Drive Bushing There are two basic designs of kelly drive bushings -- single and double plane rollers.

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1. In the first design, the drive rollers are in a single plane. Depending on the manufacturer, the kelly bushing may have a split or solid body casing. a. In the split body design, the roller pins are supported in the body journals and clamped by top nuts which bolt the body halves together. To replace the roller assemblies, the cover is removed and the rollers are accessible. b. In a solid cast body, the roller pins are supported by replaceable sleeves. To remove a roller assembly, retaining pins are removed, the roller pin taken out from the side, and the roller removed from the back. 2. The second basic design of kelly drive bushings used two rollers for each driving surface on the kelly. The rollers are stacked one above the other in "cages". All roller pins and bearings are part of this cage assembly. the cages are removable from the bushing body. The two plane roller bushing for hex kellys is adjustable for kelly and bushing wear. The two plane roller bushing for square kellys is not adjustable. 3. There are several aspects of maintenance of the kelly drive bushing which must concern the floor crew. a. Lubrication to reduce wear is the most important aspect of maintenance. As a rule, this is accomplished with a grease gun on fittings built into the bushing. This can be done on each tour or on a daily basis. b. On split body type bushings, it is very important to keep the top nuts tight. This keeps the roller pins from working in the body journal areas. c. Certain adjustments can be made on some two plane roller bushings to compensate for normal wear. In this type bushing, for a hex kelly, roller cages set on a stack of "shims" in the drive bushing body. The number of shims used determines the position of the roller cages on mating tapers between the cages and the bushing body. Each set of shims added or removed changes the working diameter of the kelly bushing by 1/32 of an inch. d. Regardless of the bushing type, it must be inspected periodically for wear. Check with the manufacturer for maintenance and inspection instruction. e. After inspection, certain parts may need to be replaced. These parts can be removed and replaced on the rig floor by the floor crew. See Figure E2-3 for Kelly Bushing Replacement Parts.

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Figure E2-3 Kelly Bushing Replacement Parts

B. Master Bushings Much can be done to prevent cutting, gouging and bottlenecking of drill pipe by proper maintenance of master bushings and rotary slips. This will prevent unnecessary downgrading and discarding of pipe as well as minimizing washouts and other types of downhole failures. The effects of worn rotary tables, master bushings and rotary slips can be seen in Figure E2-4.

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Figure E2-4 Split Master Bushings Wear Points

A similar condition occurs to the bowls and outer hull of a solid or hinged master bushing. Obviously, the drill pipe will be damaged under these circumstances. This is an extreme case; however, the same type of damage can be incurred with less worn equipment.

C. Drill Pipe Slips The right size slips must always be used for the size pipe being handled. Figure E2-5 shows the effects of using the wrong size of rotary slips on the drill pipe.

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Figure E2-5 Use of Rotary Slips on Wrong Size Pipe

Slips that are smaller than the pipe will damage the pipe and the corners of slips as well as risk dropping a string of pipe. Slips that are too large will not contact the pipe all the way around. This risks dropping the pipe and destroys the center part of the slips gripping surface.

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Figure E2-6 Effect of Stopping Pipe with Slips

The downward motion of the drill pipe must be stopped with the drawworks brakes, not with the slips. The drawing shows the effects of stopping the motion of the pipe with slips. This can occur when the floor hands are not careful to set the slips at the proper time when the driller has stopped the pipe. Do not let the slips "ride" on the pipe while the pipe is being pulled out of the hole. This practice accelerates the wear on the gripping elements of the slip. It also risks having the slip ejected from the master bushing bowl when a tool joint comes through and causing possible injury to personnel. New or "like new" inserts carry a concentrated load and deeply penetrate the pipe. Resharpened inserts carry no load. Inserts which carry a concentrated load are forced into slip bodies resulting in permanent damage to slips.

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Figure E2-7 Effect of Using Uneven Gripping Elements in Slip Bodies

Be careful not to catch the tool joint box in the slips when the driller slacks off. This often happens when coming out of the hole and the driller does not pick up high enough for the slips to fall around the pipe properly. This can ruin the slips, damage the tool joint box and damage the body of the pipe.

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Figure E2-8 Effect of Setting Slips on Tool Joints

Routine care and Maintenance will extend the service life of the drill pipe slips, protect the drill pipe and reduce the danger of sticking slips. Figure E2-9 indicates points of maintenance and lubrication.

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Figure E2-9 Lubrication and Care of Rotary Equipment

D. Inspection of Drill Pipe Slips 1. The slips should be physically inspected before every trip. If the inserts are not secure remove the slips from service until they can be repaired. If cracks are detected in the slip bodies they should be removed from service and destroyed to prevent future use. 2. The slips should be more thoroughly checked every three months. Place a straight edge on the backs of the slips and on the face of the slips. If the slips are bent or worn the straight edge will not make full surface contact with the slips. The backs of the slips should be straight and smooth. Excessively worn slips should be replaced. Magnetic particle inspection or inspection by similar method should be made to detect fatigue cracking in the slip bodies, webs and toes of the slips. If cracks are detected, the slips should be removed from service and destroyed to prevent future use. Check the insert slots for damage or excessive wear. If there is 1/8" to 3/16" clearance between the back of the inserts and the insert slot, the slips should be replaced. With worn insert slots there is danger of losing the inserts down the hole. 3. Slip tests should be performed every three months. This test is important to determine slip wear and/or master bushing wear.

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4. Spare parts are readily available to repair all slips of recent manufacture. Normally the inserts, dies or liners are the parts most frequently requiring replacement. Never intermix new inserts with worn or resharpened inserts. Section B4 of this manual provides additional information concerning resharpened inserts. 5. To maintain fully functionable slips they must be kept clean, they must not be abused, the hinge pins must be well lubricated and the backs, before use, are fully coated with good quality anti-seize compound.

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E3. Elevators I. Drill Pipe Elevators A. Elevator Specifications Drill pipe elevators for usc with taper shoulder and square shoulder weld-on tool joints shall have bore dimensions as specified in Table E3-1. Table E3-1 Drill Pipe Elevator Bores

Notes on Table E3-1: Elevators with the same bores are the same elevators. * Not Manufactured. ** Obsolescent connection. 1 Dimension DTE from API Spec. 7, Table 4.2 2 Dimension DsE from API Spec. 7, Appendix H.

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B. Cause and Result of Wear 1. Square Shoulder Elevators Square shoulder elevators in heavy use will wear or work harden under the repeated loads of the tool joint or collar. During drilling operations, the square shoulder of both the elevator and tool joint gradually becomes rounded and offers less supporting area. If this pinning of the elevator load-bearing surface is allowed to continue unchecked long enough, the bore will be reduced by the gradual flow of metal until the elevator is difficult to close and lock around pipe. At the same time, the worn surface of both the tool joint and the elevator may contact on a slight taper which could cause extreme opening forces within the elevator. That this condition could exist is admittedly rare, but indifference to wear could allow it to happen, and the result would be a catastrophe. Worn or damaged square shoulder surfaces of elevators and tool joints are easily corrected by properly matching these surfaces. 2. Taper-Type (Bottleneck) Elevators A condition that is by no means rare is the dangerous wear of 18-deg taper elevators and their counterpart, the 18deg tool joint. As the tool joints wear due to contact with the sides of the hole and the action of the drill fluid, the 18-deg taper tends to round off and, like the square shoulder joint, presents less contact area to the supporting taper of the elevator. The elevator taper, as a result, will begin to recess into the bore so that a cylindrical surface of approximately the outside diameter of the tool joint will form directly above the worn taper. Since all tool joints do not wear at exactly the same rate, some will be slightly larger than others. As the tapered bore recesses deepen, an occasional large joint will be forced to wedge itself down in the cylindrical surface so that the wedging or spreading force may be that of a 2 or 3 deg. angle instead of 18 deg. Such a spreading force will far exceed any safety factor that the elevator designer could reasonably use. Yet, this wear condition in its early stages is common. Frequently it results in an elevator sticking to the tool joint. Elevators that show hammer marks around the top of the bore should be closely examined to determine whether it is the elevator, the tool joint, or if both are at fault. Although the taper may appear to be true (18 deg.), the entire Icad bearing surface should be checked for variations. 3. Tool Joint Rebanding Careless rebanding and welding on tool joints can cause rapid elevator wear and produce a dangerous load situation quickly. Careless rebanding refers to any banding that intrudes on the 18 deg. taper of the tool joint. Banding in this area is very rough. It can rapidly wear out the elevator bore and result in extremely high internal loading. If the addition of "fingers" extending down the 18 deg. taper area is deemed absolutely necessary, then the welding should be performed as carefully as possible. It is important to make certain that the 18 deg. taper is maintained by keeping these abrasive fingers flush with the taper. Even then the operator must be prepared for the rapid deterioration of the elevator bore.

C. Care and Inspection Procedures Since both care and inspection procedures depend largely upon the amount of service the equipment has had, it is difficult to project overall recommended practice. The following is suggested as a starting point from which companies may vary according to their individual needs. 1. Before Each Round Trip All elevators should be examined to determine if the latch and the latch-lock mechanism are functioning properly. Hinge pins, latch lug surfaces, and link contact surfaces should be lubricated. Slip type casing and tubing elevators should be checked for sharp dies and the slip segments removed for cleaning and lubrication. 2. Semi-annual Check

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This examination, as outlined below, whether conducted in the field or shop, should be made using calibrated instruments to determine any deviations from the manufacturer's technical data for original parts. a. Square shoulder collar-type drill pipe, casing and standard tubing elevators: Inspect the collars for squareness, and uniformity and depth of wear. Uneven wear, or worn recesses of 1/16 in. or more, requires refacing of collar surface. Hinge pins and springs should be carefully inspected visually for excess wear and obvious weakness. b. 18 deg. taper-type elevators: inspection is the same as for square shoulder, except that the conical bore should be observed and measured (in many instances this check should be more frequent). All tool joints used with these elevators should also be measured. Amount of wear should be checked with chart, Table E3-2. In addition to the angle of taper, hard banding should be checked to see if it extends beyond the taper. Any straight edge may be used for this purpose.

II. Drill Collar Elevators A. Elevater Specifications A. Drill Collar elevators shall have bore dimensions that correspond to drill collar grove dimensions as specified in Table E3-2. Table E3-2 Drill Collar Groove and Elevator Bore Dimensions

*A and B dimensions are from nominal O.D. of new drill collar. 1' Angle C and D dimensions are reference and approximate.

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Figure E3-3 Drill Collar Elevator

B. Care and Maintenance 1. Effect of Wear When the elevator shoulder on a drill collar is new it is square and has sufficient area in contact with the elevator. See Figures E3-1 and Table E3-2 for suggested dimensions on new drill collars and elevators.

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Figure E3-1 Drill Collar Grooves for Elevators and Slips

As the collar is used for drilling, however, it wears as shown in Figure E3-2.

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Figure E3-2 Drill Collar Wear

Elevator contact area is decreased by collar OD wear and elevator spreading load is increased by angle and radius buildup on the collar and corresponding wear on the elevator seat. Elevator capacity drastically reduced by spreading action as most all drill collar elevators are intended for use with square shoulders only. As an example, with 1/ 16 inch wear on the collar OD, 1/32 inch radius worn on the corner, and a 5 deg. angle on the shoulder elevator capacity can be reduced by as much as 40 to 60 per cent, depending on collar size and elevator design. 2. Repair Before this danger point is reached, the collar and elevator should be shopped and the shoulders brought back to square condition. Be very sure the elevator, shoulder, radius on the drill collar is cold worked when the shoulder is reworked. The top bore of the elevator should be checked and corrected at this time as excessive slack between collar groove diameter and elevator bore decreases shoulder support area and also lets too much load shift to the elevator door. NOTE: These dimensions are not to be construed as being API standard. 3. Inspection The following inspection procedure for drill collar handling systems is recommended: A. Thoroughly clean and examine elevator adapter for cracks.

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B. Thoroughly clean and examine drill collar elevator for cracks with magnetic particle inspection. Make certain that elevator safety latch works easily and works every time. Check top seat of elevator to be certain it is square. C. Check elevator top bore as follows: 1. Center-Latch Elevator: Latch elevator, then wedge front and back of elevator open and measure at largest part of top bore straight across between link arms. This method will measure total wear in bore (of which there will be very little), and wear on hinge pin and latch surfaces. Wear should not be allowed to go above 1/32 inch on elevators for 5-5/8 inch and smaller drill collars and 1/16 inch for drill collars larger than 5-5/8 inch. 2. Side-Door Elevator: Latch elevator, then wedge latch open. Measure top bore from front to back. Same wear allowance as for center-latch elevators. D. Check elevator shoulder on drill collar to be certain it is square.

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E4 - Drill Collar Slips and Safety Clamps I. Drill Collar Slips In general, taper specifications are the same as listed for drill pipe slips. Examine slips for general condition and size range for the collars being run. Look for cracks, missing cotter keys, loose liners, dull liner teeth, bent back tapers (from catching on drill collar shoulder), and bent handles.

II. Drill Collar Safety Clamps Safety clamps are used on drill collars above the slips to prevent dropping the string should the slips fail to hold. Examine safety clamp for general condition. Look for cracks, missing cotter keys, galled or stripped threads, rounded-off nuts or wrenches, dull teeth, broken slip springs, and slips that do not move up and down easily.

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E5. Elevator Links, Block, Hook And Swivel Specifications I. Specifications Recommended radii for various blocks, bails, links, and link ears are specified in Table E5-1 and Figure E5-1.

Table E5-1 Hoisting Tool Contact Surface Radii

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Figure E5-1a Surface Radii on Traveling Block & Hook Bail

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Figure E5-1b Surface Radii on Elevator Link & Link Ear

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Figure E5-1c Surface Radii on Hook & Swivel Ball

These recommendations cover hoisting tools used in drilling and tubing hooks. All other workover tools are excluded.

II. Rating Change Due To Wear-links Based on recommendations on links, it is possible to approximate downrating due to wear. Figure E5-2 indicates the rating on new links and the decrease in rating by steps as the links are worn.

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Figure E5-2 Forged Links Wear Charts

Notes for Figure E5-2 To determine the strength of worn links, measure with calipers as shown, the amount of eye wear and compare figure with Table for new capacity. Capacity of set is that of weakest eye. Thickness of wear point in Low Eye Dimension (Dim)"B" To determine the strength of worn links, measure with calipers, as shown, the amount of eye wear and compare figure with Table for new capacity. Capacity of set is that of weakest eye. Thickness of wear point in Upper Eye Dimension (Dim) "A" Thickness of wear point in Lower Eye Dimension (Dim) "B" A periodic check should be made of worn diameters, particularly when weight levels may be involved. If a question exists as to proper rating after use, particularly if there is evidence of other damage, such as cracks, the manufacturer should be contacted.

III. Rated Change Due To Wear -- Link Ears Experience has shown that the greatest amount of wear on the hook is on the link ears. Thus, downgrading of the hook will be based on wear at these points.

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Also, there is considerable difference in design by various manufacturers. Even though radii are recommended by API Spec SA, shown in Figure E5-1, the differences in design will vary the downgrading based on wear. The change in rating due to wear by three manufacturers is shown in Figure E5-3, Figure E5-4, Figure E5-5.

Figure E5-3 Hook Strength Reduced by Link Ear Wear for Web Wilson Hooks

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Figure E5-4 Decrease in BJ Hook Capacity with Link Ear Wear

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Figure E5-5 Rating of National Hook Blocks with Link Ear Wear

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Measure the depth of the link ear at the point of the greatest wear (Dim "A"). The new capacity of the hook and/ or link ears is shown in corresponding chart of hook size. WEAR LIMITS It is recommended that any hook showing wear of 1/2" be promptly repaired. Wear should never exceed 3/4". When properly built up to recommended dimensions, the wear pad will prevent further loss in capacity until original wear point is reached. The load capacity will always be that determined by the end with the of greatest wear. EXAMPLE Measure the depth (dim. "a") of the link ear at the point of most wear. For a worn 460 hook with old style ears (ser. no. 1-861) dim. "a" measured 2-7/8" By refering to the chart the capacity is seen to be 94% of original capacity, WEAR LIMITS (ALL HOOKS): Repair is recommended for 1/2'' wear; wear should not exceed 3/4"

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Chapter F: Drawworks Brakes

Chapter F Drawworks Brakes

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Table of Contents - Chapter F Drawworks Brakes Introduction ........................................................................................................................................ F-3 I. Maintenance Procedures ................................................................................................................. F-4 II. Brake Linings (Blocks) ................................................................................................................... F-5 III. Brake Bands ................................................................................................................................. F-5 IV. Brake Rims (Flanges) .................................................................................................................... F-6 V. Brake Linkage .............................................................................................................................. F-20 VI. Company Policy ......................................................................................................................... F-20

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Chapter F Drawworks Brakes The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study. The following industry representatives have contributed to the development and updating of this chapter: MEMBERS OF THE TASK GROUP: Bill Brannon

Grey Wolf Drilling Company

G. Otis Danielson

Consultant

Norman Dyer

LTV Energy Products

James Jones

S & J Rig Parts

Paul Price

National Oilwell

Jack Reeve

IRI International Corp.

Introduction The information contained in this section of the Drilling Manual is for use by field personnel as a guide in the maintenance of a drawworks brake system to insure proper function, safety and economy of operation. Drawworks brakes are highly engineered mechanical systems. Manufacturers of drawworks generally furnish complete maintenance instructions. Owners and operators of rigs should look first to the equipment manufacturer for the complete and specific details of maintenance and safety considerations. Field personnel need to be informed of the basic maintenance and safety concepts necessary to make proper judgements in carrying out maintenance procedures at the well site. Fortunately, the signals indicating the need for most maintenance functions are cumulative and easily recognized. Since adjustments and replacement of linings are very routine with rig crews, the precautions and planning involved are largely just normal care and common-sense. As a practical matter, the overriding concern in brake system maintenance is the proper monitoring of the various parts to assure that wear or deterioration does not progress beyond safe limits.

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Operating Cautions: WARNING Brake handle kick can be dangerous and can result in bodily injury. Causes of brake handle kicks which involve rapid brake handle movement and potentially large forces may include: 1) sudden hoisting speed with brakes engaged with little or no hook load, 2) band rollers/springs missing or out of adjustment, 3) brake blocks stuck to the brake rims, 4) bent or damaged brake bands, and 5) worn or loose dead-end linkage. WARNING Sudden application of the brakes while the block is going up in the mast or derrick can cause the wire line on the drum spool to backlash and the wireline clamp to unseat or loosen. Such practice is hazardous to both equipment and personnel. Any time such wireline backlash does occur, rig personnel should inspect the wireline clamp to insure it is still properly installed. Only mechanical band brake systems are discussed in this section; however, caliper brake systems are presently being developed. Therefore, refer to the equipment manufacturer's literature for information on maintenance and safety considerations.

I. Maintenance Procedures The following maintenance procedures are recommended: 1) scheduled lubrication and visual inspection, 2) adjustment of brake handle position, 3) adjustment of band rollers and springs, 4) inspection of lining (blocks) and brake rims for wear, 5) inspection of cooling system, 6) inspection of bands, especially when blocks are replaced, and 7) inspection of linkage (live and dead end) for wear. The timing of these activities should be influenced by the experience of the operation, rig conditions and usage, and recommendations of the equipment manufacturer. Special or more frequent inspections may be dictated by any unusual braking action or performance of the equipment, as well as anticipated requirements for the braking system. Most of these items are a part of daily rig operation, and problems discovered in the inspection will be solved by the experienced rig crew. All inspection and repairs should be reported. Problems of an unusual or serious nature may require special attention. Item 4 inspection may dictate replacement of linings and calls for an evaluation of the equipment by the inspections in items 4 through 7 and other related parts of the brake system, as needed. A lengthy idle period and possibility of deterioration will call for an evaluation of the braking system before restarting rig use. In all cases, good maintenance records must be kept, and will help to provide a safe brake system.

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II. Brake Linings (Blocks) As with other equipment expendables, drawworks brake lining wear and replacement should be monitored and recorded. If, when inspected, the worn blocks are giving good service and have adequate wear remaining, the evaluation is likely to be "Don't change it." If service life has been shortened by non-uniform wear, etc., lining should be replaced and the cause(s) should be determined and corrected. Brake linings for all manufacturers' drawworks are readily available from a number of suppliers in a variety of materials. Due to health concerns, some equipment manufacturers are discontinuing the use of asbestos lining on new drawworks. As to the selection of replacement linings, there are many choices available. Considerations include friction factors, fade, wear, service compatibility, equipment manufacturer's recommendations, as well as health and safety of the rig crew. With the proper supervision, inspection, tools and care, the rig crew can install a new set of brake blocks at the rig site. The brake bands must meet minimum acceptance criteria as outlined below in order to be re-lined. Replacement linings delivered to the rig installed on a set of used brake bands on an exchange basis could be dangerous. Use them only if the exchange bands have been properly inspected prior to re-lining. Brake linings and blocks should be stored in a clean dry place and protected from high heat or strong sunlight to minimize aging and deterioration.

III. Brake Bands Brake band failure can be catastrophic. Proper maintenance and periodic inspection are critical to safe and reliable rig operations. WARNING Field personnel should be constantly alert to the severe consequences of brake band failure and should follow manufacturer's recommendations for brake band maintenance. Probably the largest contributor to wear on brake rims and linings, other than normal usage, is bent, flattened, or twisted brake bands. Special care must always be taken when handling, storing, or transporting brake bands, especially if brake blocks are installed on bands. When a band is distorted from its proper shape it not only promotes rapid wear, but causes the brake lever to "kick" when released. Operation of damaged brake bands can also cause brake band failure and/or damage to or failure of other brake linkage components. When removing a brake band for any reason, proper care should be taken to prevent damage of the brake band. Similar care should be taken during installing a new or relined brake band. Jerking the brake band assembly with the cat line or the hoisting line can cause kinking and distortion. Brake bands, as reinstalled on the drawworks, should conform to the following: 1) Blocks properly bolted and secured in place on a surface that is clean and free from rust and paint. 2) Bands inspected for roundness and proper curvature. Bands free of bends, flattening, twists, kinks or other distortions. 3) Bands with the same material strength and other mechanical properties as the original equipment bands. 4) Bands free from cracks around holes, rivets, welds, and at any other areas of stress concentration. All bands should have been examined prior to relining by technically qualified personnel using generally accepted inspection methods, such as magnetic particle inspection, dye penetrant examination, or other method for the detection of fatigue cracks and other defects. Bands with fatigue cracks should be removed from service and destroyed.

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5) Bands free from nicks, gouges, dents or other surface irregularities which act as stress risers. These should have been removed by filing and smoothing prior to relining. 6) Bands free from any weld repair. Make no attempt to repair a brake band by welding or any other means. If bands are not in reasonably "as good as new" condition, they should not be put into service. As a word of caution, it is an accepted fact that end connector welds that run straight across the band width act as stress risers and can cause fatigue cracks. New or replacement brake bands should be stored flat and on a level surface to minimize distortion while in storage.

IV. Brake Rims (Flanges) Introduction Brake rims are designed to have a prescribed amount of wear (reduction in thickness) before they should be replaced. Wear generally accelerates rapidly once the hardened layer or surface has been worn away, and further usage will result in more rapid wear and an unsafe condition. Each time brake linings are replaced, brake rim wear should be measured. By keeping accurate records of the cumulative amount of rim wear, field personnel can predict when to replace the brake rims in order to get the maximum safe allowable service from each set. Timely measurement of brake rims must be made to assure that safe wear limits are not exceeded.

A. Measuring for Wear Wear measurements can be made in several ways. The examples shown in Figure F-1 (as well as ultrasonic measurements) are used because they can be made with the brake bands in place and with only a short interruption in rig operations.

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Figure 1-1 Brake Rims Measurements

The procedure used in Figure F-1 obtains the measured distance "M" (using a depth gage) which is used to calculate the greatest amount of brake rim wear "W". Compare this amount of wear to the permissible amount of wear, Wi or W2, in each manufacturer's table, included herein, to determine the appropriate action. Ultrasonic thickness instruments may also be used to accurately measure remaining brake rim thickness, which, as shown in Figure F-1, is used to figure the amount of wear "W". All drill pipe inspection companies routinely use this method. Dimension "L" should be measured and recorded before each brake rim is put into service. Information in the Table F-xx is not meant to be a substitute for information that is available from the drawworks manufacturer or other suppliers.

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Tables Related to Brake Rim Wear: Tables F-xx

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It should be noted here that hardness tests of the worn brake rim surface will indicate if the wear has progressed into the underlying "soft" metal below the hard surface overlay. The brake rim manufacturer should be consulted in this. Many machine shops have portable hardness testing equipment. A variation of 10 to 15 points or more on the Rockwell C scale indicates wear into the softer base metal.

B. Inspection of Rims Each time that bands are removed, wear should be measured and recorded and rims rotated to make a full 360 degree inspection for visible defects and wear, such as: 1) Grooving and/or uneven wear. Measurement for greatest wear should be made at the point where grooving or uneven wear is greatest. 2) Transverse or other cracks which propagate across the rim. 3) "Cross checking" heat cracks are normal for hard metal overlay rims; however, if the cracks join or intersect adjoining crack patterns, it is possible for such cracks to propagate or enlarge to the point that the brake rim becomes unsafe. 4) If operating conditions or the condition of the brake rim so indicate, further inspection by non-destructive means, such as magnafluxing, should be made. Remachining of brake rims for the purpose of correcting warpage or uneven wear can be performed by any machine shop with the appropriate machining capability. The finished diameter of the rim should fall within the wear guidelines recommended by the manufacturer.

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C. Replacement Brake Rims The use of rebuilt or resurfaced brake rims is economically viable in certain circumstances, as long as the integrity of the product meets original equipment standards. Generally, large diameter rims or rims with complex geometries such as those with counterbored bolt flanges are good candidates. Rims with excessive wear or rims made of highly hardened material are not safe candidates for resurfacing. Hard surfaced brake rims are common, and are increasing in popularity both as new, original equipment rims, and as replacement equipment. New or rebuilt hard surfaced brake rims are generally harder than through hardened brake rims, and have a thicker hardened surface than flame hardened or induction hardened brake rims. The weld overlayed surface generally differs in appearance from other rims, being characterized by a cross-checking of shallow cracks. These characteristic cracks are not detrimental, and in fact indicate proper weld overlay application and relieving of residual stresses. These cracks should never extend into the base metal nor should they ever propagate into adjacent areas of the base metal. New or replacement rims should be stored flat and on a lever surface to minimize distortion while in storage.

D. Water Jacket Scale The formation of scale in water jackets can cause brake overheating. Brake rims should be descaled when inspection reveals a significant scale build-up. Water used as a brake coolant should always be checked for hardness and treated as needed. Never use salt water to cool brake rims.

V. Brake Linkage Given enough time and usage, the contact surfaces in the brake system linkage will wear, resulting in noticeable slack. This affects adjustment of the linkage, operation of the brakes, response time, braking force, etc. This wear can be accelerated by several factors, including infrequent lubrication, selection of improper greases, accumulated grit and extremes in operating temperatures. Inspection and replacement or repair of the affected parts should be scheduled. Parts should be regularly inspected for fatigue cracks as well as for wear. The drawworks manufacturer should be consulted to determine if safe wear limits have been exceeded.

VI. Company Policy Long term economy of operation, within the bounds of sound safety practice, is probably the bottom line of most company policy. For the average drilling contractor, this is best accomplished by supervisors and operating personnel educating themselves to the task and by calling on the expertise of knowledgeable and reliable manufacturers and suppliers. Our most important skill is knowing how to ask the right questions. Company policy must spell out the safe limits and must schedule the necessary monitorings and inspections. The use of remanufactured brake system components will always be an option and the test of this should be the assurance of quality as represented by the vendor and, or course, performance. The product must perform with the same degree of safety as incorporated in the original design of the drawworks.

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Chapter G: Chains and Sprockets

Chapter G Chains and Sprockets

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Table of Contents - Chapter G Chains and Sprockets G1. Construction and Specifications .......................................................................................................... G-4 I. Roller Chain Construction And Types .............................................................................................. G-4 IV. Sprockets ................................................................................................................................... G-16 G2. Installation, Lubrication And Maintenance ......................................................................................... G-22 I. Installation ..................................................................................................................................... G-22 II. Lubrication ................................................................................................................................... G-25 III Maintenance ................................................................................................................................ G-36 Roller Chain Drive Troubleshooting Guide ......................................................................................... G-41

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Chapter G Chains and Sprockets The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study. The contents of this chapter have been provided by Mr. W. R. Evans-Lombe of Diamond Chain Com

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G1. Construction and Specifications I. Roller Chain Construction And Types A. General Single Strand Roller chain is a series of alternating pin links and roller links in which the pins can turn inside the bushings. (Figure G1-1). Figure G1-1 Roller Chain Construction

The pin link (Figure G1-2) consists of two pins assembled into tow pin link plates with controlled press fits to prevent the pins from rotating in the pin link plates. Figure G1-2 Pin Link and Roller Link

The roller link (Figure G1-2) consists of two bushings assembled into two roller link plates with controlled press fits to prevent the bushing from rotating in the roller link plates. Two rollers are assembled, free to turn, on the outside of the bushings. As the chain articulates, turning occurs only between the pin and bushing, so they are primarily subject to wear. The link plates mainly bear the tensile loads and securely locate the pins and bushings. The rollers absorb the impact and provide rolling action when the chain joint engages the sprocket tooth. Roller chain may be furnished with either riveted or cottered type pins (Figures G1-3 & G1-4).

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Figure G1-3 Riveted Single Strand Chain

Figure G1-4 Cottered, Roll Pin, and Spring Clip SS Chain

Riveted type pins have both ends riveted or swagged. Cottered type pins have one end riveted or swagged and the other end cross-drilled to accept a cotter pin. Cotter pins for roller chain are carefully formed to fit snugly in the hole, and often are heat treated for high strength and toughness, so the cotter pins will not be thrown out of the chain by high speed or vibration.

B. Multiple Strand Chain Multiple strand chain is two or more single strands assembled on common pins. Multiple strand chains may be furnished with either riveted or tottered type pins (Figures G1-5 & G1-6).

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Figure G1-5 Riveted Multiple Strand Chain

Figure G1-6 Cottered Multiple Strand Chain

Multiple strand chains also may be furnished with either slip fit or press fit center plates (Figure G1-7). Figure G1-7 Multiple Strand Chain - Press or Slip Fit

Slip fit center plates have holes that are slightly larger than the pin and can be easily moved, or slipped, on and off of the pins. Slip fit center plate multiple strand chain can be readily disconnected in the field at any pin link in the chain. Press fit center plates have holes that are slightly smaller than the pin and must be driven, or pressed, on and off of the pins. Press fit center plate multiple strand chain normally can be disconnected in the field only at the connecting link without special pressing equipment. Press fit center plate multiple strand chains provide significantly better service on drives that are subjected to severe shock loading because the press fit center plates reduce pin bending and are virtually immune to fretting between the center plate and pin.

C. Connecting Links A connecting link is a pin link with a quickly detachable retainer that normally is used to connect the two ends of a chain together to make it endless on a drive. There are two common types of connecting links with respect to retainers. They are the spring clip type (Figure G1-8) and the tottered type (Figure G1-9).

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Figure G1-8 Spring Clip Connection Link

Figure G1-9 Cottered Connecting Link

The cottered type connecting links looks, and sometimes is, the same as the pin link in cottered type chain. There also are two common types of connecting links with respect to cover plates. They are of the press fit type in which the cover plate is a press fit on the pins (sometimes it is a center plate from a slip fit multiple chain). The press fit cover plate connecting link has working capacity that is virtually equal to single strand or work slip multiple strand chain, and it is preferred for maximum reliability or for the most demanding drives. The slip fit cover plate connecting link may be used on less critical drives where speed is slow or where ease of coupling and uncoupling is very important. Finally, there is a BCL type connecting link for use with press fit centerplate multiple strand chain (Figure G1-10). Figure G1-10 BCL Connecting Link with Bushed Center Link

This connecting link employs Bushed Center Links which are two center plates, usually of roller link plate height, with bushings pressed into the pitch holes. These center links have virtually the same working capacity as press fit center plates. The bushing bores are slightly larger than the pins, so the center links can be assembled and disassembled as easily as slip fit center plates. The BCL connecting links normally have press fit cover plates.

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D. Offset Links Offset links are combination links with a specially designed bend in the middle so that one end functions as pin link and the other end as a roller link. The single-pitch offset link has a slip-fit, removable pin with a flat milled on one end that fits into a "D" shaped hole in the link plate (Figure G1-11). Figure G1-11 Offset Links

An offset section may be a two-pitch (Figure G1-12) or a four-pitch (Figure G1-13) assembly. Figure G1-12 Offset Section, Two-Pitch

Figure G1-13 Offset Section, Four-Pitch

The two-pitch section consists of a roller link and offset link. The four-pitch section consists of an offset link and a pin link with a roller link on both ends. Both sections use riveted typo pins that are a press fit in all link plates. Avoid the use of offset links whenever possible. If an offset link is required, an offset section should be used because the press fit pins give it higher working capacity. The four-pitch section can be connected into multiple strand chain with a BCC connecting link.

II. Applicable Standards And Specifications A. ANSI Standard B29.1

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The ANSI standard B29.1 defines power transmission roller chain, establishes a numbering system, and dictates limiting dimensions, chain length tolerance, and minimum chain tensile strength. This standard also defines sprockets for roller chain and sets tolerances or limits on critical sprocket dimensions. B. API Specification 7F The API specification 7F refers to ANSI B29.1 for chain and sprocket definition, numbering, dimensions, and chain tensile strength. In addition, API specification 7F dictates minimum dynamic strength and pin and bushing press-out-force, included in proposed revision of June 1991.

III. Roller Chain Numbering And Dimensions A. General Dimensions The general dimensions of ANSI B29.1 standard roller chain are shown in Table G1-1A (inches), Table G1-1B (mm), and Tg1-1P5.

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Table G1-1A General Chain Dimensions, ins

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Table G1-1B General Chain Dimensions, mm

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Tg1-1P5 - Illustration for Tables G1-1a & G1-1b

Notes for Table G1-1A (inches), Table G1-1B (mm): (1) See ANSI B29.1 minimum dimensions. (3) For single strand chain.

(2) For single strand chain.

(4) Bushing diameter, as these chains have no rollers.

The most important basic dimension or a roller chain is the pitch (P) which is the nominal distance between consecutive rollers or bushings. Other key dimensions are proportional to the pitch. The roller diameter (Dr) and roller width (W) are approximately 5/8 of the pitch. The pin diameter (Dp) is approximately 5/16 of the pitch. The link plate thickness (LPT), for Standard Series chain, is approximately 1/8 of the pitch. The link plate thickness (LPT), for Heavy Series chain, is that of the next larger pitch standard series chain. The measuring load and minimum ultimate tensile strength of multiple strand chains are the single strand values multiplied by the number of strands. Measuring load is limited to a maximum of 1,000 lbs (4,448 N). The maximum dimensions of standard roller chain, Single and Multiple Strand are in Table G1-2A (in); Table G1-2B (mm), and Tg1-2P7.

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Table G1-2A Maximum Chain Dimensions, ins

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Table G1-2B Maximum Chain Dimensions, mm

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Tg1-2P7 - Illustration for Tables G1-2a & G1-2b

Notes for Table G1-2A (in); Table G1-2B (mm), and Tg1-2P7 SINGLE AND MULTIPLE STRAND CHAINS B = maximum half width of outboard chain strand K = nominal transverse pitch = 4.22 LPT + W N = number of strands

B. Roller Chain Numbering Standard roller chains are designated by a numbering system which is defined in ANSI Standard B29.1. This numbering system is based on standard dimensions that are pitch proportional; that is the major dimensions of a standard roller chain are proportional to the chain pitch. Standard single strand, single pitch chain is identified by a two or three digit number. The right hand digit is a zero for chain of standard proportions, a 1 for lightweight chain, and 5 for rollerless bushing chain. The left hand digit or digits indicate the number of 1/8 inch increments in the pitch. For example, a standard 3/4 inch pitch roller chain has 6 increments of 1/8 inch in the pitch, so the number is 60. 'Heavy' series chains have link plate thickness equal to the next larger standard size chain, and are designated by the letter H immediately following the standard chain number. For example, 80H or 160H. Multiple strand chain is designated by a hyphen and one or two digits indicating the number of chain strands; for example, 60-10 or 120H-3. The chains that are commonly used in the oil field are:

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TG1-P4 Chains Used in the Oilfield

IV. Sprockets A.

Sprocket Types.

There are four types of sprockets covered by ANSI B29.1 and API SPEC 7F, and they are shown in Figure G1-14

Figure G1-14 Sprocket Types

B. Sprocket Tooth Form and Diameters The ANSI Standard sprocket tooth form, described in ANSI B29.1, is too detailed for our use. Sprocket diameters are described in the following paragraphs and nominal pitch diameters and outside diameters are listed in an appendix. The tolerances and limits for sprocket diameters are contained in ANSI B29.1 are not repeated here.

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Pitch Diameter. The pitch diameter of a sprocket is the diameter of a circle followed by the centers of the chain pins as the sprocket revolves in mesh with the chain, and is a function of the chain pitch and of the number of teeth in the sprocket. The pitch diameter may be calculated as follows: Pitch diameter = sin [(Pitch/180°)/(No. of teeth)] This theoretical dimension is not directly measurable. Bottom diameter. The bottom diameter of a sprocket is the diameter of a circle tangent to the bottoms of the tooth spaces. The tolerance on the bottom diameter must be entirely negative to insure that the chain will mesh properly with the sprocket teeth. Caliper Diameter. Since the bottom diameter of a sprocket with an odd number of teeth cannot readily be measured directly, this catalog lists caliper diameter which enable calculating the dimensions across the bottoms of tooth spaces most nearly opposite. As on bottom diameters, tolerances on caliper diameters must be entirely negative. Outside Diameter. The outside diameter of a sprocket is comparatively unimportant as the tooth length is not vital to proper meshing with the chain. The outside diameter may vary depending on the type of cutter used. The approximate outside diameter may be calculated as follows: Outside Diameter = Pitch [0.6 + cot (180°/No. of Teeth)]

C. Sprocket Flange Thickness and Tooth Section Profile. Sprocket flange thickness dimensions are shown in Table G1-3a and G1-3b

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Table G1-3a Flange Thickness and Tooth Section Profile, SS CS

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Table G1-3b Flange Thickness and Tooth Section Profile, HS CS

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Tg1-3F - Illustration for Tables G1-3a & G1-3b

Notes for Table G1-3a and G1-3b. The I and M dimensions are for machined finish. The T tolerances apply to hot rolled plates used for plate sprockets and welded-hub sprockets. Exact dimensions for sprocket tooth chamfers are not of critical importance. For nonstandard, and narrow width chains, the dimension "g" is 1/6P but should be no greater than 1/3W.h = .5P + No. 41 Chain is not made in multiple strands.

D. Tooth Profile (from IADC Manual, Rev. 10) Figure G1-15. Section A and B, shows the recommended sprocket tooth chamfer for roller chains. Figure G1-15 Sprocket Tooth Profile

Section C, shows sprocket tooth flange location for multiple strand roller chains.

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All sprocket flanges shall be chamfered to guide the chain onto the sprocket in case of misalignment due to sprocket misalignment or permissible flange weave. Flange chamfer may be either as in Section A or B or any intermediate profile. The fillet radius f (rf) max equals 0.4 x pitch for maximum hub diameter. Other indicated dimensions are given in Tables G1-3 and G1-4. Table G1-3 Sprocket Flange Thickness

Table G1-4 Tooth Section Profile

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G2. Installation, Lubrication And Maintenance I. Installation A. Check Condition of Components. Check shaft and bearings and assure that they are in good condition. Check shaft supports and bearing mounts and be sure they are correctly positioned and secure. If the chain is not new, be sure that it is clean and well lubricated. If sprockets are not new, be sure that they are not excessively worn or otherwise damaged.

B. Align Shafts and Sprockets. Good drive alignment is necessary to prevent uneven loading across the width of the chain and damaging wear between the sprocket teeth and the roller link plates of the chain. Aligning the drive is a straightforward, two-step procedure. 1. The shafts must be parallel within fairly close angular limits. This is readily done by using a machinist's level and feeler bars (See Fig. G2-1).

Figure G2-1 Align Shafts

First, using the machinist's level, make sure that both shafts are level or in the same plane. Then, using the feeler bars, make sure that the shafts are parallel in that plane. If the shafts can float axially, lock them in the normal running position before attempting to align them. Most single strand drives will perform acceptably if the shafts are parallel and in the same plane within .050 inches per foot or 1/4 degree. However, high speed, high horsepower, or multiple strand chain drives should be aligned within the tolerance obtained from the following formula: Tolerance, in/ft = 0.01 C / (12 P n) Where: C = center distance, inches. P = chain pitch, inches. n = number of chain strands.

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2. The sprockets must be mounted on the shafts as closely in line axially as practicable. This normally is done with a straightedge or a length of piano wire (See Fig. G2-2). Figure G2-2 Align Sprockets

In practice, the maximum amount of axial misalignment is obtained from the following formula: Max. Offset (in) = .045 P Where: P = chain pitch, inches. This formula applies to both single and multiple strand chains.

C. Install Chain. A new chain should be kept in its box until ready for installation to preserve the factory lubrication and prevent contamination by dirt and debris. If the new chain is not the correct length, in pitches, to fit on the drive, a long stock length may have to be shortened or several sections may have to be connected to make the chain the correct length. A brochure entitled "Connect & Disconnect Instructions for ANSI B29.1 Roller Chains", published by the American Chain Association, describes how to do this. All of the chain and links in a give drive should be from the same manufacturer. Otherwise, the drive may surge or run rough. Fit the chain round the sprockets and bring the free ends together on one sprocket, using the sprocket teeth to hold the chain ends in position. With large heavy chains it may be necessary to block the sprockets to prevent them from turning while the chain ends are brought together. Insert the pins of the connecting link through the busing holes to couple the chain endless. With long chain spans, it may be necessary to support the chain with a plank or rod while the connection is made. Then, install the cover plate and the spring clip or cotters. After the fasteners have been installed, the ends of the pins should be pressed back until the fasteners are snug against the cover plate. This restores the intended clearances across the chain and allows the joint to flex freely as it should. Again, the connection procedure is well described in the brochure, 'Connect & Disconnect Instructions for ANSI B29.1 Chains'.

D. Connecting Links. Connecting pins should use interference fit cover plates because their capacity is virtually the same as the rest of the chain. The use of slip fit cover plates should be avoided because their capacity can be much less than the rest of the chain.

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E. Offset Links. The use of offset links should be avoided whenever possible because their capacity can be much less than the rest of the chain. If an offset link is necessary, an offset section, assembled with press fit pins, should be used.

F. Adjust Chain Tension. First, turn one sprocket to tighten one span of chain. Then, use a straightedge and scale to measure the total midspan movement in the slack span (Fig. G2-3). Figure G2-3 Chain Tension Adjustment

Adjust the drive center distance or the idler to produce 4 to 6% mid-span movement for drives that are on horizontal centers to 45 degrees inclined, and 2 to 3 % for drives that are inclined 45 degrees to vertical, subject to high shock loads, or on fixed centers.

G. Ensure Adequate Clearance. Check the drive carefully to ensure that there is no contact between the drive and adjacent objects. Ample clearance must be provided to allow for chain pulsations, chain elongation from wear, and possible shaft end float.

H. Provide Adequate Lubrication Before starting the drive, be sure that the specified lubrication system is working properly. See the section on "Lubrication" for details.

I. Install Guards. If the roller chain drive does not run in a chain casing, it should be enclosed by a guard that will prevent people from being injured by inadvertent contact with moving components of the drive. More detailed information about guards can be found in the Standard ANSI B15.1; Safety Standard for Mechanical Power Transmission Apparatus.

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Before installation, inspect the guard to be sure it is not broken or damaged, especially at or near the mounting points. Then, install the guard; making sure that all fasteners are secure and all safeguarding devices (such as presence sensors and interlocks) are functioning.

II. Lubrication A. Lubrication Flow. Each joint in a roller chain is a journal bearing, so it is essential that the pin and bushing surfaces receive and adequate amount of the proper lubricant to achieve maximum wear life. In addition to resisting wear between the pin and bushing, an adequate flow of lubricant smooths the engagement of the chain rollers with the sprocket, cushions roller to sprocket impacts, dissipates heat, flushes away wear debris and foreign materials, and retards rust. The lubrication should be applied to the upper edges of the link plates in the lower span of the chain shortly before the chain engages a sprocket (Figs. G2-4 & G2-5).

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Figure G2-4 Chain Lubrication Guide

Figure G2-5 Chain Lubrication Guide

Then, gravity and centrifugal force both will aid in carrying the lubricant to the critical pin and bushing surfaces. Surplus lubricant spilling over the link plat edges will supply the roller and bushing surfaces.

B. Lubricant Characteristics. Lubricants for roller chain drives should have the following characteristics: 1. Sufficiently low viscosity to penetrate to the critical internal surfaces. 2. Sufficiently high viscosity or appropriate additives to maintain the lubricating pin under the prevailing bearing pressures. 3. Clean and free from corrodents. 4. Capability to maintain lubricating qualities under the prevailing operating conditions. The requirements usually are met by a good grade of non-detergent petroleum base oil. Detergents normally are not necessary, but anti-foam, anti-rust, or film strength improving additives often are beneficial. Heavy oils or greases should not be used because they are too thick to penetrate to the internal surfaces of the chain. The recommended oil viscosity for various surrounding temperature ranges is shown in Table G2-1.

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Table G2-1 Oil Viscosity vs Temperature

Note: When the temperature range permits a choice, the heavier grade should be used.

C. Types of Lubrication. There are three types of lubrication for roller chain drives. The recommended type is based on chains speed and is selected from Table G2-2. Table G2-2 Lubrication for Pitch and Speed

These should be regarded as minimum lubrication requirements and the use of a better type may be beneficial. Type 1 Manual or Drip Lubrication. For manual lubrication, oil is applied periodically with a brush or spout can, preferably once each 8 hours of operation. The time between application may be longer than 8 hours, if it has proven adequate for that particular drive.

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The volume and frequency of oil application must be sufficient to prevent a red-brown (rust) discoloration of the oil in the joints. The red-brown discoloration indicates that the lubrication in the joints is inadequate. When rust discoloration is found; remove, clean, relubricate, and reinstall the chain before continuing operation. For drip lubrication, oil is dripped between the link plate edges from a drill lubricator. Drip rates range from 4 to 20 drops per minute or more, depending on chain speed. Here again, the drip rate must be sufficient to prevent a redbrown (rust) discoloration of the lubricant in the chain joints. Care must be taken to avoid misdirection of the oil drops by windage. For multiple strand chains, a distribution pipe is needed to feed oil to all link plates, and a wick packing is usually required to distribute oil uniformly to all the holes in the pipe (Fig. G2-4).

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Table G2-4 Chain Wear Elongation Limits

Figure G2-6 Drip Free Lubrication

Type 2 Bath or Disc Lubrication. For oil bath lubrication, a short section of the lower strand of the chain runs through a sump of oil in the drive housing (Figure G2-7).

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Figure G2-7 Oil Bath Lubrication

The oil level should just reach the pitch-line of the chain at its lowest point in operation. Long sections of chain running through the oil bath, as in a nearly horizontal lower span, should be avoided because the can cause oil foaming and overheating. For slinger disc lubrication, the chain operates above the oil level. The disc picks up oil from the sump and slings it against a collector plate. Then, the oil usually flows into a trough which applies it to the upper edges of the link plates in the lower span of the chain (Fig. G2-8). Figure G2-8 Slinger Disc Lubrication

The diameter of the disc should produce rim speeds to pick up the oil effectively, while higher speeds it may cause oil foaming or overheating.

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For both oil bath and slinger disc lubrication, the temperature of the oil bath and the chain should not exceed 180 degrees F. Also, the volume of oil applied to the chain must be great enough to prevent a red-brown (rust) discoloration of the lubricant in the chain joints. For both oil bath and slinger disc lubrication, the oil level in the sump should be checked after every eight hours of running time, and oil added when needed. At the same time, the system should be checked for leaking, foaming, or overheating. Type 3 Oil Stream Lubrication. For oil stream lubrication, a pump delivers oil under pressure to nozzles that direct an oil stream or spray onto the chain. The oil should be applied evenly across the width of the chain, and be directed onto the lower span from inside the chain loop (Fig. G2-9). Figure G2-9 Oil Stream Lubrication

Excess oil collects in the bottom of the casing and is returned to the pump suction reservoir. A pressure-regulating valve may be used to return excess pump discharge to the reservoir. Oil cooling may be by radiation from the external surfaces of the reservoir or by a separate heat exchanger. Oil stream lubrication is always recommended for chains running at relatively high speeds and loads. It is absolutely essential for roller chains operating in the indicated galling region for any extended period of time. The oil stream not only lubricates the chain, but also cools the chain and carries away wear debris from a drive chain being operated at or near full rated capacity. Table G2-3 shows the minimum oil flow rate based on the amount of horsepower transmitted.

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Table G2-3 Oil Flow for Chain Drives

Here again, the oil level in the sump should be checked after each eight hours of operation time, and oil added when needed. At the same time, the system should be checked for leaking and overheating.

D. Chain Casings. Chain casings (Fig. G2-10) are used to facilitate lubrication and to protect the drive from being damaged by debris or contamination. Figure G2-10 Oil Retaining Chain Casing

Chain casings are usually made of sheet metal, stiffened by steel angles or embossed ribs, and have access doors or panels for inspection and maintenance of the drive.

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Adequate clearances must be provided inside the chain casing or the useful wear life of the chain may be restricted. As chain wear elongation accumulates in the slack span, chain sag can become great enough to allow the chain to strike the bottom of the casing, damaging both the chain and casing. Casing clearance for maximum wear elongation percentages may be determined from Figure G2-11. Figure G2-11 Casing Clearance Wear Limit

In addition to the clearance to allow for chain sag, there should be at least 3 inches clearance around the periphery of the chain and 3/4 inch on each side of the chain. When a chain casing is used for oil bath, slinger disc, or oil stream lubrication; it may need to be sized for adequate head dissipation. The temperature rise of the oil in a chain casing may be estimated by the use of Figure G2-12 and Figure G2-13 and their accompanying procedures.

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Figure G2-12 Temperature Rise of Oil inside Chain Casing

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Figure G2-13 Values of X

To estimate the probable temperature rise on a chain case, the following formula may be used: T = 50.9 HP/(AK) = °F above ambient where: T = Temperature rise, °F HP = Transmitted horsepower A = Casing area exposed to air circulation in sq ft K = Radiation constant in BTU/sq ft/hour/ °Fahrenheit temperature difference K = 2.0 for still air 2.7 for normal free air circulation 4.5 for rapid air circulation Good practice limits the allowable operating temperature to approximately 180°F (temperature rise plus ambient). If the calculated temperature is greater than this value, a larger casing could be used or an oil cooler added to reduce the operating temperature to allowable limits. The accompanying chart may be used for a quick approximation of possible temperature rise. (Figure G-12, Figure G-13) Explanation: 1. Compute value of "X" and plot point *1 2. Draw vertical line from "X" value (point *1 ) to intersect appropriate centers (pt. *2) 3. Draw horizontal line from "centers" (pt. *2) and read exposed projected casing area (pt. *3) 4. At intersection o{ appropriate HP & horizontal line (pt. "4) (rom step 3, draw a vertical line and read approximate casing temperature rise. (pt. *5) VALUES OF X Standard Casing:

X = P/6 (t + T) + Wc + 9

Oversize Casing: X = R1 + R2 + W where: P = Chain pitch, inches

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t = No. teeth small sprocket Wc = Chain width, inches R1 = Casing radius, small end, inches R2 = Casing radius, large end, inches W = Casing width, inches HP = Horsepower transmitted T = No. teeth on large sprocket A = Area, sq ft

III Maintenance A. Inspection and Service Schedule. A roller chain drive requires proper and timely maintenance to deliver satisfactory performance and life. It is assumed that the shafts, bearings, and supports; the chain and sprockets; and the lubrication type have been properly selected and installed. Then, a maintenance program must be established to assure that: 1. The drive is correctly lubricated. 2. Drive interferences are eliminated. 3. Damaged chains or sprockets are replaced. 4. Worn chains or sprockets are replaced. 5. The sprockets are properly aligned. 6. The chain is correctly tensioned. 7. Guarding is in good condition and is properly installed. A roller chain drive should be inspected after the first 50 hours of operation. After that, drives subjected to heavy shock load or severe operating conditions should be inspected after each 200 hours, and more ordinary drives may be inspected after each 500 hours of operation. Experiences may indicate a longer or shorter interval between inspections. At each inspection, the following items should be checked and corrected when necessary. In addition, the maintenance person should refer to the "Inspection and Service Checklist" following Appendix A.

B. Inspect Lubrication System. For manual lubrication, be sure that the lubrication schedule is being followed and the correct grade of oil is being used. If the chain is dirty, clean it with kerosene or a nonflammable solvent and relubricate it. For drip lubrication, check the flow rate and be sure that the oil is being directed onto the chain correctly. For oil bath, slinger disc, or oil stream lubrication, be sure that all orifices are clear and that oil is being directed onto the chain correctly. Change the oil after the first 50 hours operation, and after each 500 hours thereafter (200 hours in severe service).

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C. Inspect for Damaged Chains or Sprockets. Inspect the chain for cracked, broken, deformed, or corroded parts; and for tight joints or turned pins. If any are found, find and correct the cause of damage, and REPLACED THE ENTIRE CHAIN. Even though the rest of the chain appears to be in good condition, it very probably has been damaged and more failures can occur in a short time. Inspect sprockets for chipped, broken, or deformed teeth. If any are found, correct the cause of the damage, and REPLACE THE SPROCKET AND CHAIN. Sprockets are stronger and less sensitive to damage than chain, but running a worn chain on new sprockets can ruin the new sprockets in a short time.

D. Inspect for Chain Wear. In most roller chain drives, the chain is considered worn out when it has reached 3% wear elongation. With 3% wear, the chain does not engage the sprockets properly and can cause damage to the sprockets or chain breakage. In drives with large sprockets (more than 66 teeth), allowable wear is limited to 200/N which may be substantially less than 3%. And, in fixed-center, non-adjustable drives, allowable wear may be limited to as little as one-half of one chain pitch wear elongation. To determine chain wear elongation, rotate the sprockets in opposite directions to make one span tight. Then, measure a representative section of the tight span, as shown in Figure G2-14 and Table G2-4, and if wear elongation exceeds 3 % or a functional limit, replace the entire chain.

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Figure G2-14 Measurement of Chain Length for Wear

Table G2-4 Chain Wear Elongation Limits

Do not connect a new section of chain into a worn section because it may run rough and damage the drive.

E. Inspect for Sprocket Wear. A worn out sprocket is not nearly as well defined as a worn out chain. However, there are some sprocket characteristics that indicate when a sprocket should be replaced. Check for roughness or binding when a new chain engages or disengages the sprocket. Inspect for reduced tooth thickness and hooked tooth tips (Fig. G2-15).

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Figure G2-15 Worn Sprockets

If any of these conditions are present, the sprocket teeth are excessively worn and the sprocket should be replaced. Do not run new chain on worn out sprockets because it will cause the chain to wear rapidly. Also, do not run a worn chain on new sprockets because it will cause the sprocket to wear rapidly.

F. Inspect for Sprocket Misalignment. Inspect for significant wear on the inside surfaces of the chain roller line plates and on the sprocket flange faces. If this type of wear is present, the sprockets may be misaligned. Realign the sprockets as described in the installation instructions to prevent further abnormal chain and sprocket wear. If 5% or more of the link plate thickness is worn away (Fig. G2-16), or if there are sharp gouges in the link plate surface, the chain should be replaced immediately. Figure G2-16 Chain Measurement Wear

If 10% or more of the sprocket tooth flange thickness is worn away (Figure G2-17), the sprocket should be replaced.

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Figure G2-17 Sprocket Misalignment Wear

Measure the total mid-span movement (Fig G2-3), and if it exceeds the tabulated limit, adjust the center distance to obtain the required amount of slack. If elongation exceeds the available adjustment, and wear elongation still has not exceeded 3% or the functional limits, remove two pitches and reinstall the chain. If the minimum adjustment limit' will not permit shortening the chain two pitches, the chain may be shortened by one pitch using an offset line or an offset section.

G. Inspect Guards. Inspect the guards to ensure that they are in serviceable condition. The guards must not be bent or deformed so that intended clearance is reduced. An designed openings in the guards (mesh) must not be enlarged. The guards must not be broken or damaged, especially at or near the mounting points. If the guards are found to be in serviceable condition, reinstall them on the drive; making sure that all fasteners are secure and that all safeguarding devices (such as presence sensors and interlocks) are functioning.

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Roller Chain Drive Troubleshooting Guide Excessive Noise

Chain Climbs Sprocket Teeth

Chain Clings to Sprocket

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Wear on Inside Of Link Plates And On One Side Of Sprocket

Tight Joints

Turned Pins

Enlarged Holes

Cracked Link Plates (Fatigue)

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Cracked Link Plates

Broken Pins

Broken, Cracked, or Deformed Rollers

Pin Galling

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Worn Link Plate Contour

Battered Link Plate Edges

Missing Parts

Rusted Chain

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Chapter G: Chains and Sprockets

Corroded or Pitted Chain

Missing or Broken Cotters

G4 - Glossary of Roller Chain Terms PITCH -- Distance from the centerline of one pin to the next. ROLLER WIDTH -- Width of the rollers. BUSHING -- Fits inside rollers, similar in looks but smaller in diameter and longer. Pressed into inside link plates. PIN -- Fits inside bushing and holds the outside linkplates together. Pressed into outside linkplates. LINKPLATES -- Total of four, two inside and two outside. Holds chain together. MASTER LINK -- Also known as CONNECTING LINK. Used to shorten chain by one pitch. Replaces one pin link and one roller link. CONNECTING LINK -- Same as above. HALF LINK -- Also known as OFFSET LINK. Used to shorten chain by one pitch. Replaces one pink link and one roller link. OFFSET LINK -- Same as above. COTTERS -- Heat treated spring steel wires formed into a shape on two legs with an eye that is used to help hold link plates on pins. COTTER PIN CHAIN -- Chain with pins riveted on one end and has cotter pins on the other end. RIVETED CHAIN -- Chain with both ends of the pin riveted or side masked. ANSI -- American National Standards Institute. API -- American Petroleum Institute.

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Chapter H: Rotary Hose & Swivel

Chapter H Rotary Hose and Swivels

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Table of Contents - Chapter H Rotary Hose and Swivels H1. Rotary Hose Specifications ................................................................................................................ H-4 I. Introduction ..................................................................................................................................... H-4 II. Specifications ................................................................................................................................. H-4 H2. Rotary Hose Care And Maintenance .................................................................................................. H-9 I. Recommended Dimensions ............................................................................................................ H-9 II. Care And Maintenance ................................................................................................................ H-10 H3. Swivels Specifications ...................................................................................................................... H-12 I. Swivel Pressure Testing ................................................................................................................. H-12 II. Swivel Gooseneck Connection ..................................................................................................... H-12 III. Swivel Subs ................................................................................................................................ H-13 H4. Inspection ........................................................................................................................................ H-14 I. Inspection ..................................................................................................................................... H-14

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Chapter H: Rotary Hose & Swivel

Chapter H Rotary Hose & Swivel The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study.

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H1. Rotary Hose Specifications I. Introduction API Spec 7 (1990), Section 17 defines rotary drilling hose as the flexible connector between the top of the standpipe and the swivel which allows for vertical travel. It is usually made in lengths of 45 feet and over. Rotary vibrator hoses are flexible connectors between the mud pump manifold and the standpipe manifold to accommodate alignment and isolate vibration. They are normally 30 feet in length or less.

II. Specifications A. Dimensions Rotary drilling and vibrator hoses shall be furnished in the sizes, lengths and dimensions given in Table H1-1a.

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Table H1-1a Rotary Drilling and Vibrator Hose - Working Pressure

Additional lengths of vibrator hose and drilling hose may be ordered in five foot increments. B. Connections Rotary hose assemblies shall be furnished with external connections threaded with line-pipe threads as specified in API Spec 5B.

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C. Test Pressure Each hose assembly will be individually tested by the manufacturer. Test pressure is specified in Table H1-1b.

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Table H1-1b Rotary Drilling and Vibrator Hose - Test Pressure

D. Working Pressure Pressure surges are added to the operating pressures and the total pressure must not exceed the working pressure rating in Table H1-1.

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Figure H1-1 Rotary Drilling and Vibrator Hose

Notes for Figure H1-1: F - For Rotary Hose, this dimension shall be 6 inches to 18 inches from the inboard end of the coupling. F - For Vibrator Hose, this dimension shall be 6 inches to 10 inches from the inboard end of the coupling. *NOTE: Hose manufacturers shall mark the hose with the notation "Attach Safety Clamp Here. "

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Chapter H: Rotary Hose & Swivel

H2. Rotary Hose Care And Maintenance I. Recommended Dimensions A. Hose Length In order to avoid kinking of hose, the length of hose and height of standpipe should be such that while raising or lowering, as in making mousehole connections, the hose will have a normal bending radius at the swivel when the hose is in its lowest drilling position and at the standpipe when the hose is in its highest drilling position. The recommended length of hose is given by the following equation, see Figure H2-1. Figure H2-1 Layout for Rotary Hose

Lh = Lt/2 + nR + S Wherein: Lh = length of hose, in feet. Lt = length of hose travel, in feet. R = minimum radius of bending of hose, in feet, = 3 ft for 2 inch hose = 4 ft for 2-1/2 and 3 inch hose = 4-1/2 ft for 3-1/2 inch hose S = allowance for contraction in Lh due to maximum recommended working pressure, in feet, which is 1 ft for all sizes of hose. B. Standpipe Height The recommended standpipe height is given by the following equation, see Figure H2-1.

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Hs = Lt/2 + Z Wherein: Hs = vertical height of standpipe, in feet. Lt = length of hose travel, in feet. Z = height, in feet, from the top of the derrick floor to the end of hose at the swivel when the swivel is in its lowest drilling position. When the actual length of hose is greater than the length calculated as above, the standpipe height should be increased by one-half the difference between the actual length and the calculated length. C. Hose Connections The threaded connection on the rotary hose is capable of handling the rated pressure and should not be welded to its connector as this will damage the hose. The connections between the rotary hose, standpipe and swivel should be consistent with the design working pressure of the system. The connections attaching the hose to the swivel and to the standpipe should be as tangential as possible. The use of a standard connection on the swivel gooseneck will insure this relationship at the top of the hose. The gooseneck on the standpipe should be selected to provide for connecting the rotary hose at an angle 15 degrees from vertical (Figure H2-1).

II. Care And Maintenance A. Handling To minimize the danger of kinking, the hose should be removed from its crate by hand, laid out in a straight line, then liked by means of a catline attached near one end of the hose. If a catline is used to remove the hose from its crate, the crate should be rotated as the hose is removed. The use of a carrier to protect the hose in moving to a new location is a recommended practice. It is considered bad practice to handle hose with a winch, to hang the hose from a truck gin pole, or to place heavy pieces of equipment on the hose. B. Twisting Hose should not be intentionally back twisted. Twisting is sometimes employed to force the swivel bail out of the way. This places injurious stresses on the structural members of the hose body, because one spiral of reinforcing wires is opened and the other is tightened, thus reducing the resistance of the hose to bursting and kinking. In order to prevent twisting, it is suggested that a straight swivel be installed on one end of the hose. Each length of hose has a longitudinal lay line of a different color than the hose cover. This should be used as a guide in making certain the hose is installed in a straight position. C. Clearance The hose installations should provide adequate clearance between the hose and the derrick or mast. D. Safety Chains The safety chains should be as short as possible without restricting the movement of the hose when the swivel is at its highest point and lowest point of operations. The safety chain at the standpipe end of the hose should be attached to a derrick upright rather than to a transverse girt, the chain can then move upward should the traveling block be raised too high. The safety chain at the swivel end of the hose is attached to the lug on the swivel body or housing.

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E. Vibration and Pulsation Continual flexing is injurious to drilling hose and reduces its service life. Pulsation dampeners should be installed in the mud pump discharge line and suction stabilizers installed in the mud pump inlet line to reduce the magnitude of the pressure surges. Pre-charge pressures for the dampeners and stabilizers will be stated by the manufacturers. F. Working Temperature Working temperature should not exceed 180

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H3. Swivels Specifications I. Swivel Pressure Testing A. Pilot Model The pilot model of rotary swivels shall be pressure tested. This test pressure shall be shown on the swivel nameplate. B. Castings All cast members in the swivel hydraulic circuit shall be pressure tested in production. This test pressure shall be shown on the cast member.

II. Swivel Gooseneck Connection A. Dimension The angle between the gooseneck centerline and vertical shall be 15 degrees (Figure H3-1). Figure H3-1 Swivel Connection

The size of swivel gooseneck connections shah be 2, 2-1/2, 3, 3-1/2, 4, or 5 inch nominal line pipe size as specified on the purchase order. B. Threads Threads on the gooseneck connection shall be internal line pipe threads conforming to API STD 5B, Threading, Gaging, and Thread Inspection of Casing, Tubing, and Line Pipe Threads. C. Marking Swivel gooseneck connections conforming to this specification shah be marked with the size and type of thread as shown in the following example: 3 API LP THD

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III. Swivel Subs A. Dimensions Swivel subs shah conform to the outside diameter, bore, and bevel diameter requirements for the upper kelly connections as specified in API Spec 7. B. Swivel Sub Connection The lower connection of rotary swivels shah accept API gages and be interchangeable with API connections. The connection shall conform to the applicable requirements including gaging and marking as specified in API Spec 7.

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H4. Inspection I. Inspection All hoisting tools on the rotary drilling rig must have daily inspections followed by monthly and quarterly (more frequent if severe operating conditions or loading is imposed) shutdown inspections. A. General Inspections 1) Field inspection of hoisting equipment in an operating condition should be made by crew or supervisor on a daily basis. 2) The monthly inspection is The same as The daily inspection except the equipment is shutdown, all oil and grease removed from surfaces to be inspected (use detergent if necessary) and paint is removed from high stress areas. The equipment should be kept clean by a daily hosing and/or brushing in order that the daily in-operation visual inspection can be effective. Persons inspecting hoisting equipment on a daily basis should look for cracks, loose fitting connections or fasteners, elongation of parts and any signs of excessive wear or overloading. Any equipment found to show cracks, excessive wear, circ., should be removed from service immediately. 3) The quarterly inspection is the same as the monthly inspection -- this inspection is recorded on a log sheet and retained for future reference. B.

Disassembly Inspection

1) Equipment should be taken to a suitably equipped facility and all parts checked for excessive wear, cracks, flaws, etc. Visual and non-destructive (NDT) techniques are used. Where, in the opinion of the user, excessive wear is noted, it is recommended that the matter be discussed with the manufacturer. 2) The equipment should be disassembled as much as necessary to permit NDT inspection of all load bearing parts. 3) All parts must be cleaned, by a suitable method, of all dirt, paint, grease, oil, scale, etc., before inspection. 4) The inspection is to be made by only technically competent personnel. 5) Minor cracks or defects, which may be removed without reducing safety or the operational rating of the equipment, can be so removed by grinding or filing (preferably in consultation with manufacturer). 6) Following removal of the defect, the part should again be inspected by an appropriate NDT method to insure that the defect has been completely removed. 7) For other than minor defects or cracks, refer to REPAIRS which follows. C. Repairs CAUTION: Repairs and modification, including welding, without approval of the manufacturer can substantially reduce the rating of the tool. 1) If repairs are not performed by the manufacturer, such repairs should be made in accordance with methods or procedures approved by the manufacturer. 2) If the tool or part is defective beyond repair, it should be destroyed immediately upon so determining. 3) Field welding should not be done on any hoisting tools, because without full knowledge of the design criteria, the materials used and the proper control when welding (stress relieving, normalizing, tempering, etc.), it is possible to reduce the strength of the tool sufficiently to make its continued use dangerous.

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In addition to the daily and quarterly GENERAL INSPECTIONS, the rotary tool joint connections in the drill string, above the rotary table, must be independently inspected for integrity or indications of possible failure. D. Frequency of Inspection It is the responsibility of the owner/operator to dictate the frequency of these inspections. In this matter, it is suggested that reference be made to records of previous inspections, if deterioration is progressing it may be necessary to make inspections at a rate of more than normal frequency. Consideration should be given to drilling conditions, loading of the drill string, tensioning when hoisting underreamers, pulling the kelly with junk in the hole, bit stuck on bottom, etc. As a minimum these inspections should be made prior to drilling to any of the deeper formations or after drilling approximately 50,000 feet in shallow areas. These connections should also be inspected every time the drill pipe is inspected. E. Inspection Methods Normally the inspections are made by specialty companies having the proper equipment, gauges and trained personnel. Any of the present methods; ultrasonic frequencies, magnetic particle or other electromagnetic techniques, if they are approved by the owner/operator or the contractor, should be satisfactory. In the absence of the specialty companies, the swivel body (stem) tool joint box, the pin-and-pin swivel sub and other rotary tool joint connections above the rotary may be inspected by using a liquid penetrant. The cleaner, the penetrant and the developer can be obtained for spray application or for an immersion method of testing. The American Society for Testing and Materials (ASTM) outlines in their publication E165-75, an immersion method for this testing. Some training may be required for the proper interpretation of liquid penetrant inspections. F. Inspection Procedures When inspections are made by specialty companies they will outline the inspection procedures. When inspections are made with liquid penetrant, follow the instructions prescribed by the manufacturer of the penetrant or ASTM specification. The cleaning of the area to be inspected will be an important factor in obtaining satisfactory results from liquid penetrant testing. It is not easy to clean the bore of the swivel body (stem) especially on smaller swivels, but it has to be done. A slow speed electric drill with a wire buffer wheel on a shaft extension can aid in this internal cleaning. Mechanic's mirrors or a bore-scope may be needed to check the cleaning and inspect the testing area. Always use approved thread gauges to check each box and pin before making-up any of these rotary tool joints. Remember, all standard tool joints above the rotary have left hand threads. Obtain a written report of all test results and make the report a part of your permanent records. G. Possible Causes of Tool Joint Failures * Failure to inspect and gauge the tool joints. * Infrequent inspections and gauging. * Improper interpretation of test results. * Worn thread gauges. * Damaged box or pin prior to make-up. * Box and pin not squarely shouldered.

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* Galled tool joint threads. * Crooked kellys. * Loose connection (not fully torqued). * Fluid cut connections. * Drilling with rotary table tilted. * Strain on drill string exceeding yield strength of pipe or tool joints. CAUTION: Any leak or wash-out, no matter how small, must be investigated immediately upon detection. Suspend operations at once and replace or renew the affected tool joint sub, connection, etc. Refer to INSPECTION and INSPECTION PROCEDURES before considering any repairs in this area.

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Figure H4-1a Inspection of Rotary Swivel - External

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Figure H4-1b Inspection of Rotary Swivel - Internal

Inspection Guide: 1) Check for Wear, 2) Check for Cracks, 3) Check for Wear and Cracks, 4) Refer to "Disassembly Inspection"

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Chapter I: Engines - Care and Maintenance

Chapter I Engines

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Table of Contents - Chapter I Engines I. Engines - Care And Maintenance ............................................................................................................ I-4 I. Installation ........................................................................................................................................ I-4 II. Maintenance ................................................................................................................................... I-9 III. Operating Troubles And Their Causes - Diesel Engines ................................................................. I-14 IV. Intake Vacuum vs Load ................................................................................................................ I-18

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Chapter I: Engines - Care and Maintenance

Chapter I Engines - Care and Maintenance The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study. The contents of this chapter were updated under the direction of Mr. Paul O'Conner of O'Conner & Young Drilling Company.

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I. Engines - Care And Maintenance I. Installation A. General 1. Mounting. All engines should have solid, vibration-free, mounting. Installation of box-base type engines with full-length supports is desirable. Shims or other precision methods should be used to avoid uneven support and distortion of the engine structure. 2. Leveling. Engines should be as level as possible. Install shims (preferably stainless steel) when necessary. 3. Alignment. The alignment of the engine with the driven equipment should comply with the recommendations of both engine and driven equipment manufacturers. Before aligning, both engine flywheel and flywheel housing, as well as the driven equipment, should be checked for runout resulting from handling or service. Alignment may be maintained with shear blocks or dowel pins. 4. Flexible Coupling and Drum or Open-type Air Clutches. During initial installation of driven equipment, shafts and hubs should be aligned to the flywheel before installing coupling or clutch. Proper alignment procedure considers angular, parallel and runout. (Figure I1-1A)

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Figure I1-1A Parallel Misalignment

FIGURE I1-1A: Parallel (or bore) misalignment occurs when the centerlines of the driven equipment and the engine(s) are parallel but not in the same plane as shown above. Extreme caution must be exercised to prevent thrust loading of the engine crankshaft. This, and misalignment can result in severe damage to the engine. Most flexible couplings will tolerate only a minimum of misalignment. Refer to the manufacturer's specifications for maximum limits. Figure I1-1B Face Runout

FIGURE I1-1B: Face runout refers to the distance the face of the hub is out of perpendicular to the shaft centerline as shown above.

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Figure I1-1C Face Alignment

FIGURE I1-1C: Angular or face alignment occurs when the centerlines of driven equipment and the engine(s) are not parallel as shown above. Figure I1-1D Bore Runout

FIGURE Il-ID: Bore runout refers to the distance the driving bore of a hub is out of parallel with the shaftcenterline as shown above. 5. Sheaves, Bearings and Clutch Shafts. Drive pulleys should be mounted as close to the engine as possible. This places the load near the clutch main bearing and tends to reduce the overhang load on the bearings. Caution should be exercised in installing excessively large-diameter or heavy drive pulleys. Heavy tools or excessive force should not be used to drive sheaves or similar equipment on the clutch shafts. Such procedure can damage bearings and cause difficulty in the removal of sheaves. The recommendations of the manufacturer for such installation should be carefully followed. Taper bushing type is best.

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6.

Engine Exhaust.

Each engine exhaust system should be of sufficient size so that back pressure at the engines does not exceed manufacturer's recommendation. It is desirable to include in the exhaust piping a short section of flexible tubing or expansion bellows for vibration isolation, thermal expansion, and ease of alignment on installation. Exhaust piping should be independently supported to prevent damage to the engine. Care should be exercised to prevent welding slag or any foreign material from entering the engine during installation. Do not connect exhaust from several engines to a common header. All exhaust systems should be protected against water entry and a suitable trap and drain provided to prevent condensate from returning to the engine. 7. Protection Against Weather. Proper protection against weather should be provided during storage or installation. For storage longer than a few days, use the protection materials and methods recommended by the engine manufacturer. Engines should not be stored with the cooling system in a dry condition as this promotes rust and deterioration of seals. The cooling system should be flushed, filled, circulated and stored with a sufficient solution of clean water, antifreeze, and rust inhibitor. 8. Engine Cooling System. Only clean water, soft or treated, should be used in the engine cooling system. Do not use distilled or chemically softened water. Add corrosion inhibitors every 250 hours (1 month) of operation. Permanent antifreeze contains a rust inhibitor which deteriorates in a short period of time and must be replaced at regular intervals. Some antifreezes have no rust inhibitor. Provide and mark suitable system drains. Unless antifreeze is to be used, drain complete system including air intercoolers and intercooler circulating lines in cold weather. All water system piping should comply with engine builder's size recommendations. The top tank of the radiator, or the expansion tank when using heat exchangers, should always be the highest point in the system and always higher than the cylinder heads with no high point air traps. 9. Cooling Air. Engines should be oriented to take advantage of prevailing winds. Suction or blower fans should be used as best suited to conditions. When engines are installed inside buildings, sufficient openings should be provided for the intake and exhaust of cooling air. Any danger of recirculating the cooling air should be eliminated by the use of ducts.

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Where thermally actuated cooling water control valves are used, the capillary tubing should be as short as practical in order to prevent interference from outside temperature sources. Exhaust stacks, crankcase breathers, and other sources of oily vapors should be vented to prevent build-up on radiator cores and the contamination of dry-type air cleaners. 10. Fuel System. When installing fuel piping, all foreign material should be removed from lines before they are connected to the engine. Lines of adequate size should be installed and adherence to safety codes should be observed. Adequate strainers and liquid traps should be provided in the fuel system. Day tanks are recommended for diesel engines. It is desirable to include a section of flexible tubing for vibration isolation. Non-restricting shut-off valves should be provided in the fuel lines immediately adjacent to the engine. Gas regulators, their orifices and springs should comply with the engine builder's recommendations. 11. Battery Starting Systems. The battery should be installed in a clean, cool, ventilated, accessible, and vibration-free location, which is as close to the starting motor as practicable. Before installation, the battery should be checked for correct polarity. Cable size must be adequate to prevent excess voltage drop. 12. Air and Gas Starters. Gas starters must have sealed pinions so that gas cannot enter engine flywheel housing. Where gas starters are used, exhaust gas should be piped a safe distance from the engine. Air starters should have a lubricator. The air receiver should be drained daily to keep water from entering the starter. 13. Control Equipment. Consideration should be given to the use of engine temperature control equipment and to the use of safety devices such as low oil pressure and high water temperature cutoffs. Such devices should be operable and not blocked out. 14. Transporting, Loading and Unloading. Engines can suffer twisted frames or other harm from careless handling. During loading and unloading operations, adequate tools for skidding, or non-crushing slings should be used to prevent such damage. Lifting by winch lines hooked around the engines is not recommended. Lifting eyes on engines and generators are for installation only and should not be used to lift a complete package. Jacking or pushing against the vibration damper or flywheel can cause severe damage. Always check runout after moving engine to new location. Do not use steel bands, load binding straps or chains across the engine crankshaft or pto shaft when hauling engines.

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15. Fire and Explosion Hazards. Consideration should be given to the elimination of all possible sources of fires and explosions, particularly in hazardous locations.

II. Maintenance 1. Daily Inspection. All engine manufacturers have operation and maintenance manuals. These should be read and used. The lubrication and oil change intervals recommended in these manuals are very important and should not be extended without consulting with the manufacturer or his representative. the following suggestions will help to establish a good Preventative Maintenance Program. This material may or may not be covered in the manufacturer's manual. a. Daily Engine Report and Log Book. All work done, the hours of engine operation and the amounts of oil, antifreeze, rust inhibitor and special lubricants used should be recorded daily. Also all gauge readings should be recorded along with ambient temperature and the type of activity you are using the engines for, such as drilling, WOC, or tripping. b Lubrication. The crankcase oil level in both main and starting engine should be checked and oil added if needed. Be careful not to overfill the crankcase as this can damage crankshaft seals and cause the oil to foam. At this time the oil should be inspected for signs of water, fuel dilution, dirty beyond normal conditions, or obviously thickened, or thinned. If any of these exist they should be corrected immediately and the oil replaced at this time. The proper lubricants recommended by the manufacturer must be used. Different manufacturers recommend different grades of crankcase oil for their engines. All points recommended by the manufacturer as requiring daily attention should be checked, eg. fan drive and clutch bearings. c. Cooling System. Coolant water level should be checked and a proper coolant added if necessary. Do not overfill. Coolant level should be above the radiator core. If not, this will cause aeration and result in cracked cylinder heads. When checking the coolant level, the coolant should be checked for signs of oil (crankcase, torque converter, etc.), air bubbles (combustion gases), rust or scum. If any of these conditions exist, the cause should be repaired immediately and the coolant replaced. The entire cooling system including water lines, cylinder block and head should be checked for leaks. These should be repaired immediately to prevent aeration and loss of coolant. Any hoses that have become hard or brittle need to be replaced. If an over-heating problem exists and cannot be corrected by yourself, call for help.

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Do not put a water hose in the radiator and let it overflow as this will destroy your radiator cores. Do not remove thermostats from your engines as this will cause further overheating. Radiator caps on pressurized cooling systems should be removed only when the engine is at low idle or stopped and then only when the engine is at low idle or stopped and then only with extreme caution. Always keep the radiator cap installed on a pressurized system and be certain it is holding pressure. On aircooled engines, the flywheel air screen and air intake stack should be checked, and any foreign material removed. If flywheel air screen or intake stack is very dirty, the fins on heads and cylinder blocks should be inspected and cleaned, if necessary. If cylinder block fins are rusty, they should be thoroughly cleaned with a wire brush. d. Air Cleaners. Air cleaners and breather opening should be checked and cleaned as required according to the design and condition of the cleaner. Oil bath air cleaners should never be run without oil. When cleaning dry type should be taken not to damage the sealing surface or to knock or blow a hole in the element. In extremely dusty conditions air cleaners may need to be serviced several times a shift. Stopped-up air cleaners are a major cause of turbocharger failures. Precleaners and two-stage air cleaners are available and should be considered if extremely dusty conditions prevail. e. Fuel Supply System. The fuel-supply system should be checked by draining the sump traps and strainers. Water (condensation) should be drained from all diesel tanks. Excessive amounts of water should be recorded and reported to rig manager. Buy clean fuel and keep it clean. f. Leaks or Damage. A visual inspection should be made of all water, fuel, lubricant lines, fittings, and valves for indications of leaks or damage. Report and repair any broken or loose mounting bolts, any indication of misalignment or physical damage. g. Malfunctioning or Needed Repair. Any malfunction or repair needed should be reported. Always furnish model, serial number and specification number.

2. Weekly Inspection. The following weekly inspection of engines should be made by a qualified engine operator, who should also record each inspection performed.

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a. Daily Inspection Items. All of the daily inspection items as given previously should also be performed in the weekly inspection. b. Cleaning. If necessary, the engine exterior should be thoroughly cleaned with a non-toxic, non-explosive solvent (not gasoline). Compressed air or hot water should be used for flushing and drying. Care should be taken to not wash or blow dirt into inaccessible locations behind filler openings or into ignition or injection equipment; or on air-cooled engine, into the fins on heads and cylinder blocks. Always dry and relubricate governor and control linkage joints after cleaning. c. Water Pump. Water-pump seals should be inspected and packing on packed-type pumps should be tightened or replaced, if necessary. d. Fan Belts. Fan belts should be checked for proper tension and tightened or loosened, if needed. Do not over-tighten. e. Lubrication of Generator and Accessories. Check your manufacturer's lubrication guide for proper lubrication of all accessories. If you do not have one, ask for help. Many accessories need special lubrication or have hidden or unapparent lubrication points. The oil level on hydraulic governors should be checked and proper oil added if needed. f. Power Take Off Clutch. The power take off clutch should be lubricated and, if required, adjusted according to the instructions of the manufacturer. Do not over-lubricate. g. Gas Regulators. Gas engines should be checked for gas pressure at the primary and final regulators. h. Breather Elements. All removable breather elements should be carefully cleaned and washed in non-toxic, non-explosive solvent (not gasoline). Change oil on those elements requiring re-oiling. Follow instructions carefully on dry type element service. i. Diesel Fuel Filters. Diesel fuel system strainers should be cleaned and filers replaced as scheduled, by the engine builders.

3. Monthly Inspection. The following monthly inspection should be performed by an expert mechanic who should also record each inspection performed.

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a. Daily and Weekly Inspection Items. All of the daily and weekly inspection items as given previously should also be performed in the monthly inspection. b. Ignition System. On spark ignition engines the following ignition devices, depending upon the type used, should be checked: a) magneto point condition, clearances and timing; b) the impulse function; c) the spark-plug gap and heat range; and d) the distributor condition with respect to the automatic advance mechanism. c. Valves. The external appearance of the valve mechanism should be checked, as well as the condition of the valve rockers, push-rod ends, and valve stems. All valve clearances should be set according to the instructions of the engine manufacturer. Valve timing should be checked if an adjustable timing device is provided. The compression on all cylinders should be measured, if the engine lacks power or if the condition of valves and rings is questionable. The functioning of the compression-release device should be checked on diesel engines, if it is used. Engines using hydraulic valve lifters should be checked for sounds of lifter malfunction and the manufacturers inspection procedure followed. d. Starting Equipment. The starting equipment should be carefully tested and inspected. Starting engines should be checked for lubrication and general condition; special attention being given to the mounting bolts, bendix-drive lubrication, engagement linkage, pinion-gear teeth mesh and adjustment, fuel-tank strainer. Manufacturer's recommendations for specific makes and types of engines should be observed. Add the recommended lubricant to air starter lubricant reservoirs and clean air traps of dirt. If electric starters are used, the system should be checked for loose connections, worn wires, or make-shift repairs. e. Engine Mounts. Engine mounts should be inspected and tightened, if required. A check should be made for signs of engine shifting, misalignment, loosening of coupling or sheave, or improper loading. Any shifting should be corrected and all points of alignment rechecked. f. Cooling Fan. The cooling fan should be examined for evidence of physical damage or cracking in the hub or spider area.

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If the fan-hub bearings require lubrication by disassembly and packing or by installation of a special grease fitting, this operation should be performed. g. Safety Shields. All fan belt and shaft safety shields should be repaired and reinstalled. h. Rocker Covers and Inspection Doors. New Gaskets should be used on all rocker covers and inspection doors, if removed. i. Season Check of Cooling System. Particularly at the changes of the season and when starting to use or remove antifreeze, the cooling system should be flushed thoroughly. The thermostats should also be removed and tested for correct functioning. Evidence of scale, sludge, or rust deposits in the cooling system warrants further investigation, and a special cleaning of oil coolers and heat exchangers may be necessary. The proper mix of antifreeze and water is very important. A 50/50 mixture is considered the best except in extremely cold climates. Never run pure antifreeze in a cooling system. Rust inhibitor recommended by the manufacturer should be used at all times and the required additional amounts added every month or 250 hours operating time. lnhibitors recommended by the manufacturer should be used. Soluble oil can damage O-rings. j. Crankcase. Inspection plates should be removed, if the crankcase is so equipped, and a check made for sludge in the crankcase. The oil pump screen should be checked, and cleaned if necessary. k. Safety Devices, Generator, and Battery. A check should be made of safety devices. Check the actual function of "over temperature", low oil pressure, and overspeed shutdowns. If the engines are equipped with backfire valves or crankcase explosion relief valves, these should be checked for condition and evidence of damage. l. Vibration Damper. Inspect the vibration damper for damage, runout, signs of deterioration of loss of viscous material, or looseness. m. Turbocharger. Inspect turbocharger compressor impeller for accumulations of dirt, dust, and oil. Clean according to manufacturer's recommendations. If slack in the bearing or signs of the compressor impeller touching the housing is found, this should be corrected immediately.

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n. Throttle and Governor. The governor linkage and butterfly shaft end should be checked for free movement through their full range. Minor governor adjustments should be made, if needed; and throttle and governor controls should be lubricated. Compounded engines should be synchronized and a careful check made for proper functioning of vacuum gauges, pyrometers, tachometers, oil pressure gauges, torque converter pressure and generator outputs. o. Engine Log Book. The work done, material used, and the time required should be recorded.

III. Operating Troubles And Their Causes - Diesel Engines General When an internal-combustion engine fails to function properly, the causes must be found and corrected promptly. Since most internal-combustion engines react in much the same way to specific maladjustments, a check list of possible causes of trouble often will be helpful in locating the difficulty. Following are trouble shooting hints for diesel engines. 1. Starting Difficulty. If a diesel engine fails to start or does not start readily, the following possible causes of trouble should be checked in an effort to locate the difficulty. a. Fuel failure, low-pressure side. 1. Line valves not open; tank empty. 2. Ice in lines or traps. 3. Cold fuel. 4. Plugged fuel filters, or dirt in lines between filter and pump. 5. Fuel tank too low in relation to transfer pump. 6. Dirt under transfer-pump valves or worn valves. 7. Air lock in fuel pump or injection pump. 8. Safety switch not being held open by operator. Note: The foregoing items may be checked by opening the bleeder valve and cranking the engine. A pressure gage should be used in the bleeder-valve hole to check for primary pump pressure. A hand plunger may be used on the transfer, if desired. A substantial flow of fuel without air bubbles should exit from the bleeder opening. b. Fuel failure, high-pressure side. 1. Enrichment lever not in proper position; rack partly closed in cold weather. 2. Stop control in wrong position. 3. Air locks in high-pressure lines. 4. Broken or disconnected pump-drive coupling.

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Note: The foregoing items may be checked by loosening the line-coupling nuts a few tums at each nozzle and cranking engine. A substantial flow of fuel should occur at each injection impulse. If no fuel appears and an equate flow of fuel is known to have reached the plungers, either the plungers or delivery valves may be stuck as a result of poor fuel, improper storage, or inadequate lubrication. c. Poor nozzle spray pattern or gummed or corroded nozzles. d. Faulty injection timing. e. Glow plugs too cold. f. Battery voltage low. (A fully charged 12-volt heavy-duty battery at normal temperatures will show 10.5 volts while cranking.) h. Poor compression. (Check each cylinder) i. Liquid lock between piston crown and cylinder head due to flushing oil from storage, leaking head gasket, or leaking injector. j. Low cranking speed duc to weak batteries, poor starter condition, or thick, cold oil. 2. Engine Stops Running. If the diesel engine suddenly stops running, the following possible causes of trouble should be checked in an effort to locate the difficulty. a. Lack of fuel. b. Fuel lines obstructed or broken. c. Automatic low oil-pressure or high water-temperature safety control may have operated. d. Excessive overload or improper governor adjustment may cause the engine to stall. e. Plugged fuel-tank vent. f. Damaged transfer or injection pump drive. 3. Low Power. If the diesel engine has low power and runs unevenly, the following possible causes of trouble should be checked in an effort to locate the difficulty. a. Inadequate supply to fuel to pump. b. Fuel-tank vent partially plugged. c. Faulty timing. d. Delivery valves not operating properly. e. Dirty or damaged injection plunger. f. Leaking fuel lines or air in lines. g. Damaged or excessive clearance in blowers. h. Overflow valve or injector drain line feeding back into primary pump inlet.

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i. Dirty or clogged nozzles. j. Air cleaner or manifold obstructed. k. Low or uneven compression. 1. Broken valve spring. 2. Sticking valves. 3. Badly worn rocker arms. 4. Sticking cam followers. 5. Bent throttle control linkage. 6. Binding of injector-rack control tube or injector racks. l. Fuel oil not to specification. m. Improper exhaust line. n. Leaking turbocharger air connections. o. Dirty or damaged turbocharger. p. Improper intercooler operation.

4. Surging or Irregular Speed. If the diesel engine develops a surge or irregular speed, the following possible causes of trouble should be checked in an effort to locate the difficulty. a. Governor needs lubrication. b. Improper grade of governor oil (hydraulic governors). c. Governor improperly adjusted. d. Injection pump. 1. Lack of lubrication. 2. Insufficient fuel supply for primary system. 3. Irregular operation of automatic bleeder valve; air entrapment in pump and lines, valves, or nozzles. 4. Inaccurate pump timing. e. Slipping clutch or belt drive; wide variation in loads of poor regulation on electrical equipment. f. Dirty or damaged turbocharger system. 5. Overheating. If the diesel engine overheats, the following possible causes of trouble should be checked in an effort to locate the difficulty. a. Excessive exhaust back pressure. 1. Restricted muffler or loose baffles in muffler. b. Cooling system.

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1. Insufficient coolant. 2. Radiator frozen or clogged (tubes and tanks). 3. Radiator core dirty (external). 4. Water hose clogged. 5. Slipping fan belt. 6. Thermostat stuck. 7. Cooling system inadequate. 8. Improper air recirculation. 9. Aeration of water from leaking gaskets or pump. 10. Defective water pump. 11. Excessive back pressure on external cooling system. 12. Air shroud, air stack, cylinder-head fins or cylinder-blocked with debris. c. Combustion. 1. Improper fuel. 2. Faulty injection timing, retarded or wrong cycle. 3. Faulty injection nozzle. 4. Pump setting incorrect. d. Lubrication. 1. Improper or excessive time between oil changes. 2. Air-locked or plugged oil filter, cooler, or screen. e. Load. 1. Prolonged service at excessive load. 2. Improper synchronization of two or more engines. f. Installation. 1. High exhaust back pressure to improper piping or muffling. 2. Insufficient air circulation when engines are operating in closed spaces. 3. Improper turbocharging; intercooler too hot.

6. Low or Fluctuating Oil Pressure. If the diesel engine develops a low or fluctuating oil pressure, the engine should be stopped at once and the following possible causes of trouble should be checked in an effort to locate the difficulty. a. Oil. 1. Insufficient oil. 2. Dirty filters, oil coolers, or sump screen.

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3. Improper grade of oil. 4. Foaming oil due to water leakage. b. Valve. 1. Worn, sticking, or loose relief valve. 2. Vent behind relief valve plugged. 3. Inaccurate pressure gauge.

IV. Intake Vacuum vs Load (API Standard) (For use on four cycle engines of two or more cylinders equipped with carburetors for liquid or gaseous fuels.) The vacuum load curves shown in Figure I1-2 are an index of the approximate percentage of power (within three per cent on new engines), that an average engine in proper adjustment will develop at a given location. Figure I1-2 Vacuum Load Curves

These curves are average of curves obtained from six representative engine manufacturers covering many models of 2-1/2" to 9-3/8" bore. They can be used at any altitude at which any non-turbocharged engine can be used. The curves shown cannot be used on turbocharged engines. Instructions for use 1. Be sure engine being checked is in good adjustment. Cheek spark, gas supply, gas pressure, and carburetor adjustment before taking vacuum readings. Use a conventional vacuum gauge with dial graduated to read inches of mercury.

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2. Run engine at normal operating speed NO LOAD and note manifold vacuum. 3. Run engine at normal operating speed LOADED and note manifold vacuum. 4. Select curve to vacuum line indicated on the LOADED engine (Item 3). From this point on the curve follows down vertically to the percentage of load indicated on the horizontal line. NOTE: The manifold vacuum and horsepower an engine will develop decreases with an increase in altitude. Engine manufacturers consider sea level barometric pressure (29.92 inches of mercury) standard. The power developed decreases about 3 per cent with each thousand feet in altitude. Likewise, the no load vacuum decreases with increasing altitude. An engine that will show 20 inches no load vacuum at sea level will show the following no load vacuum altitudes noted at normal operating speeds. Sea Level

20 inches

2,000 feet

18 inches

4,000 feet

16 inches

6,000 feet

14 inches

8,000 feet

12 inches

10,000 feet

10 inches

EXAMPLE: Operator observes engine developing 17" vacuum at no load and normal speed. Load is applied and engine develops 10" vacuum. Follow down 17" curve until it crosses 10" horizontal. Drop down vertically at this point to base line. Engine is developing approximately 48 per cent of full power. Failure to duplicate former readings on properly adjusted engine when running at NO LOAD NORMAL SPEED, will indicate poor engine condition due to poor gas supply, loss of compression, ignition timing, etc. Failure to obtain former readings at NORMAL LOAD and SPEED will indicate either change in engine efficiency or change in load. Field men should become familiar with vacuum curve readings on their engines properly adjusted and in good operating condition to enable them to detect variation in either load or engine condition.

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Chapter J: Pumps

Chapter J Pumps

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Table of Contents - Chapter J Pumps J-1 Introduction - Pumps ........................................................................................................................... J-4 J-2 Surface and Mud System ................................................................................................................... J-13 I. Suction Mud System ...................................................................................................................... J-13 II. Discharge System .......................................................................................................................... J-17 III. Drilling Fluids And Their Effect On Expendable Pump Parts .......................................................... J-18 J-3 Pump Parts, Theory and Function ...................................................................................................... J-23 I. Pistons ........................................................................................................................................... J-23 II. Duplex Piston Rods ....................................................................................................................... J-25 III. Rod Lubricants ............................................................................................................................ J-27 IV. Liner Packing ............................................................................................................................... J-28 J-4 Removal and Installation of Fluid Ends ............................................................................................... J-32 I. General - Removal and Installation of Fluid Ends ............................................................................. J-32 II. Duplex Pump -- Disassembly ....................................................................................................... J-32 III. Duplex Pump-assembly ............................................................................................................... J-37 IV. Duplex Pump -- Piston Assembly ................................................................................................. J-46 V. Single Acting Pump -- Disassembly .............................................................................................. J-54 VI. Single Acting Pump -- Assembly .................................................................................................. J-56 VII. Single Acting Piston Assembly .................................................................................................... J-57 IX. Valve and Seat ............................................................................................................................. J-64 J-5 Pump Problems, Failures and Analysis ............................................................................................... J-74 I. Priming and Starting Instructions ..................................................................................................... J-74 II. Pistons and Liners ......................................................................................................................... J-74 III. Fluid End Piston Rod and Packing ................................................................................................ J-77 IV. Valves and Seats .......................................................................................................................... J-78 V. Reducing Pump Volume ................................................................................................................. J-79 VI. Centrifugal Pump Care and Maintenance ...................................................................................... J-80 VII. Checklists .................................................................................................................................. J-82 J6. Power End Maintenance ................................................................................................................... J-84 I. Pump Storage ................................................................................................................................ J-90 J7. Preventive Maintenance ...................................................................................................................... J-91 I. Planned Preventative Maintenance .................................................................................................. J-91 II. Establishing a Preventative Maintenance Program ........................................................................... J-92 III. Advantages of programming: ........................................................................................................ J-94

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Chapter J Circulation System The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study.

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J-1 Introduction - Pumps A generalized nomenclature system is shown in Figures J1-1 through J1-11. These include comparable components on duplex and triplex pumps and valve pot numbering system. The API monogram is the symbol denoting interchangeability and signifies that manufacturers who are authorized to use the symbol, maintain standards and gauging practices to insure that their parts are universally interchangeable.

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Pump Terminology Code Figure J1-1 Components of the Hydraulic System

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Figure J1-2 Single Acting Mud Pump w/ "L" Head-back Loading

Figure J1-3 Single Acting Mud Pump w/ "L" Head-back Loading

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Figure J1-4 Single Acting Mud Pump w/ Over & Under Valves-front Loading

Figure J1-5 Single Acting Mud Pump w/ Over & Under Valves-front Loading

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Figure J1-6 Single Acting Mud Pump w/ Over & Under Valves-front Loading

Figure J1-7 Fluid End: Duplex Double Acting Mud Pump

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Figure J1-8a Cylinder and Valve Numbering System - Duplex Pump

Figure J1-8b Cylinder and Valve Numbering System - Triplex Pump

Figure J1-8c Cylinder and Valve Numbering System - Sextuplex Pump

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Table J1-1 Power End Parts. Duplex And Triplex

101

Frame

106 *Connecting Rod

111 *Crankshaft Bearing Housing

102 Crankshaft

107 *Crosshead

112 *Pinion Shaft Bearing

103

108 *Crosshead Pin

113 *Crosshead Pin Bearing

Main Gear

104 Pinion

109 *Connecting Rod Bearing

105 Pinion Shaft

114 *Crosshead Extension Rod (Pony)

110 *Crankshaft Bearing (Main) 115 *Crosshead Extension Rod Wiper

*Exact location of these parts designated as right, or left, and center if for triplex pump.

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Figure J1-9 Section through Power End - See Table J1-1

Figure J1-10 Section through Crankshaft - See Table J1-1

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Figure J1-11 Section through Shaft and Crossheads - See Table J1-1

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Chapter J: Pumps

J-2 Surface and Mud System I. Suction Mud System A. Positive Head Particular attention should be paid to the construction of the suction line and the pit or tank fluid level in relation to that of the pump so that minimum net positive suction head requirements at the pump suction flange will be met. Sufficient net positive suction head insures that the drilling fluid will follow the piston on the suction stroke without any void or airspace forming between the slug of fluid and the piston. If an airspace forms in this area, a knock will occur when the fluid contacts the piston at the end of the piston stroke. Beside reducing the efficiency of the pump, knocking will reduce the service life of expendable pump parts and could be detrimental to the power end of the mud pump. The following discussion will pinpoint the numerous trouble spots that may exist in the typical suction system.

B. Mud Tanks and Pits In many installations, a good shale shaker, a suitable mud tank system, and adequate jetting provisions for mud mixing and tank cleaning are adequate. The shale shaker takes out large cuttings and the tanks should have adequate volume for settling out sand and releasing contained gas from the mud. Particular care should be exercised in placing the suction inlet of the pump in the pit or tank. The inlet should be far enough off bottom so that flow will not be restricted and sand will not be drawn into the pump. At the same time, the suction inlet should not be too near the surface or the mud will swirl allowing air to enter the pump suction. This could promote knocking in the pump or at least reduce the volumetric efficiency. The required fluid level above the suction inlet is a function of the pump suction line velocity. If the pump is to be operated with a low fluid level in the tank or pit, the suction line should be sized to reduced suction velocity. It is recommended that the suction line be as large as the regular suction line and no smaller than 8". There should be no loops or sharp bends in the suction line that would restrict the flow of fluid going to the mud pump. It is a good practice to dig a trench so that the suction line goes down gradually to the bottom of the pit rather than down with sharp angles. Use 45 degree elbows rather than a 90 degree elbow where the suction lines goes down into the mud; and in all cases, the suction line leading to the mud pump should be as short and straight as possible. Be sure that all couplings are airtight. If a discharge line is run from the shear relief valve into the pump suction line or manifold, it should be checked at all joints for possible air leaks. This type of arrangement is bad practice as the suction line could become pressurized and possibly cause the line to rupture if a valve wore closed in the suction line, or some other type restriction were in the !inc. Air leaks, which will reduce volumetric efficiency, can be easily checked with soap suds by putting the suds around all suspected joints. the suction line should be checked to determine that the hose lining has not collapsed or separated due to the use of low aniline point oils or from other causes. Check for any accumulation of solids that could collect on the bottom of the line. Many times when two pumps are used on the rig, with one as standby, this accumulation of solids in the pump suction will be excessive and will not be washed out during the short period the standby pump is used. Other times suction velocity is not great enough to keep mud from settling out of the line. Each pump should have its own suction line and not share a suction line with another pump. After a period of time, the accumulation in the suction line will greatly reduce the volume that can be drawn through it. When the rig is moved from one location to another, the suction line and strainer should always be thoroughly washed out. Some contractors install two couplings and rotate the suction line, periodically putting the top on the bottom, which may clear the line of solids. It is good practice to use suction strainers, but they are a potential source of trouble and should be kept clean at all times. Proper tank settling volume and careful location of the pump suction, will reduce the risk of clogging of the suction strainer.

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C. Pulsation Dampeners Pulsation dampeners in mud pump suction and discharge lines serve to absorb the pressure-flow variations normally produced by the reciprocating motion of the pump pistons. If dampeners are not properly maintained and operated, the pressure-flow variations can produce damaging effects to piping and mud pump components. Undamped pressure-flow variations in mud pump discharge lines can produce high pressure spikes and shocks which can result in weld and piping failures, loose connections, ruptured rotary hose, and disturbing hammering noise. In the suction lines, undamped pressure-flow variations caused by many factors, including acceleration head, can adversely effect the volumetric efficiency of the pomp and shorten suction valve life at high pump speeds. Suction linc dampeners provide advantages of higher pump operating speeds without knocking, usage or longer or smaller diameter suction lines, usage of heavier and/or higher temperature muds and provide more efficient use of horsepower, Fig. J2-2. Figure J2-2 Pump Suction Dampener Maximizes Efficiency

FIGURE J2-2: A suction dampener, preferably commercial, should be installed for maximum efficient use of horsepower. To assure smooth and efficient pump performance, pulsation dampeners should be checked daily to assure proper operation and precharge. Always refer to the manufacturer's instructions, which are usually attached to the dampener body, for correct maintenance instructions. Anytime maintenance work is performed on a pulsation dampener the precharge on the dampener must be completely bled off. Component damage and personal injury could result if a dampener is disassembled while still pressurized.

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D. Centrifugal Supercharging Pumps Although suction dampeners are adequate for many conditions, often times a particular mud pump will require a boost in suction pressure to meet its net positive suction head requirements. This pressure boost is normally supplied by a centrifugal pump placed in the suction linc. The primary purpose of the centrifugal precharging pump is to keep the mud pump from being starved by maintaining a positive pressure in the suction line. Many benefits may result from the addition of a centrifugal supercharging pump: 1. Higher pump output. 2. Increased volumetric efficiency. 3. Less expensive hydraulic horsepower. 4. Smoother operation. 5. Longer pump parts life. For maximum benefit a suction dampener should be used in conjunction with the supercharging pump. When designing suction piping, it is best to have an upward slope from source of supply to the centrifugal pump to prevent trapping of air or gas. An eccentric reducer should also be used on the suction instead of a concentric reducer. This will eliminate trapping air in the upper portion of the larger pipe, Figure J2-1. Figure J2-1 Efficient Pump Suction Line

FIGURE J2-1: Suction line must slope upward toward the pump to prevent air pockets. Note for Figure J2-1: An Air Pocket Exists Because An Eccentric Reducer was Not Used, And Also Because Suction Pipe Does Not Slope Gradually Upward From Supply. Air trapped in the suction reduced the cross-sectional area and can cause the pump to cavitate due to its restricted area. Air can also be drawn into the pump through the suction line and lose prime on start up. If a rise in the suction piping must be designed into the system, an automatic air release valve should be installed at the highest point to prevent air being trapped in the suction line.

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Figure J2-3 indicates that a straight piece of pipe at least twice the diameter of the suction should be between the pump and any other equipment. Figure J2-3 Sizing the Pump Suction Line

FIGURE J2-3: There should be a straight section of pipe equal to twice line diameter between pump and any equipment or other connections. Ells and valves cause turbulence. If the fluid is turbulent entering the pump, then increased pump wear will result. Many installations are designed where the fluid is returned to the tank, dropped onto the surface or is jetted into the surface. Both of these procedures trap some air into the fluid. This trapped air will lower your pump life and possibly cause it to lose prime. In oilfield applications, gas or air is often redissolved in the fluid by running guns or hopper returns above the fluid level. Returns to the tank should be below normal operating level, as shown in Figure J2-4.

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Figure J2-4 Return Line to Pump Suction Pit

FIGURE J2-4: To minimize air entering mud, return should be below mud level. A properly selected centrifugal pump and an adequate suction system will insure smooth pump operation and maximum pump efficiency.

II. Discharge System A. Fluid Pressure Pulsation Fluid pressure pulsations in the discharge line shortens the life of the discharge piping and the rotary hose. To reduce pulsations and keep pressure drops in the discharge system to a minimum, piping should be kept as simple and as short as possible. Long radii fittings are preferable in the discharge line. All sections of the line should be firmly anchored to a rigid structure and high pressure hose ends tied against the possibility of whipping freely in case of break. In case severe discharge vibrations occur, "resonant" situation may exist and a change in pump speed, discharge pressure or mud composition may relieve the situation temporarily. If vibrations persist under desired operating conditions, outside help should be obtained to locate and remedy the cause of the trouble.

B. Precharged Discharge Pulsation Dampeners Precharged discharge pulsation dampeners absorb pressure variations, reduce peak pressures, permit slightly higher pump output, and increase discharge line life. When correctly charged to the manufacturer's recommendations, these devices should effectively smooth out discharge pressure variations. If there is any doubt as to the correct charge for a given pumping pressure, contact the manufacturer for assistance. An incorrect charge will render the device ineffective. Pulsation dampeners should be placed as near the pump as possible.

C. Pressure Relief Valve A pressure relief valve must be installed in the discharge line immediately beyond the pump. Its purpose is primarily to protect the pump and discharge line against extreme pressures such as might occur when a bit becomes plugged. The relief valve should be used to limit the pressure in accordance with the pump manufacturer's rating for a given liner size. Usually, relief valves are set to exceed rated pressure by some given amount.

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Setting of a shear-type relief valve too close to operating pressure will result in too frequent replacement of the shear pin nail (ns is commonly used). Continuous pump operation above rating must be normally limited by the operator. Always use protective covers on shear relief valves for protection of personnel. Automatic-resetting relief valves are available which can essentially be adjusted to the relief pressure desired. These relief valves protect the pump to a given maximum pressure and allow continued operation without resetting due to momentary pressure surge. Being independent of shear pin failure, relief pressure may be set close to the pump rated pressure. Any relief valve must be placed before the discharge strainer in the discharge line, otherwise it cannot protect the pump. A relief bypass that is short, without bends, and rigidly anchored, should be used with all relief valves to provide escape for the fluid hack to the mud system. This bypass must not be returned to the pump suction.

D. Cutting and Welding Accepted welding procedures, including preheating and post-heating, should be observed when assembling discharge piping to guard against premature failure. Frequent inspection for leaks and damage should also be made while the discharge piping is in service. Many of the fluid ends now furnished are heat treated or carburized so as to better withstand high stress levels and reduce problems of fatigue. It is recommended that wherever possible no cutting or welding should be done to these fluid ends as any heat applied to these surfaces may destroy the effects of the heat treatment. Valve seats should be pulled with appropriate pullers rather than torch cutting. See section on valve and seat removal for suggested procedure if cutting is required.

III. Drilling Fluids And Their Effect On Expendable Pump Parts A. Aniline Point and Effects Oils used in drilling fluids should have an aniline point of 150 degree F or more to get good service from rubber parts. Under certain conditions, a mud supplier may recommend an oil with an aniline point less than 150 degree F in order to get better mud characteristics. In these cases, the operator must decide if the improved mud conditions justify the increased cost of fluid end parts replacement and damage to pipe protectors, suction end parts replacement and discharge hoses, blow out preventer rams, pulsation dampener bladders and other rubber parts in the mud system. While drilling fluids are generally selected for many reasons other than their effect on mud pump parts, some consideration should be given these effects because excessive mud pump and mud system repairs may overbalance the improved mud characteristics. If it is impossible to change to a high aniline point oil, the best that can be done is to see that equipment is in good or new condition, even then trouble can be expected to continue. Also, remember that high temperatures and high pressures cause more rapid failures when an oil mud us used than when drilling under the same conditions using water base mud. When low aniline oil is no longer required to condition the mud, an additive should be used to raise the aniline point. Diesel oils with high aromatic content are found to be more detrimental to rubber products than those with low aromatic content. Laboratory tests have been confirmed by field experiences, Figure J2-5 and Figure J2-6.

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Figure J2-5 Swelling of Rubber vs Analine Point

FIGURE J2-5: There is drastic change in swelling of neoprene and buna rubber in different aniline point oils. Figure J2-6 Rubber w/ Different Aniline Values

FIGURE J2-6: Graph shows effect of swelling of different rubbers with varying aniline points of oil. The relative aromatic content of an oil is indicative of its aniline point, which is the temperature in degrees, Fahrenheit that the oil and a chemical called Aniline will mix with each other. Oils having a high aromatic content have a low aniline point, and oils with a low aromatic content have a high aniline point. Consequently, the high aniline point diesel oils are the most desirable for use in drilling mud as they will cause less difficulty with the rubber equipment on the rig. Oil should be specified with an Aniline point above 150 degree

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It is difficult to check the aniline point of an oil after it is mixed with the drilling mud due to discoloring, but the aniline point of the oil can usually be obtained from the supplier, as aH refineries know the aniline point of their products. Also, the mud representative handling the drilling mud may know or be able to obtain the aniline point for you, as some of the mud suppliers specify the aniline point of oils used in the prepared muds that they sell. A distillation process can be used to obtain the aniline point if the oil is mixed in the mud.

B. Sand Solids Effect Sand in the mud delivered to the pump suction will seriously shorten the life of pump parts. Where possible, desanders should be used and kept in good working order. Where desanders are not used, large settling tanks or pits should be used with periodic jetting to allow room on the bottom of the tanks for additional settling. There is a popular belief that "API" sand particles are the only abrasives in a mud system. These are sand particles that will not pass through the 200 mesh sand screen, particles below 200 mesh size pass through the sand screen and are not considered as sand content. Abrasive particles in lapping compounds, used to grind valve and sets, are nearly all below "API" sand size or below 200 mesh screen size. Abrasiveness of any particle is determined by its shape and hardness. While it is true that one larger abrasive particle will make a deeper grove and remove more material than one smaller abrasive particle, it is also true that a pound of small abrasive particles applied to a surface will remove approximately as much material as will a pound of coarser abrasives. What appears to be very critical in regard to wear is the amount of solids in the mud. Solids are carried in the system as the viscosity, gel, etc. increase, making drop out of the Particles more difficult. Therefore, if your mud log reflects high percent solids, low sand content and you are experiencing unusual wear rate, the chances are you are carrying a high percent of abrasive solids below 200 mesh screen size.

C. Effect of Entrained Gas or Air and High Temperature High mud temperatures aggravate corrosive conditions which will shorten the life of all metal parts exposed to the mud. High temperature muds are also detrimental to all elastomers in contact with the mud. (Polyurethane is especially vulnerable and should be avoided when the mud temperature exceeds 160 degree F at the pump suction.) the surface area of the mud tanks should be large enough to cool the hottest mud circulated to the desired temperature on the hottest days anticipated. Mud temperatures should be kept below 150 degree F at the pump suction to avoid flashing in the liner which results in the partial Fillings of the liner and resultant loss of volumetric efficiency. The effect of mud temperature can be illustrated by Figure J2-7.

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Figure J2-7 Mud Temperature Increase Reduces Effective Suction

FIGURE J2-7: Rise in mud temperature reduced the equivalent fluid level and effective suction. If the mud is 100 degree F and is allowed to rise to 150 degree F, this 50 degree F rise corresponds to a reduction of the mud level in the pit or tank of 6.3 feet. In Figure J2-8, note that in system B the mud level is 5 feet below system A. Figure J2-8 Effect of Mud Temperature on Suction

FIGURE J2-8: Schematic sketch indicates in practical manner effect of mud temperature on effective suction. If temperature rises 50 degree F in system B, the mud level effort would then be equivalent to 11.3 feet below system A. In system C, fluid level is 5' above the center linc of the liner. If this 50 degree F temperature rise takes place in system C, even a flooded suction, then there would be an equivalent fluid level of minus 1.3 feet below the pump center line. This reduction in fluid level pressure head when combined with atmospheric pressure may not be sufficient to force or push the suction valve completely open and partial or no filling of the liner would be the result.

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D. Effect of pH High pH muds (caustics in the concentrations found in drilling muds) have no appreciable effect on the life of metal pump parts provided they are properly mixed before they reach the mud pump. Caustics do shorten the service life of elastomers. Low pH (acidic) can cause severe corrosion of metal parts in just a few hours. Muds should be at least slightly alkaline (7.5 pH or higher) except in certain instances where specific conditions are to be met.

E. Effect of Hydrogen Sulfide and Carbon Dioxide The primary hazard resulting from encountering hydrogen sulfide is the loss of human life without warning -- the gas is fatally toxic. The maximum safe level of hydrogen sulfide for normal working conditions is no higher than 20 rpm. Concentrations as low as 150 ppm will cause irritations of the eyes, the respiratory tract, and deadening of the olfactory nerves so the ability to detect odors is lost. Being exposed to a concentration of from 800 to 1000 ppm for a short period of time, as little as two minutes, may result in death. A secondary hazard of hydrogen sulfide is its drastic effect on high strength steel. H2S is soluble in water and produces a weak diabasic acid. This acid is troublesome to high strength steels and often results in embrittlement and catastrophic metal failure. Some understanding of the physical and chemical action of H2S is vital to the safe and successful handling of this gas in drilling operations. Frequently referred to as sour gas, H2S smells like rotten eggs in low concentrations. In higher concentrations it kills the sense of smell. It is highly flammable and forms explosive mixtures with air. !t is heavier than air and will accumulate in low areas, such as in the cellar beneath the rig floor, or in low-lying areas around drilling locations. H2S is soluble in drilling muds and its solubility in water is approximately proportional to the pressure. This relationship holds true for the solubility of H2S in water up to about 4 to 5 atm. But for extremely high pressures such as the hydrostatic pressure of the mud column, the hydrogen sulfide may be liquefied and the simple relationship may not hold true. Normally, the higher the temperature, the lower the solubility of the gases. Carbon dioxide (CO2) often accompanies H2S during a gas flow. Carbon dioxide dissolved in water will react to it to form mild carbonic acid. In comparison to H2S, the water solution of carbon dioxide is not considered very toxic but is corrosive to steel. A solution of CO2 water is known as sparkling water. The bicarbonate or carbonate ion can be formed in an alkaline environment with pH changes. At higher pH value (or more alkaline conditions) the carbonate form would be favored. Since H2S is nearly three times as soluble in water as carbon dioxide, if aeration occurs, carbon dioxide will be removed first. If the hydrogen sulfide is present in an alkaline solution it is not effectively removed by aeration. In drilling fluids, aeration as occurs in waterflooding is not a practical method for removing the hydrogen sulfide gas.

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J-3 Pump Parts, Theory and Function I. Pistons Pistons perform as a moving seal. The piston rubber acts like an "o" ring bridging the gap between the piston flange and liner bore, Figure J3-1. Figure J3-1 Piston Rubber Acts as an "O" Ring

The higher the pressure the smaller the gap must be to prevent the piston rubber from extruding and tearing. How critical the clearance between piston flange and liner bore is to piston life is illustrated in the graph, Figure J3-2.

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Figure J3-2 Proper Clearance Under Pressure Promotes Piston Life

FIGURE J3-2: Proper clearance under various pressure conditions is important to prevent extrusion and have better piston life. For example, if the clearance is 0.040" at 3000 psi, a set of replacement rubbers can be expected to last only 50% as long as they would on a new piston in a new liner with a clearance of 0.010". Since there are no API standards on the piston flange OD, this will vary from manufacturer to manufacturer. As the piston fails, there is high velocity fluid slipping between the piston flange and liner bore. With a slow failing piston or if a failed piston is allowed to run, this jetting fluid will cause wash out damage to piston flange and liner bore and dragging of piston flange in liner bore 180 degree from the wash out, Figure J3-3. Figure J3-3 Flange Damage by Fluid Jetting Round Worn Piston

FIGURE J3-3: Fluid jetting around worn piston causes damage to flange and liner bore.

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The cost of a piston is small compared to the cost of a liner, so every effort should be made for early detecting and replacement of piston failures to prevent extensive damage to the liner bore. In low pressure operations it is permissible to change piston rubbers if the piston flange is not washed out or excessively worn. On pistons where wear grooves are provided, the grooves can indicate how much wear has taken place and may serve as a guide to piston or piston rubber replacement. Still, it is well to remember that if new piston rubbers are installed on worn or washed piston bodies, the piston will fail earlier than if the rubbers were installed on a new piston body with full gage piston flange. Figure J3-P1 Effect of Clearance on Piston Life

Notes on Figure J3-P1: << Left. When clearance is excessive between piston flange and liner, pump pressure forces part of the piston rubber into the clearance where it is pinched off. The result is short piston rubber life. Right >> When liner and piston flange fit closely, pressure cannot extrude rubber into the clearance to be pinched off. The result is long life for piston rubber. Piston rubbers will tend to burn or at least wear rapidly in single action pumps if the piston and liner are not flushed adequately with coolant. The amount normally ranges from 5 to 10 gallons per minute per liner but it's best to refer to the manufacturers recommendations in order to keep the liner cool and flush any piston leakage from the liner. A method of cooling is to direct a spray into each pump liner. Care must be taken to get complete coverage with this technique or liner walls may not be completely flushed. Several different arrangements are in use to accomplish proper flushing and cooling. The arrangement should allow complete flushing of the entire stroked area in the liner and should increase the service life of both the piston assembly and the liner. Proper cooling becomes more critical as pump speed increases.

II. Duplex Piston Rods Duplex pump piston rods must be replaced periodically because they wear on the OD as the rod strokes through the rod packing. The pump rods are designed to be wear resistant in this area and the manufacturers generally offer both a standard grade and premium grade of rod. Most of the high pressure rods on high horsepower duplex pumps require both a corrosion and abrasion resistant coating for heavy duty applications, Fig. J3-4 and Fig. J3-5

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Figure J3-4 File-Gard Rod in Corrosive Drilling Fluid

FIGURE J3-4: This File-Gard rod was run in a corrosive drilling fluid. Notice the severe pitting that drastically shortens the useful life of both rods and packing when corrosive fluids are being pumped. Figure J3-5 Rod Scouring by Excessive Packing Tightening

FIGURE J3-5: Excessive tightening of packing has resulted in scoring of this rod.

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A premium grade rod should be used which may have a chrome plated coating over case hardened steel or a sprayed and fused layer of hard metal such as nickel -chrome boron. The nickel -- chrome boron coating is more abrasion and corrosion resistant than chrome plating and generally should last longer. As the rod wears, the high polish and absence of corrosion pitting tends to reduce packing wear. The standard metal pump rods are not coated, but are heat treated to be as hard as the costlier premium rods. Although the standard rods lack the corrosion and wear resistance that premium rods exhibit, they should provide satisfactory service in lower pressure non-corrosive environments.

III. Rod Lubricants There are three general types of lubricants currently being used on rods. 1. Clear water, in some areas, serves as coolant and flush but has very little lubricating qualities. 2. Engine oil cut with diesel oil. If oil is being used the viscosity of the mixture should be equal to SAE 5 motor oil. A suggested mixture is 10 parts diesel oil to one part of SAE 40 oil. 3. Soluble oil. If soluble oil is used, a satisfactory solution can be made from about 10 to 20 parts of fresh water to 1 part of soluble oil. Soluble oil is being used more and more. Soluble oil is a good lubricating fluid for rubber, and does a superior job of cooling and flushing. Any accumulation of drilling mud and abrasives that get into the soluble oil reservoir will readily settle to the bottom of the settling pan, reducing the chance of the sand being picked up and recirculated through the rod lubricating system. The settling pan should be cleaned out regularly so that abrasives will not clog the pump inlet or be recirculated through the lubricating system to cause unnecessary wear to the rod and packing. Water will evaporate, and the solution will become more concentrated; add more water to dilute the concentrate. Soluble oil is not usually found on drilling rigs unless it is used in the cooling system of the engine, but it is readily available from sources that supply either your diesel or lubricating oils. Suitable typos of soluble oils can be obtained from bulk distributors. The rod lubricating system reservoir should be checked to see that it is clean and all residue discarded. If the pump is running slowly, the quantity of lubricating fluid should be sufficient to lubricate and cool both rods properly. The rod oiler pump should supply at least one gallon per minute per rod. The necessary amount should be determined by what coolant is being used and the type of lubricating system in use: gravity, spray, force feed, etc. If the mud pump is being run at slow speeds and the proper volume is not being delivered to the rods by the oiler pump, steps should be taken to speed up the oiler pump. There should be enough coolant supplied to the oil for the coolant to run to the bottom of the rod before it is wiped off by the packing. If the oil is heavy and will not run to the bottom of the rod; or if the volume is insufficient, the packing will wipe off the oil before it can get to the underside of the rod. It is difficult to get coolant to run to the bottom of a large diameter rod. Usually the coolant will drip from the large diameter and not run underneath, Figure J3-6.

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Figure J3-6 Rod Damage by Improper or Insufficient Lubricants

FIGURE J3-6: If rod is large and lubricant is heavy, or there is insufficient volume, rod will be damaged.

IV. Liner Packing Each manufacturer has his own design for a liner packing. One type of packing is the all rubber liner packing and is recommended only for low pressure, low horsepower pumps. All rubber liner packing is generally an oil resistant packing and is used in low pressure pumps and pumps without telltale holes or pumps that require narrow or special shaped packing. The special sizes and shapes are furnished in accordance with the pump manufacturer's specifications. High pressure liner packing can be used in pumps with high, medium, or low pressure applications. The High Pressure Liner Packing is more popular inasmuch as it will generally out-last conventional regular rubber packing. Liners are easier to pull with top quality packing that does not extrude and wedge under the liner, locking the liner in the pump. The liner packing makes a seal around the liner separating each end of the liner. The fluid pressure in the head acts on the packing first, and then the pressure from the power end acts on it. It must be tightened firmly to withstand the continual pressure reversals. Any movement of the packing causes wear in the pump cylinder. One type of packing is provided with metal end rings used in conjunction with nylon back-up rings and a rubber seal packing ring. The zero clearance design using the metal end rings compensates for previous minor damage and wear in the pump bore. The metal end ring restores worn shoulders in the pump housing, Figure J3-7.

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Figure J3-7 Correction of Worn Pump Shoulders by Metal in Packing

FIGURE J3-7: Worn end of pump cylinder is replaced with metal end ring in one type of packing. One cause of this wear is the removal of the liner from the pump cylinder when liners are changed, Figure J3-8. Figure J3-8 Pump Cylinder can be Damaged while Replacing Liners

FIGURE J3-8: Pump Cylinder can be damaged with replacing liners. The major cause of the rounded shoulder is the continual movement of the packing around the shoulder. The packing wants to extrude into this clearance on each pressure stroke of the pump. As sand and abrasive particles work their way under the packing, a small grinding action takes place. With time, wear occurs, Figure J3-9.

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Figure J3-9 Damage of Pump Cylinder caused by Pump Movement

FIGURE J3-9: Major cause of wear on end of pump cylinder is movement on each stroke. Another type of high pressure packing has cotton fabric (duck) reinforced corners or other similar techniques to support the corners and prevent extrusion. The lantern ring, if not worn, washed out, or damaged, should be saved and reused, as it is one of the most expensive parts of a set of packing, Figure J3-10.

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Figure J3-10 Remove Lantern Ring Carefully

FIGURE J3-10: The lantern ring should always be removed carefully from the liner that was removed from the pump and reinstalled on the new liner using new liner packing. The lantern ring should be thoroughly inspected for any nicks or burrs. If the lantern ring is still in good condition, all that is needed to repack the liner is a Packing Kit. The lantern ring should be the proper width for the packing selected. Not all packing manufacturers use the same width lantern ring. As you will note in Figures J1-2, J1-3 and J1-6, some single acting mud pumps do not use liner packing that seals on the OD; but rather a gasket in the recessed end of the liner that seals against the fluid cylinder.

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J-4 Removal and Installation of Fluid Ends I. General - Removal and Installation of Fluid Ends The purpose of this section is to present general practices recommended to be used in replacement of fluid end parts. Mud pumps, despite their extreme size, are actually very precisely engineered pieces of equipment, manufactured to very close tolerances and fits. If good procedures are not followed and replacement parts are installed carelessly, you will most likely have shortened service life of these parts and possible severe damage to the pump. It is important, therefore, that replacement parts be installed properly. Most manufacturers of pumps or pump parts publish recommended procedures for installing parts of their manufacture and these instructions should be followed.

II. Duplex Pump -- Disassembly A. External First loosen the liner adjusting nut and/or the liner packing screw, then remove the cylinder head and liner cage (when applicable). To keep the packing and wear surfaces clean, wash all mud off before it hardens.

B. Piston and Rod Loosen the rod packing gland and the rod lock nut. Be sure to use a backup wrench on the pony rod while moving the piston rod, otherwise it may be loosened in the crosshead. Care should be exercised in keeping the pipe wrench off the wear surface of both the piston rod and pony rod. Once the piston rod has been loosened in the pony rod, it is easier to remove the piston rod by turning it with a rod removal tool, Fig J4-1, Fig J4-2, Fig J4-3, and Fig J4-4. Figure J4-1 Removal of Pump Rod

FIGURE J4-1: Screw the rod removal tool onto the pump rod and line up the splines so that the collar on the tool can be slipped forward to engage with the splines on the rod nut. Once the sleeve has been slipped over the piston rod nut, the tool and rod nut are locked together and removal or installation can be started.

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Figure J4-2 Removal of Pump Piston

FIGURE J4-2: Using the rod removal tool to turn the rod is much simpler than using a pipe wrench to remove pump rods from pony rod once the rod has been broken loose from the pony rod. Similarly, installation is much easier when the tool is used to make up the rod in the pony rod. Final closure should be done using a 36" or 48" pipe wrench applied to the rod crosshead end knurl.

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Figure J4-3 Removal of Pump Rod

FIGURE J4-3: This method of piston removal is much faster and easier than any other method in use. Figure J4-4 Removal of Pump Rod

FIGURE J4-4: After the piston is knocked free of the liner, the removal tool can be used as a handle.

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Notice how the sleeve slips over the rod nut to lock against rotation during removal. If a rod removal tool is not available, a discarded rod nut with a welded handle and a pinch bar may be useful, Figure J4-5 and Figure J4-6. Figure J4-5 Removal of Pump Piston and Rod

FIGURE J4-5: In the absence of special rod removal wrench, a standard rod nut with a loop welded on as shown is a time and labor saver. First this special nut is screwed on at the end of the rod.

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Figure J4-6 Removal of Pump Piston and Rod

FIGURE J4-6: After the nut is screwed on the rod, a chain is hooked around the loop and a crow bar is used to pull piston and rod out of liner as shown.

C. Liner Position the liner puller in the liner and check to make sure the fingers or hooks make good positive contact on the end of the liner. Pull the liners. Before any attempt is made to install a new liner, the pump should be thoroughly cleaned of all accumulation of sand, grit, mud and old pieces of packing. Take a piece of welding rod or wire and clean out the telltale hole to be sure it is not plugged with pieces of old liner packing and dried mud, Figure J4-7.

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Figure J4-7 Pump Liner Removal

FIGURE J4-7: After removing the liner, the pump bore should be thoroughly cleaned and all pieces of packing removed. The telltale hole should then be cleaned to be sure that it is open to the packing area. The liner packing areas or shoulders should be thoroughly inspected for nicks, burrs and excessive wear. Look for cracks in the pump body itself. This inspection should be done very carefully with a good light since trouble, if found early, can be repaired before the pump is seriously damaged.

D. Rod Packing Remove all of the old rod packing and adapters from the stuffing box. Thoroughly clean the stuffing box and all metal parts. Check for any damage or wear to the stuffing box, brass cage and junk ring. Excessively worn junk rings should be replaced.

III. Duplex Pump-assembly A. Liner Packing Before commencing with installation, a final check should be made to see: 1. That you have the correct packing. 2. The pump bore is clean. 3. The pump bore has been inspected for wash outs or damage. 4. The telltale holes are not clogged. 5. That the packing adjusting studs on the cylinder head have been backed off.

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When the liner packing areas have been thoroughly cleaned and inspected, the area holding the packing should be greased with a general purpose grease. DO NOT USE PIPE DOPE, since it does not provide the lubrication necessary for this application. Each piece of packing should be greased thoroughly with the same general purpose grease. Grease is recommended instead of oil because the grease will fill up voids or openings and help keep sand out of these areas. As each piece of packing is greased, it should be placed in the pump and pushed all the way forward to the shoulder. Be sure packing parts are installed in proper order. On some pumps, the liner packing should be installed on the liner prior to placing the liner in the pump. Some pumps are designed so that the liner shoulders in the pump and makes up metal-to-metal with the liner cage. In this ease, the packing is installed after the liner is in place. (See subsection B, Liner, below.) Wear of the pump housing due to liner movement and housing shoulder wear due to liner installation and removal procedures, causes clearances to increase. Bridging and sealing of this clearance becomes even more difficult. Packing that has reinforced corners of metal end rings tends to reduce this gap and give longer packing life, Figure J4-13, Figure J4-14 and Figure J4-15.

B. Liner The bore of the liner should be thoroughly cleaned of rust inhibitor. This rust inhibitor has no lubrication value, and will actually cause an early piston rubber failure. Once the packing is in place, the liner should then be lifted into position. While resting on the open end of the pump, the liner barrel should be thoroughly greased with particular attention to guide and packing areas. The liner should then be pushed carefully through the packing. The fit of the liner into the pump bore and the packing is very snug -- but it is not a force fit. It will sometimes be advantageous to bump the liner so as to pass through the rear liner pad. Never will it be necessary to drive or jack the liner in place. If the liner installation is difficult, the liner should be removed from the pump and the pump housing and the liner O.D. should be thoroughly checked again for any foreign material or burrs either in the pump housing or on the liner. On some pumps, the liner will hang down and catch on the rear guide pad; and in cases of this typo, it will be necessary to lift the back of the liner to get it over the rear pad. Some pumps are designed so that the liner goes in and rests against a shoulder in the pump and makes up metal-tometal with the liner cage. In cases of this typo, the packing may be installed after the liner is in place, but again all areas should be thoroughly greased. When installing liner packing in a pump, after the liner is in the pump, it will be easier to install the bottom section of the liner packing first. Once the bottom section of the liner packing is installed, the remainder of the packing can be pushed into place while the crewmen let the weight off the liner. Once a packing ring is started into the pump, it should be pushed all the way forward and then the next succeeding ring started in a like manner. Never use a sharp object to pound or push the liner packing into place. It is preferred that the hand be used or possibly use the handle of a hammer, but never use a screw driver or the sharp end of a file. All other parts such as liner retainers and liner cages should be thoroughly greased before installing in the pump with particular attention being given to the webs and parts of the assembly which bear against the packing. These retainers should be inspected for burrs or wash outs which will greatly shorten the liner packing life.

C. Piston and Rod After the piston is installed on the rod (See VII. Assembly of Single Acting Piston Assembly) you are ready to install the piston and rod in the pump. Check to see that the stuffing box has been thoroughly cleaned and all old packing has been removed. A rod removal and installation tool will make the installation of the piston and rod much easier, Fig J4-1 and Fig J4-2. FIGURE J4-1: Screw the rod removal tool onto the pump rod and line up the splines so that the collar on the tool can be slipped forward to engage with the splines on the rod nut. Once the sleeve has been slipped over the piston rod nut, the tool and rod nut are locked together and removal or installation can be started.

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FIGURE J4-2: Using the rod removal tool to turn the rod is much simpler than using a pipe wrench to remove pump rods from pony rod once the rod has been broken loose from the pony rod. Similarly, installation is much easier when the tool is used to make up the rod in the pony rod. Final closure should be done using a 36" or 48" pipe wrench applied to the rod crosshead end knurl. The liner bore and piston should be well lubricated, Figure J4-8. Figure J4-8 Lubrication of Liner and Piston w/ Grease

FIGURE J4-8: The liner and piston should be well lubricated with general purpose grease before installing piston in liner. The grease makes installation considerably easier, and it also helps protect the surface of the piston during the initial priming period. Note: Grease is not recommended for regular rubbers. See other section for instructions on regular rubber installation. If the pistons are made from an oil resistant compound, the liner bore and piston should be thoroughly lubricated with a general purpose grease. Never use pipe dope as this material is not recommended as a lubricant for this application. If the pistons are made from natural rubber, then no oil or grease should be used in the liner or on the piston. A solution of detergent used in drilling muds or rig washing compounds can be used. Lubricating the piston and liner not only makes installation easier, but also helps protect the piston and liner surfaces during the initial priming period. Due to the close fit of the piston in the liner bore it is very important that the piston be centered in the bevel of the liner. If this operation is not performed correctly, severe damage can occur to the lip of the power end piston rubber, causing it to fold back between the liner and piston rubber. Feel with your hand to be sure the gap between the bevel and the rubber lip is equal all the way around, Figure J4-9 and Figure J4-10.

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Figure J4-9 Centering of the Piston Rubber

FIGURE J4-9: The piston rubber must be centered in the entering bevel of the liner to prevent the piston lip from being turned back against the liner bore while installing. Use your hand as illustrated to be sure the lip of the piston rubber is being started into the bevel all the way around. Figure J4-10 shows the piston rubber lip starting into the bevel of the liner correctly.

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Figure J4-10 Starting the Piston Rubber into the Liner Bevel

FIGURE J4-10: When the piston is perfectly centered, solidly bump the installation tool to start the piston in liner. Using a knocker, the piston can be driven completely into the liner. On pumps where room permits, it is easier to pull the piston into the liner rather than drive it in. Install the hammerup jam nut on the rod after it has passed through the stuffing box. As one man centers the piston in the liner bevel, another man prying against the jam nut with a pinch bar pulls the piston into the liner, Figure J4-11. Figure J4-11 Using Pinch Bar to Pull Piston into Liner

FIGURE J4-11: Use pinch bar to pull piston into liner. The piston rod should not be driven back against the pony rod since this might damage the threads of both.

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Once the rod packing is in place (See Rod Packing Installation), the piston rod can be connected. First, a visual inspection should be made of the threads in the Pony Rod and also on the pump rod to make sure that there are no burrs or broken threads. The threads on the pump rod should be lightly lubricated before screwing the rod into the Pony Rod, make sure that the hammer-up lock nut has been placed on the rod first. The face of the hammer-up lock nut that contacts the Pony Rod face should be true and square so that when the hammer lock nut is made up tight the threads will not be stressed unevenly, Figure J4-12. Figure J4-12 Jam Nut must fit Square

FIGURE J4-12: A jam nut that does not fit square against the pony rod is a common cause of crosshead end thread failures. Such a nut causes a severe stress concentration at the root of the threads and may cause the rod to break at this point. Note how the nut makes contact with the pony rod on one side, while there is considerable clearance on the opposite side. Crosshead threads should be made up according to the pump manufacturer's specifications. Generally, straight threaded rods should be made up until they bottom and then backed off two or three turns, except for a few rods which are designed to bottom out in a recess in a Pony Rod. The hammer lock nut should now be tightened by holding a bar against one of the lugs and striking the bar several times with a sledge, Figure J4-13.

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Figure J4-13 Tightening the Hammer-up Lock Nut

FIGURE J4-13: After tightening the piston rod in the pony rod or positioning the rod, as in the case with straight threads, be sure that the hammer-up lock nut is tightened with several hard blows with a sledge to be assured that the piston rod is locked in place in the pony rod.

D. Rod Packing The proper installation of rod packing can make the difference in packing and rod life. The stuffing box should always be inspected to be sure it is in good condition and that all brass is good and not washed or worn. The I.D. of the stuffing box should be inspected for wash outs and egg-shaped conditions. When the box is bad, the rod packing may fail between the packing and stuffing box and not around the rod. On pumps that rely on lubrication through a hole in the stuffing box, the lubrication hole should be cleaned thoroughly to make sure it is free of any accumulation of pieces of rubber or mud; this lubrication line may become blocked and the packing will burn out in a short time. In preparing the packing for installation in the pump, each piece of packing should be thoroughly oiled by soaking all pieces of packing in oil before installing in the stuffing box. Do not grease when installing the oil soaked rings. Grease may become trapped between packing lips and prevent the lips from flexing properly. Also, grease may hold any sand that may wash between the packing lips. It is important to oil the stuffing box as well as the rod and all the pieces of brass. This lubrication will make the installation and removal of the packing much easier, and the packings will be assured of lubrication on the start up. If it is impossible to slip packing over the end of the rod, the packing pieces should be opened by twisting the packing apart, rather than by bending the ends away from each other. On most pumps, there is a full entering bevel in the stuffing box which makes installation of the packing easier; but on some, the bevel is very small. If the stuffing box is new, the fit is tighter. On high pressure packing designed with an outside lip to seal against the stuffing box, the outside lip of the packing must be protected and not turned back when the packing is pushed into the stuffing box. Experience has shown that it is easier to start the packing into the box on the side that is next to the inside of the pump. By lifting the rod, the weight of the rod can be taken off the bottom of the stuffing box; and by pulling the rod toward you, the packing can be easily started on the inside, and the next to the bottom side, Figure J4-14.

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Figure J4-14 Installing the Pump Packing

FIGURE J4-14: The lips of the packing should be placed toward the piston with the cuts staggered. When installing each piece of packing, it is easier to start the packing parts on the back side of the rod and on the bottom first. The use of a bar to lift the weight of the rod off the bottom will help and as soon as the bottom is star,ed and the back side, take the bar away and the weight of the rod will compress the packing permitted the rest of the piece to be easily installed. Always push each piece of packing all the way forward using a small, dull tool. The gland spacer and adjusting nut can now be installed. Tighten gland nut to seat the packing and then back off. See break-in instructions. Then release the rod; the weight of the rod will compress the packing at the bottom of the box, making installation at the top of the box easier. The rest of the installation of the piece of packing will be relatively simple as you have working room and can see when to push on the packing. Once the first ring is in place, the rod becomes centered, making installation of the other rings easier. Use your fingers to be sure that the lip is not turned back on any part of the packing you cannot see. Each piece of packing should be pushed all the way forward in the stuffing box. The piston rod installation tool should be left connected to the rod as you can thereby shake the rod, and installation of packing is made easier. As each piece of packing is installed in the stuffing box, the cuts on the packing should be staggered so these cuts will not line up with each other. When pushing the packing forward in the stuffing box, do not use sharp objects and do not force. Just a steady bumping will push the parts forward. Many rigs save their old pieces of worn-out brass and make installation tools from these pieces by attaching two or three metal bars to them and hammering on these metal bars, pushing evenly against the packing. Once all the pieces are installed in the stuffing box, the threads of the stuffing box should be cleaned and lubricated. The gland nut then can be made up hand tight. Do not overtighten the gland nut because the packing will swell as it absorbs coolant and circulating fluid. After several hours use, the packing expansion will diminish, then the gland nut can be tightened as require.

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Overtightening of the new packing before the packing swell has stabilized is one of the quickest ways to damage a rod and ruin a packing, Figure J4-15. Figure J4-15 Scoring of Rod by Overtightening or Lack of Lubrication

FIGURE J4-15: This rod has been severely scored. This condition can be caused by over tightening the rod packing or recirculating abrasives through the rod lubrication system. Run rod packing as recommended by the packing manufacturer and keep rod lubrication reservoir clean of all abrasives and mud. Follow packing manufacturer's recommendations for tightening.

E. Cylinder Head Cylinder heads are designed to provide a method of holding the liner and the liner packing in place and retain the fluid being pumped. There are many different designs in use, depending on operating pressure and service for which the pump is intended. In all cases, however, the cylinder head must retain the full fluid load and in high horsepower, high pressure pumps this can be quite large. Therefore it is essential that careful maintenance of cylinder heads and related Parts be maintained. Before installation, all parts, i.e. cylinder heads, liner retainer and cages should be cleaned and inspected for burrs, wash outs and cracks. Thoroughly clean and grease the packing areas and install new packing. If the cylinder head is equipped with liner packing adjusting screws and liner adjusting screws, make sure these screws are backed out before making the cylinder head up tight on the pump. This will eliminate the possibility of excessive tightening of liner and liner packing resulting in damage to cylinder bores, cages, set screws and liner, Figure J4-16.

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Figure J4-16 Liner Ruined by Excessive Tightening of Liner Packing

FIGURE J4-16: This liner was ruined by excessive tightening of the liner packing. The most common cause for this damage is failing to loosen the liner packing adjusting screws before tightening the cylinder head nuts. Refer to the pump manufacturer's maintenance manual and tighten cylinder head and set screws to manufacturer's recommended torques. Cylinder head must be square with the face of the fluid and therefore the nuts should be tightened evenly in a criss-cross manner.

IV. Duplex Pump -- Piston Assembly A. Removal The piston nut should be loosened until it is flush with the end of the rod. It is never good practice to remove the nut from the rod because when the piston comes loose from the taper, it can come off with a great force and could cause injury to some standing nearby. The nut also protects the threads on the end of the rod from being damaged. With the rod held in a vertical position and on solid foundation, a heavy object is dropped against the shoulder of the piston, Figure J4-17.

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Figure J4-17 Knocking Piston off Piston Rod

Figure J4-17. Drop heavy object such as sub to knock piston off rod. A solid foundation, such as a skid or rig floor, should be used for this operation. Where the piston hub is nearly the same size as the rod O.D., drop the heavy sub against the piston flange. When dropping the sub against the piston flange, remove the back snap ring, plate, and piston rubber. Where the rod diameter is larger than the hole in the piston plate, it will be necessary to cut the back rubber from the piston and then push the plate down against the piston flange; then drop the sub on the plate which is resting against the piston flange. By dropping any heavy object several times against the flange or hub, removal of the piston can be accomplished. Under no circumstances should the piston be vibrated off by hammering on the rod, Figure J4-18.

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Figure J4-18 Damage to Piston Rod caused by Hammer Marks

FIGURE J4-18: The lower of the two photographs above shows a section of piston rod that has been struck repeatedly with a hammer. Notice that while the cracks are not visible to the naked eye, they show up when the rod is magnafluxed (upper of the photographs). These cracks form the beginning of rod breaks. This practice severely damages the rod and in many cases, has caused breakage in the rod. If the piston is to be saved, the taper should be greased and the piston put in a safe place where heavy equipment is not likely to fall on it.

B. Piston Assembled to Rod When installing a new piston on the rod, the rod taper must be thoroughly cleaned with a solvent, and thoroughly dried with a clean cloth. Even a small amount of oil left on the taper such as would be found in diesel oil, is enough to let the piston work up the rod taper, expand the flange, and possibly cause the piston to seize in the liner. After the rod taper has been thoroughly cleaned and dried, the piston taper should be thoroughly cleaned of all rust inhibitor and thoroughly dried. With both tapers dry, the piston is pushed on the rod; it should go solid and stick on the rod taper. The threads on the rod should now be thoroughly cleaned and lubricated with general purpose grease, as should the face of the piston that the nut will turn against, Figure J4-19.

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Figure J4-19 Greasing of Rod Threads and Piston Face

FIGURE J4-19: After the piston has been put on the rod hand tight, the rod threads and face of piston should be greased. This greasing of the threads will make installation and removal of the rod nut easier and protect the threads from galling. The greasing of the threads and the piston face after the piston has been installed on the rod, will make the installation and removal of the nut much easier. the threads should be greased after the piston has been placed on the taper so that no grease is dragged onto the taper as the piston is slid over the threads. The rod tube, in which the rod is shipped, should be saved and the rod stuck back in this tube. the rod is then inserted into a pump skid, or suitable holding device for the operation of torquing up the piston rod, Figure J4-20.

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Figure J4-20 Protecting the Rod Threads while working over Pump

FIGURE J4-20: When removing the piston from the rod, put a rod tube on the rod to protect the threads and the wearing surface of the rod and put both in the end of the pipe that makes up the engine or pump skid. In case the piston rod tube is not available, the crosshead threads should be protected by burlap or a rag securely tied around the threads. It is wise to protect the area of the rod that contacts the pump skid using wood from liner crates, or burlap. As a rule, the nut on the rod is splined and should be tightened with a splined wrench of the same size, Figure J4-21.

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Figure J4-21 Use Splined Nut Wrench to Prevent Damage to Nut

Figure J4-21. The use of the splined nut wrench as shown will prevent crushing of the nut. The spline nut wrench is safer to use than the pipe wrench. However, if this is not available, a 36 or 48 inch pipe wrench will have to be used. A pipe wrench is not recommended for makeup of the rod nut because the jaws of the pipe wrench can pinch or collapse the nut causing it to bind or gall on the rod threads, Figure J4-22.

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Figure J4-22 Pipe Wrench can Crush Nut and cause Galling of Threads

Figure J4-22. Pipe wrenches are prone to crush the rod nut and cause galling results in removal problems. The wall section of the splined nut is very thin and will deform under a crushing force such as exerted by a pipe wrench. A false torque reading can be obtained and the piston may not be tight on the rod taper if the nut is crushed. The piston must be made up with the proper torque, as too little torque will cause the piston to work loose and wash between the rod and the taper, Figure J4-23. Figure J4-23 Damage Caused by Fluid Cutting

Figure J4-23. This fluid cutting could have resulted either from dirt or grease on rod or piston taper, or insufficient tightening of the piston end nut.

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The piston flange diameter will increase approximately 0.002 to 0.004 of an inch as the piston is forced up the taper, when the piston is made up with the proper torque. 1. On standard API tapered non-shouldered reds, if the tapers are not thoroughly cleaned and dry, the pump pressure could drive the piston up the taper and lock the piston in the liner. This could result in broken rods, cracked liners and severe damage to the pump. Care should be exercised to use the proper make up torque for each particular rod taper, Figure J4-24. Figure J4-24 Torque for API Rod Connections

Overtightening could excessively expand the piston flange diameter making installation in the liner difficult or impossible. 2. On the API-HP tapers, installation and torque procedures are very critical since the piston must shoulder on the rod as the joint is prestressed, to reduce the magnitude of the high pressure cyclic stress which leads to rod breakage from fatigue (See API Section J7). To prevent wash outs on the taper and rod breakage, the following installation procedures should be carefully adhered to: a. Place piston on rod taper hand tight. Piston must stand off from rod shoulder from 1/32" to 3/32". b. After placing piston on rod, lubricate rod threads and nut face to prevent galling. c. Draw piston rod' shoulder with nut. d. After initial shoulder contact, make relative position of nut and piston with punch mark, paint stripe, grease stripe, etc.

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Figure J4-25 Making up the HP Connection

FIGURE J4-25: As soon as the HP piston shoulders on the HP rod, continue tightening until the designated number of splines has been indexed past the point where contact was made. On an API-6 nut turn 2-1/2 - 3 splines and on an API-5 nut turn 2 -- 2-1/2 splines past the contact point. This step is very important in making up the HP connection. e. Continue tightening 60 degrees to 72 degrees This would be 2 -- 2-1/2 splines on an API-5 rod nut with 12 splines or 2-1/2 -- 3 splines on an API-6 rod nut with15 splines. Experience has shown that the vast majority of HP rod breakage is due to improper prestressing of the HP joint.

V.

Single Acting Pump -- Disassembly

A. Single Acting Pump -- "L" Head (Figure J1-2 and Figure J1-3) 1. Piston and rod removal - Single Acting Pump -- "L" Head Rotate the pump so that the piston rod is in the rear stroke position. Some pumps have an extension on the pinion shah allowing the pump to be easily rotated with a suitable pipe wrench or crank. To prevent washouts on taper of rod and piston, tighten rod taper nut as follows: Particular care should be taken with GD-1, and API-1, -2, and -3 tapers, as the threads are likely to twist off if the above recommended tightening force is exceeded. API-5 and API-6 rods should be tightened as recommended above. Too little tightening force may result in a washout failure at high operating pressure. Disconnect the liner flush and coolant assembly and liner splash shield. Remove the piston rod clamp. Most of these pumps use a two piece rod, some use an additional clamp while some are threaded. Remove the extension rod. The piston rod and piston assembly can now be removed without disturbing the liner. Removal of piston rod and piston assembly can be facilitated by looping a chain or rope around the rear flange on the piston rod, or attaching a special pry tool available on some of the threaded rods, and using a pry bar to pull the assembly from the liner. If a pry bar is used, be careful not to damage the rod joint faces.

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2. Liner Removal - Single Acting Pump -- "L" Head Liner removal in the single acting pumps is relatively simple and easy compared to the duplex pumps. "L" head pump liners are seated and held in place by external retaining assemblies. One type, Figure J1-2, utilizes a bevel clamp. To remove this liner you simply remove the clamp and move the liner out of the pilot bushing with a pry bar between the collar on the liner and the end of the pilot bushing. Use care not to damage the shoulders with the pry bar. Another type, Figure J1-3, uses a threaded liner retaining nut equipped with set screws that align with a slot in the liner. These set screws have the single function of assisting in removal of the liner and should not be tightened against the liner wall. To remove this liner you engage the set screws in the slot, the liner nut should be free to turn, and as you unscrew the liner nut, the set screws pull the liner. When the liners have been removed, wash the pump out thoroughly in preparation for installation of the new liner.

B. Single Acting Pumps -- Over and Under (Figure J1-4, Figure J1-5 and Figure J1-6) 1. Piston and Rod Removal - Single Acting Pumps -- Over and Under Rotate the pump so that the piston rod is in the forward stroke position with the rod clamp exposed. Disconnect the liner flush and coolant assembly and liner splash shield. Remove the rod clamp or unscrew threaded rods. The latter operation may require a back-up wrench on the crosshead rod, otherwise it may be loosened in the crosshead. Remove the cylinder head and liner cage if applicable, Figure J1-4. Once the piston rod has been loosened from the crosshead rod it is easy to remove the piston and rod by using a rod removal and installation tool (Figure J4-3). If a rod removal tool is not available, you can push the rod and piston out by using a piece of timber between the crosshead rod and the piston rod while rotating the pump by hand.

2. Liner Removal -- Single Acting Pumps -- Over and Under Liners in the over and under pumps may be retained by external clamps, Figure J1-5 and Figure J1-6, or by a liner cage Figure J1-4. Some are loaded from the power end, Figure J1-6. Some are loaded from the fluid end, Figure J1-4 and J1-5. Removal of liners loaded from the power end, Figure J1-6, is easily done by simply using a piece of timber to jar the liner loose. It can then be removed by hand. Liners loaded through the fluid end can be easily removed by using timber and pushing the liner out by rotating the pump by hand. Care should be exercised to see that the liner is pushed straight and not allowed to cock. When liners have been removed, wash the pump out thoroughly in preparation for installation of the new liner.

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VI. Single Acting Pump -- Assembly A. Liner Installation Thoroughly clean the guide areas in the retainer bushing or liner housing, then the face of the fluid cylinder which the liner packing will seal against. These areas should be completely free of all foreign material such as barite and rust. Since the liner makes up metal-to-metal with the fluid cylinder, even small accumulations of foreign material may cause the liner to cock -- resulting in excessive wear to the liner and piston. The new liner is coated with a rust inhibitor to protect it during shipping. This coating has no lubricating value, and will actually damage the piston rubbers if it is not thoroughly removed from the I.D. of the liner. Use diesel oil or some other suitable solvent to remove the protective coating and dry the bore of the liner with a clean cloth. Inspect the liner gasket ring groove and the liner surfaces that contact the pump cylinder. These areas should be absolutely clean and free of nicks and burrs. Apply a light coat of general purpose grease to the guide and shoulder areas on the outside of the liner. Likewise grease the guide areas in the liner retainer bushing or cylinder housing and the face of the fluid cylinder on the pump itself. On pumps loading from the power end, Figure J1-2, Figure J1-3 and Figure J1-6, install gasket on the liner before installing the liner in the pump. Lightly grease the gasket and reinstall it in the recessed area provided in the end of the liner. Now, slide the liner into position in the pump. When the liner is securely in place -- replace the liner retention assembly, and tighten to the pump manufacturer's specifications. After you have tightened the liner retention assembly, reach through the liner to the packing area and feel with your fingers to be sure the liner packing is still in place. On pumps loading from the fluid end, Figures J1-4 and Figure J1-5, installation of the liner is best accomplished by two men. On pumps that retain the liner externally, Figure J1-5, grease the packing and install it in the pump first. As one man pushes the liner into position through the front cylinder head opening -- the other man, standing in the cradle, should grasp the opposite end and guide it into position. Care should be exercised not to damage the packing while installing the liner. On pumps that retain the liner through a liner cage, Figure J1-4, after the liner is in place, thoroughly grease the liner packing area and each piece of packing, -- and install them over the liner. Push the packing assembly all the way forward to the shoulder on the liner.

B. Piston and Rod Installation 1. "L" Head Pumps (Figure JI-2 and Figure J1-3) Thoroughly grease the bore of the liner and the piston. Center the piston in the bevel of the liner. The piston rubber must be centered in the centering bevel of the liner to prevent the piston lip from being turned back in the liner bore, Figures J4-9 and Figure J4-10.

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Use a piece of timber as a spacer between the piston rod and the crosshead rod. While holding the piston rod in this position, turn the pump through by hand pushing the piston into the liner. When the piston is installed in the liner, rotate the pump so the crosshead rod is in the rear stroke position to allow clearance for installation of the extension rod. On pumps that use a one-piece rod, the piston and rod assembly must be installed in the liner and the whole assembly of piston, rod and liner is installed as a unit. Carefully inspect the mating faces of the component parts of the rod to be sure they are absolutely clean and free of nicks and burrs. Install the extension rod and clamps as recommended by the manufacturer.

2. Pumps with over and under valves (Figure J1-4, Figure J1-5 and Figure J1-6) Before installing the piston and rod assembly, be sure to carefully inspect the connecting face of the rod to be sure it is clean and free of nicks and burrs. Grease the liner bore and the piston thoroughly. Center the piston in the liner and push it into the liner until the face of the piston rod contacts the crosshead rod. A rod removal and installation tool will facilitate installation. If a rod installation tool is not available, it may be necessary to drive the piston into the liner using a timber. One man should support and pull the piston rod into the liner as it is being driven in. Connect the piston rod to the crosshead rod as specified by the manufacturer. Replace the liner flushing and coolant assembly and the liner splash shield. Since the cylinder heads must retain the full fluid load, it is essential that careful maintenance of these and related parts be maintained. Before installation, all parts i.e. cylinder heads, liner cage, Figure J1-4, and suction valve guide, Figure J1-5, should be cleaned and thoroughly inspected for burrs, wash outs and cracks. Thoroughly clean and grease the threads and packing area. Remember -- always use new packing. Install cylinder head and tighten to manufacturer's recommended torque.

VII. Single Acting Piston Assembly Failure of a single acting piston can quickly be seen since the single acting feature leaves the back side of the piston open. On some triplex pumps the piston is accessible through the cylinder head, Figure J1-4, Figure J1-5 and Figure J1-6. On others, cylinder heads are not provided, therefore, the piston and rod assemblies are removed from the power end of the liners, Figure J1-2 and Figure J1-3. Since the fluid pressure operates on one side only, the piston rod connection is straight rather than tapered, Figure J4-26, thus the piston can be easily removed.

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Figure J4-26 Rod Piston Connections for Triplex Pumps are Straight

A pressure actuated "O" ring seal fits in a counterbore in the piston body and seals against the radius and shoulder on the rod, Figure J4-27. Figure J4-27 Single Acting Piston

For proper piston installation the following procedure should be observed: 1. Thoroughly clean the threads, piston rod end and the face of the rod that contacts the piston flange. 2. Lightly lubricate the piston end of the rod. This will help reduce corrosion and make piston removal easier.

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3. Lightly grease the "O" ring and make sure it is properly seated in the piston "O" ring groove, Figure J4-27. 4. Make sure the piston fits squarely against the rod flange. 5. Lubricate the rod threads, the face of the piston and the elastic stop nut. 6. Piston with a 1-1/2" or 1-5/8" hole should be tightened with no more force than one man on a 3' wrench and cheater combination. 7. Piston with 1" hole should be tightened with no more force than one man on an 18" wrench. In an effort to reduce pump downtime, some operators keep an extra piston and rod assembly ready for immediate installation. Care should be taken never to store a piston and rod assembly with the piston lying on the floor. This could cause a flat spot on the piston rubber, resulting in premature failure.

VIII. Piston Rubber Removal and Replacement If the piston body is to be reused, the snap ring is easily removed by hammering a sixty penny nail under the beveled end of the snap ring, driving the nail in a clockwise direction, Figure J4-28 and Figure J4-29.

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Figure J4-28 Loosening Snap Ring with Nail (Drive in nail to loosen snap ring)

Figure J4-29 Piston Rubber Replacement

Figure J4-29. If an inspection of the flange and wear groove on the piston shows that replacement of the piston body is not necessary, the piston rubbers only may be replaced. The first step in piston rubber replacement is the removal of the snap ring, which is accomplished with a large nail and hammer as shown. The snap ring will always peel off clockwise, and should be installed counter clockwise. If piston is removed from the rod, insert a hammer handle in the piston bore to retain the ring when it springs from the groove.

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With the snap ring removed, the plate is then removed and the piston rubber is pried from the piston body, Figure J4-30. Figure J4-30 Removing Piston Rubber and End Plate

FIGURE J4-30: After the snap ring is removed, then the end plate and the piston rubber may be readily removed. Before installing new piston rubber on a used piston body, check the body to be sure that the body has not been damaged, washed out, or worn beyond acceptable limits. Be sure that the hub and flange are thoroughly cleaned of any accumulation of mud, rust, or pieces of fabric, Figure J4-31.

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Figure J4-31 Cleaning the Piston Body

Figure J4-31. After the piston rubbers have been removed, thoroughly clean the piston body. Solvent and wire brushing may be required to remove caked mud. The new piston rubber must be pushed down firmly and evenly against the piston flange to make installation of the plate and snap ring easier. the use of a piston assembly tool will greatly assist in the assembly of new piston rubbers. Always use the new piston plate and snap ring supplied with the piston rubber. With the piston plate in place, start the end of the snap ring, with the square end first, into the groove on the piston body so that the snap ring will go into the grove in a counter-clockwise direction, Figure J4-32 and Figure J4-33.

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Figure .J4-32 Snap Ring Installation

Figure .J4-33 Tapping Snap Ring into Place

Figure J4-33. After piston rubbers and end plates have been replaced, the snap ring should be hammered in place. A piston assembly tool is recommended for tapping this snap ring in place, although a cold chisel and hammer may be used if a piston assembling tool is not available. Start Square End of snap ring first as snap ring will be easier to start and remove. The last part of the snap ring to go into the groove is sprung slightly upward, and is beveled on the inside to make removal easier. If the snap ring is put on upside down, removal is very difficult. After the snap ring is in place, it is good practice to bump the snap ring hard all the way around to be sure that the snap ring is fully seated in the groove and not resting on the edge of the groove.

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IX. Valve and Seat A. Removal 1. Mechanical Valve Seat Puller When chaining valves and seats, it is recommended to use either a mechanical wedge or hydraulic valve seat puller, Figure J4-34 and Figure J4-35, because of the dangers associated with cutting the seats from the pump with a torch. Figure J4-34 Wedge Type Valve Seat Puller

Figure J4-34. This cutaway shows the wedge type valve seat puller with a J-tool head. J-tool heads are available with 2, 3, or 4 hooks.

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Figure J4-35 Hydraulic Jack Seat Puller

Figure J4-35. Hydraulic jack type seat pullers are available instead of the wedge type. Puller heads are identical to those used with the wedge-type valve seat pullers, but a center hole hydraulic jack is used instead of the wedge assembly. To prevent injury when the seat releases and pulls out of the deck, secure a safety chain around the pulling assembly. Make sure you use the proper puller head for the seat being pulled. Engage the hooks under the crossarms and tighten the nut against the top block. Be sure the hooks are engaged completely around the crossarms. If you are using a wedge type puller, lay the bottom wedge block over the stem ... place the wedge in position ... and lay in the top wedge block. Now place the nut on the stem and secure the nut as tight as you possibly can, Figure J4-36.

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Figure J4-36 Valve Seat Puller

Figure J4-36. Of the two different types of valve seat pullers in common use, the most widely used is the wedgetype shown above. After the appropriate valve seat puller head has been attached to the seat and the valve puller main stem screwed into it, the nut is tightened as shown with the wedge in the retracted position. Strike the wedge with a sledge until the seat is dislodged from the taper, Figure J4-37, Figure J-38 and Figure J-39.

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Figure J4-37 Protection of Studs while using Wedge-type Pullers

Figure J4-37. When wedge-type pullers are used on pumps with stud-type valve pet covers, a rag inserted in the crotch of the wedge will protect the studs.

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Figure J4-38 Pulling the Valve Seat

Figure J4-38. The valve seat is then pulled by striking the wedge with a sledge hammer.

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Figure J4-39 Valve Seat Puller Assembly

Figure J4-39. This photograph shows the entire valve seat puller assembly immediately after it has been removed from the valve pot. Hydraulic jack pullers employ the same type puller head as the wedge type only the stem is longer for the jack. Place the jack over the stem on the two piece block and install the nut. Insert the "C" washer between the top of the jack and the nut. Release the fluid return valve to compress puller ... and bring the nut up as tight as possible. To prevent injury when the seat releases and pulls out of the deck, secure a safety chain around the pulling assembly, Figure J4-35. On duplex and single acting "L" head pumps all the valves are accessible from the top and may be changed easily. However, on single acting cylinder head pumps the intake valve is directly below the discharge valve and requires a special pulling tool, Figure J4-40.

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Figure J4-40 Pulling Tool for Valves on Cylinder Head Pumps

Figure J4-40. Special pulling tool for valves on cylinder head pumps. 2. Torch Cutting When changing valves and seats, it is desirable to use either a mechanical wedge or hydraulic type puller because of the danger associated with cutting seats from the pump with the torch. However, if pullers are not available, and torch cutting is the only means of removal, then the seat should be carefully cut from the pump by an experienced person. This cutting operation should be done as rapidly as possible so as not to overheat the deck which could cause permanent distortion to the deck taper. Heating of deck may destroy any heat treatment of the deck taper. On seats with crossarms, cut all but one crossarm all the way through. After crossarms are cut, the seat becomes a ring and either two or three evenly spaced cuts should be made a part way through the body of the seat running from the top to the bottom. These cuts should not be more than 2/3 of the way through the seat. As soon as these cuts have been made, cold water should be thrown on the seat which will contract and allow it to be easily removed. If the jaw of a 24" pipe wrench is turned around backwards, the hook can be used for pulling and jerking on the seat without burning the hand. Note: Never install a new seat in a pump deck that is still hot.

B. Installation Wash the pump immediately after pulling the seat to remove any accumulation of drilling mud before it drys and hardens, Figure J4-41.

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Figure J4-41 Washing Out the Valve Pot after Removing Valve Seat

Figure J4-41. The entire valve pot should be washed immediately after removal of the valve seat. The deck should be carefully inspected for damage of any sign of fluid cutting. Any damage to pump deck should be repaired before installing new valve seats. Clean the pump deck thoroughly, removing any accumulation of rust or dried mud at the bottom of the machined tapered surface. If there is a shoulder at the bottom of the deck it must be thoroughly cleansed. A build-up of rust or mud in these areas will prevent the seat from seating properly in the taper, Figure J4-42 and Figure J4-43.

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Figure J4-42 Seat Must Seat Properly in Taper

Figure J4-43 Washout of Seat and Pump Deck

Figure J4-43. This seat and pump deck were severely washed out due to an improper seat installation, or installing a set in a pump deck that was only slightly nicked across the deck taper. Inspect the taper for cracks or wash outs. If any rough spots are found on the surface of the taper, smooth the surface with emery. Remember, rub in a circular motion -- never up and down. Finally, clean the deck thoroughly with a solvent and wipe dry with a clean cloth to build up a dam where the ports open onto the pot area. It is extremely important that the mud and water be kept off the clean taper.

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The new valve seat is coated with a rust inhibitor, which must be thoroughly removed before installation in the pump. Remove the inhibitor with diesel oil or some other suitable solvent, and wipe dry with a clean cloth. The seat should be installed immediately after cleaning. If heat was used to remove the old seat, be sure the pump deck is cool to touch before attempting to install the new seat. Place the seat in the taper and press down firmly with your hand. This pressure should be sufficient to cause the seat to stick to the taper. There should be good contact all the way along the taper of the seat and the deck. If the seat will not stick in the taper and make good contact all the way around, remove the seat and inspect the mating surfaces again to be sure you have sufficiently removed the accumulation of rust and mud from the pump deck and that there are no nicks, burrs or pieces of weld spatter on the taper. Also check the part number to be sure it is the correct part for the pump. When the seat is firmly in place, most manufacturers recommend you place an old valve on the seat and strike several blows on the upper stem with an old pump rod or similar object to drive the seat into the deck. You can usually tell from the sound when it is properly seated. This step is very important. Do not rely on pump pressure to make this initial seal within the pump, since this may allow drilling fluids to seep between the seat and the deck taper causing leaks and wash outs. Before installing the valve in the pump, check the fit of the valve stem in the valve cover guide. If the valve cover guide is found to be egg-shaped, or if the clearance around the valve stem is greater than 1/16", the pot cover guide should be replaced. Now install the valve in the pump. NOTE: Never install old valves in new seat or new valves in worn seat, Figure J4-44. Figure J4-44 Never Install Worn Valves in New Seat (and vice versa)

Remember when installing new valves in the pump, always use new springs to insure long trouble-free service from valves and seats; otherwise, check springs for signs of corrosion, loss of tension, physical abuse or wear. Before installing the pot covers, thoroughly clean the sealing surface. Lubricate both the sealing surface and the gasket with a general purpose grease. Remember: always use new gaskets. Prime the pump through all pots and install the pot covers. Make up to the proper torque recommended by the pump manufacturer.

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J-5 Pump Problems, Failures and Analysis I. Priming and Starting Instructions Once the pump rod, cylinder heads and valve seats are installed, the pump is ready to be primed through all valve pots. Before installing the pot covers, be sure that the sealing surface and gaskets are cleaned and lubricated with general purpose grease. Make up the studs to the torque that is recommended by the manufacturer. If prechargers are available, they should be used so that the pump will be sure of getting complete prime and that entrained air in the mud pump will be easily worked out. The mud pump should be brought up to operating pressure gradually. On a duplex pump a crewman should cheek to make sure that the rod packing is getting sufficient lubrication. Rod packing leakage can be checked by momentarily pulling the rod lubricator line out of the gland nut and observing if any mud is coming through the packing while the piston is moving toward the power end of the pump. Reinstall the lubrication line. On triplex pumps check the liner coolant system to assure adequate volume of coolant in the liner. Pot covers and tattle tale holes should be checked to be sure that there is no oozing of mud or excessive breathing. During the break-in period, the liner packing is also seating and expanding into all the voids and crevices. At the end of approximately a two hour period, the pump should be shut down and the liner packing retightened. Any movement of the liner will allow abrasive mud to get into the packing housing causing undue wear to the pump surfaces. Never tighten liner packing while the pump is under pressure.

II. Pistons and Liners A. Excessive Wear of Liner and/or Piston Body In low pressure (less than 850 psi) service, when a total clearance of 3/32 or more occurs between piston flange and liner wall, the piston and/or liner should be replaced depending on wear of each. At medium (850 psi to 1600 psi) to high pressure, 1/16 clearance should be the limit. At extreme pressures (1600 psi to 3200 psi) and other severe operating conditions 0.040 clearance and the piston and/or liner can be considered "worn out". The continued use of worn liners or pistons will result in short service life of piston rubbers. Do not use worn pistons in new liners or new pistons in worn-out liners.

B. Streaking of Liner Bore and Piston Rubbers This condition is generally caused by excessive sand or other abrasive or foreign materials in the drilling fluid. Keep drill fluids as clean as possible and inspect the liners frequently when the pump is shut down.

C. Pitted Liner This indicates corrosive conditions, pH of mull should be checked and increased if too low (below 7.2 pH). Corrosion inhibitors may be considered. If corrosion is severe, the use of corrosion-resistant liners may be indicated.

D. Concentration of Wear on One Side of Piston or Liner Normally a piston body will wear more on the lower side than the upper. If eccentric wear is excessive, or if it occurs at points other than the lower side, misalignment may be indicated. Check for worn crosshead slides, worn pump bores, worn stuffing boxes and junk rings, and unequal tightening of liner rod packing.

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E. Swollen and Torn Piston Rubbers The use of regular (natural rubber) piston rubbers in oil emulsion or oil contaminated mud will result in swelling and deterioration of the rubber. The use of oil resisting piston rubbers in oil emulsion muds with low aniline point oils can also result in similar swelling and deterioration. In the latter case, failure of other parts such as pipe protectors, blowout preventer rubbers, etc. will probably occur also, Figure J5-1. Figure J5-1 Buna N Rubber in Low Aniline Diesel Oil

Figure J5-1. This "Buna-N" rubber has been run in an oil emulsion mud with a low aniline point diesel oil. Note the evidence of swelling of the face and chunks of rubber broken out of the body of the piston rubber caused by the deteriorating effect of the low aniline point diesel oil. The aniline point of the diesel oil being added to the mud must be above 150°F to prevent deterioration of all rubber goods which come in contact with the mud.

F. "Burned" Piston Rubbers A starved suction or starting the pump without priming results in "burning" the piston rubbers in dry lines. Rapid failure will result after burning has occurred and it is sometimes difficult to trace or identify the failure. A "squealing" in the cylinders when starting the pump or trying to pick up a prime indicates probable damage, Figure J5-2.

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Figure J5-2 Piston Damaged by Lack of Prime in Pump

Figure J5-2. This piston had been run a few strokes in a pump that was not completely primed. Note the broken and torn rubbers and the wiping lips that have been completely rubbed away on the dry surface. This illustrates the importance of properly priming the pump and lubricating the piston and liner at time of installation. Notice the burned area has unburned areas on either side. This indicates the liner was partially filled -- piston burned at the top or uphill side. Piston rubbers on single acting pumps can be burned or rapidly deteriorated due to improper functioning of the pump's liner coolant spray system. The spray mechanism at the rear of the liner should be checked every tour to be sure that a full, continuous stream of coolant is being sprayed into the liner. On recirculating type liner coolant systems, the rod chambers and coolant pump should be thoroughly cleaned after each piston failure, and the sump filled with fresh coolant.

G. Torn or Broken Lips on One Rubber of One End of Piston Turning the lip under or otherwise damaging it during installation is generally confined to one end of the piston or rubber. This can also be caused by stroking out of either end of the liner. Check for both.

H. Packing Area of Liner Fluid Cut or Bottleneck Fluid cutting of the liner in the packing area is generally due to failure to tighten packing sufficiently, keep it tight, or replace it when worn. Over tightening will "bottleneck" the liner and possibly cause damage to other pump parts, Figure J5-3.

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Figure J5-3 Liner Damaged by Excessive Tighening of Liner Packing

Figure J5-3. This liner was ruined by excessive tightening of the liner packing. The most common cause for this damage is failing to loosen the liner packing adjusting screws before tightening the cylinder head nuts.

III. Fluid End Piston Rod and Packing A. Rod Broken Through Taper (Duplex Pumps) This type break can be caused by pump misalignment. Check for unequal wear on piston rod, piston body or liner for evidence of misalignment. Break can be caused by a notch or a stress concentration point or improper torque on the HP taper make-up so that the joint is not prestressed.

B. Rod Broken in Cross-Head or Pony Threads Cross-head thread breakage is frequently due to out-of-square jam nuts, but pump misalignment can also cause such breakage. The use of an out-of-square jam nut can produce a stress concentration of up to ten times that of one having the proper fit, Figure J4-12.

C. Rod Breakage in Body of Rod Failure of this type can be due to cracks started by hammer blows or other external rod damage. Don't hammer on the body of the rod to remove the piston, Figure J4-18.

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D. Rod Pulled Apart in Taper End Threads (Duplex Pumps) These breaks are found exclusively in the smaller tapers and are generally the result of overtightening the piston and nut when making the piston up on a rod, Figure J4-24.

E. Single Acting Piston Rod Problems Overtorquing of piston rod nut can cause rod breakage, thread galling and other installation and removal problems. Reference Figure J4-24 Torque for API Rod Connections for torque values. Inspect rod at clamp or thread end for cracks in flange and/or threads, as well as wear. Also inspect clamps for wear. With a clamp in good condition and tightened properly there must be no movement between clamp and rod.

F. Rapid Wear or Streaking (Duplex Pumps) Overtightened or wornout gland packing, inadequate lubrication, or high sand content are chief causes. High pump pressures aggravate any streaking tendencies that may be present. If wear or streaking is concentrated on one side of rod, check pump alignment or check for uneven tightening of the packing gland. Recirculation of sand in the coolant system can also cause streaking. Too viscous a fluid so that fluid does not flow around entire rod also can contribute to streaking.

G. Pitted or Streaked Rod Due to Pitting (Duplex Pumps) Corrosive drilling fluids or corrosive water lubrication are responsible. Use chrome-plated or hard coated piston red.

H. Chrome Worn Off Rod (Duplex Pumps) Chrome plated piston rods have a hardened surface beneath the chrome plate and should not be replaced just because the chrome has worn off if chrome has worn in smooth. Replace when worn 1/16" to 3/32" total wear, depending upon operating conditions. At pressures above 2000 psi, 0.045 wear is generally all the wear that can be accommodated without excessive packing replacement.

I. Washed Out Taper or Piston Pushed Up on Rod Taper (Duplex Pumps) Improper installation is responsible for the majority of these failures. Both piston and rod tapers should be clean and dry and proper torque used when piston is made up on rod, Figure J4-23.

J. Short Packing Life (Duplex Pumps) Over tightening of packing, insufficient lubrication, high sand content, or use of worn-out rods with new packing are generally responsible. Worn junk rings, misalignment, or unequal tightening of the gland are other possible causes, as well as wash outs on worn stuffing boxes.

IV. Valves and Seats A. Fluid Cut Sealing Members or Parts These failures are generally due to foreign material or lost circulation materials in the mud, or continued use of new sealing members on worn metal parts. Check all parts for wear, including upper valve guides, and replace if worn out.

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B. Fluid Cut Taper of Seat and Pump Deck Most cutting between the seat and deck is due to failure to realize the importance of proper installation and replacement of valve seats, Figure J4-43. Careless use of cutting torch in removing valve seats can result in damaging the deck so that the new seat will not seal properly. If a deck needs reworking, it should be done before a new scat is installed and qualified personnel should do it.

C. Abnormal Wear or Breakage The use of new parts combined with worn-out mating parts frequently results in very rapid failure of either or both the new and worn part, Figure J4-44. Improper application sometimes results in similar failures of new parts. Proper selection of parts for the operating conditions will eliminate these troubles. Rapid wear results from high sand content in the drilling mud and if the sand content cannot be controlled or reduced, more frequent replacements will be necessary. Proper lift, with adequate guiding and correct springs are necessary for optimum valve life and performance.

V. Reducing Pump Volume Pump manufacturers agree that reducing pump volume should be done be reducing pump speed and/or reducing liner size. If neither of these can be done, and under short emergency conditions, the following methods have been used.

A. Duplex Pumps The discharge volume in any constant speed duplex pump may be reduced by removing valves as illustrated in Figure J5-4. Figure J5-4 Volume Reduction by Removing Valves

FIGURE J5-4: Reduce volume by removing valves as shown.

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B. Triplex Pumps There are at least two methods that have been used: 1. Remove the center suction valve only, or 2. Blank off center cylinder by welding a plate in the liner bore. Before any method is used, manufacturer should be consulted for his recommended procedure. REDUCING DUPLEX PUMP VOLUME BY REMOVING VALVES At any constant pump speed the volume discharge may be reduced by removing valves in the following manner: For 25 % volume reduction, remove discharge valve No. 8. For 50% volume reduction, remove discharge valves No. 2 and No. 8. For 75 % volume reduction, remove discharge valve No. 2 and suction valves No. 5 and No. 7.

VI. Centrifugal Pump Care and Maintenance A carefully planned and carried out maintenance program extends pump life, maintains high pump dependability and rated performance, and reduces overall operating costs. The three primary areas of pump care are general effects of erosion and specific problems of packing and bearings. Erosion is wear caused from the impingement effect of the fluid. The wear from erosion is increased when abrasive solids are suspended in the fluid. Discontinuities in the flow passage, such as exposed gaskets, abrupt change of pipe size, and sharp corners, are particularly susceptible to erosion. They cause a change in the direction of flow that creates eddy currents and instantaneous velocity increases. A centrifugal pump which has been carefully selected for its application will show less wear and that wear will be uniform thus affecting performance less. A pump that is the wrong size or the wrong design for its service can very likely fail prematurely. As a pump wears, impeller clearances are increased, and the pump's performance is reduced. Pumps that depend on close clearances for effective performance show the most rapid reduction in performance. For this reason only a pump designed for slurries should be used in that service. These pumps do not depend on such close impeller clearance, internal discontinuities are eliminated, fluid passages are large to minimize high velocities, and impeller diameters and shafts are larger so the pump can be run at reduced speeds. Packing problems most usually are caused by difficulty in maintaining proper lubrication between the shaft and packing. The shaft and packing must be lubricated to prevent shaft scoring and wear as well as packing wear. The most common method for lubricating packing is to allow leakage. The most common cause of packing difficulties comes from preventing this kind of lubrication by overtightening. Tight packing causes excessive heat that wears the shaft and packing. As a result, the shaft is scored and packing must be replaced frequently. And it is virtually impossible to maintain reasonable packing life or to seal against a rough shaft. Usually the line fluid is used as a lubricant. However, if it contains abrasives, it is not suitable and another lubricant must be introduced into the stuffing box at the lantern ring. Around a drilling rig the best such external lubricant is water free from abrasives. But it's pressure must be sufficient to force it into the stuffing box and to keep the abrasive line product from entering the stuffing box. Packing life is also reduced at higher shaft speeds. So one more important point in pump selection is to pick the pump that will do the job required at the lowest speed.

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When repacking the stuffing box, first make sure the box is clean and all old packing is removed. Place packing in the bottom of the box that, when compressed, the lantern ring will be in the proper location beneath the sealing tap. (Figure J5-5) Figure J5-5 Installing King Type Packing

The ring joints should be staggered. Draw up snug only by means of the gland. Pack the remainder of the box, draw up snug and back off the gland until the nuts are finger-tight. Packing expands with heat, and a box which is more than finger-tight when cold, will generally smoke when started up. Tighten nuts half a turn at a time and wait to see if leakage has been controlled to desired rate. Do no run drop tight. Some drippage is required to cool packing. Water to the packing lantern ring is recommended when the stuffing box pressure is below atmospheric pressure. Where water cannot be used, grease as often as required to maintain an air seal. Water flushing also prolongs packing life in abrasive service. NOTE: Do not add extra packing rings when excessive leakage occurs. The third important factor in pump performance is proper care of the bearings. Several factors can affect their life and performance. Mechanical unbalance produces excessive loads, as does misalignment of the pump because of improper or poor piping foundation. Excessive cavitation also causes unusual vibration loads on the beatings, resulting in premature failure. Solids that ball up and plug the impeller cause a mechanical unbalance and corresponding vibration loads that are damaging. Overtightening the beatings cause the lubricant to break down while excessive lubrication causes beatings to overheat. But the most important bearing problems come from contamination. Dirt and grit in the bearing race cause rapid failure. Moisture within a beating enclosure (usually entering from contaminated lubricant) causes rust and corrosion with subsequent bearing failure. Cleanliness cannot be overemphasized. You should not need to regrease the pump unless the original grease becomes contaminated. Disassemble the pump and remove old grease. Hand pack the bearing and fill the bearing cap approximately 1/3 full with clean grease. An increase in bearing temperatures (above 200°F) or noise indicates possible bearing failure. Complete bearing failure usually damages other pump parts. Try to prevent complete bearing failure by changing when the above conditions are detected.

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VII. Checklists A. Checklist for Start Up 1. Coupling Aligned. 2. Pump Full of Fluid. 3. Suction Valve Open. 4. Water on Stuffing Box. (In case of double seal). 5. Oil Full. (If Oil Lubricated). 6. Pump Rotates Freely by Hand.

B. Checklist for Trouble-Free Suction 1. Keep suction flooded. This will eliminate priming problems. 2. Make suction pipe as short and straight as possible. 3. Make suction pipe one size larger than pump suction flange and one pipe; size larger than the discharge pipe. 4. If a reducer is used, use an eccentric reducer with all eccentricity at the bottom. 5. Suction line must be leak-free to keep air out of the fine.

C. Checklist for Increased Packing Life 1. Use proper pump for application. 2. Keep packing box and shaft clean. 3. Do not overtighten packing. Allow leakage if line product is not abrasive. 4. If abrasives are present, lubricate externally with clean liquid under pressure.

D. Checklist for Maximum Bearing Life 1. Choose proper pump for application. 2. Do not let bearings overheat. 3. Keep bearings and enclosure free of dirt and contamination. 4. Check Bearing alignment. 5. Check drivers, piping, and foundations to prevent excessive loads cause by misalignment. 6. Do no press or hammer on bearings when installing. 7. Lubricate properly neither too much nor too little, with clean lubricant. 8. Clean impeller and casing after using if it will be more than a week before pump is to be used again. 9. Do not apply excessive external loads to pump, such as pipe strain, which cause a load on the bearings.

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E. Table J5-P6 Centrifugal Pump Trouble Shooting Guide

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J6. Power End Maintenance The power end of a slush pump is essentially a "speed reducer slider crank mechanism" used to translate the rotating motion of the power source to the reciprocating piston action required for the pumping fluids. Gears, bearings, crossheads and crosshead liners are all utilized in most conventional mud pump power end designs. Reliable long life service from these items is primarily dependent upon proper lubrication. Therefore, routine power end maintenance must focus upon the pump's lubrication system and the care and periodic inspection of components associated with it.

A. Lubrication Proper functioning of the power end lubrication system requires that: the correct type and quantity of lubricant be maintained in the power end sump, contaminants and excess heat be continuously removed from the lubricant, the lubricant be properly distributed to all moving components, and the power end lubricant be completely segregated from the drilling mud and water in the fluid end rod chamber. To accomplish these requirements, slush pumps are equipped with: various filter and/or magnet assemblies to capture contaminations, dipsticks or sight glasses to check oil levels, a pressurized flow or splash-gravity flow lubrication system for distributing the lubricant to various components, and various sealing wiper arrangements on the crosshead extension rod to prevent drilling mud from entering the power end. Each of these items will be subsequently reviewed in more detail, but first let us pause to examine the importance of the proper lubricant in the power end. All slush pumps are equipped with bearings, crossheads, and gears (chains and sprockets in some instances) which must be continually supplied with the correct type and quantity of lubricant. Usually a high grade, extreme pressure (EP) gear oil is recommended by most manufacturers. These gear oils must be capable of maintaining a lubricant file on all bearing surfaces and gear teeth under varying operating speeds and loading conditions. Failure to do so can lead to rapid wear and ultimate destruction of bearings, gears and crossheads. Pump manufacturers have thoroughly analyzed the operational speeds, loads, and temperatures of their pumps and have specified lubricant viscosity grades and additive recommendations which should adequately protect against component wear and corrosion. Lubricant recommendations are usually based upon temperature of the lubricant itself within the pump. Rather than recommend particular brands of lubricant for the pump, many pump manufacturers prefer to simply state the viscosity grade requirements for various temperature ranges. (Refer to pump manufacturer's specific lubricant recommendations). The drilling contractor is then at liberty to contact his local or preferred bulk lubricant distributor, and arrange for them to furnish a lubricant which complies with the pump manufacturer's recommendations. In the past several years confusion has been observed between pump manufacturer's, drilling contractors, and lubricant suppliers as to whether or not lubricants with the correct viscosity characteristics are being furnished and utilized in the pumps. If the pump manufacturer's classification system is not the same as the lubricant supplier's nomenclature and if efforts are not taken to cross reference the information, errors can and do occur. These errors have resulted in the gears, bearings, and crossheads being overheated, pitted, scored, and effectively deteriorated to an unacceptable condition. To eliminate confusion between various classification systems, Figure J6-1 compares AGMA lubricant numbers, SAE gear oil numbers, and ISO viscosity grades.

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Figure J6-1 Viscosity Classification Systems

Kinematic viscosity in centistokes (cSt) at 40°C, and viscosity in Saybolt Universal Seconds (SUS) at 100°F are also presented for the different classification systems.

B. Lubricant Contamination Contamination of the gear oil in the power end is an inevitable by-product of slush pump operation. Metallic particles may be worn off the working surfaces of the gears, bearings, and crossheads. Dust and other debris may enter the power end through the air breather or through worn crosshead extension rod wipers. Water may also enter the power end through damaged or worn crosshead extension rod wipers, or it may condense as a result of temperature changes within the power end. Oil may be oxidized due to high operating temperatures and chemical reactions of the oil with oxygen in the air. Dust, dirt and metallic particles in the gear oil can attach moving components with an abrasive, lapping action which can quickly lead to excessive clearance in bearings and scoring of the gears and crossheads. Water in the power end quickly mixes with the gear oil as the pump operates, and imparts a cloudy or milky appearance to the oil. This condition will frequently cause rusting and corrosion of bearing surfaces, and accelerated wear on load carrying members due to thinning and breakdown of the lubricant's film thickness. Oxidation causes darkening of the gear oil color and leads to sludge formation in the sump and oil troughs. To protect against the detrimental effects of gear oil contamination, most pump manufacturer's recommend the gear oil be changed every six months, or as frequently as required to maintain a relatively clean, sludge free oil. Maintaining a clean, quality lubricant in the power end of the mud pump is the best insurance available for reliable, long life service from slush pump power ends.

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C. Lubrication Systems Several systems are used in slush pump power ends for collecting and distributing gear oil to the various components requiring lubrication. The pressure flow system, the splash-gravity flow system, and a combination of the pressurized flow and splash-gravity flow systems are used by different pump manufacturers to fulfill the lubrication requirements of their particular pump design. The pressurized flow system is the most commonly used lubrication system. This system relies upon a small gear pump to circulate lubricant from the sump and to force it under pressure to various lubrication points. Pressurized flow systems are frequently equipped with heat exchangers, pressure and temperature gages, filters, and a low pressure alarm. the pressure and temperature gages should be checked once every tour for correct lubrication system operation. The splash-gravity flow system, used either singularly or in conjunction the pressurized flow system, relies upon the rotation of the main gear of the pump to pick up lubricant from the sump. Wiper arms or troughs are mounted adjacent to the gear to catch oil from the gear and distribute it to the bearings and crossheads. Proper operation of this arrangement requires that the pump speed be maintained above a certain minimum and that the wiper arms are adjusted properly with respect to the main gear. At every routine oil change, the adjustment of troughs and wiper arms should be checked and the fasteners which retain these members in position should be checked for the correct tightness.

D. Lubrication System Magnets and Filters To assist in the removal of contaminants from the power end gear oil, pump manufacturers have incorporated filters and/or magnet assemblies at strategic points in the power end lubrication system. Pump designs which require a pressurized flow of lubricant to the bearings and crossheads, generally have a filter or strainer screen installed in the lube pump's plumbing to remove debris from the lubricant. Filters equipped with gages or "condition indicators" should be routinely checked to be sure that the filter is not clogged and in a by-passing condition. Magnet assemblies are also installed at various locations in the power end to collect ferrous (iron) particles which are gradually worn from the load carrying surfaces of gears, bearings and crossheads. Pump designs which use an oil splash-gravity flow type lubrication system usually have multiple magnet assemblies in the upper lubrication troughs, crosshead oil reservoirs, and in the sump. Pumps equipped with pressurized flow type lubrication usually only have a sump magnet and possibly a magnetic rod canister installed in a lubrication plumbing linc. Filter cartridges, strainers, and magnets should be cleaned or changed at every routine power end oil change. Anytime insufficient lubrication pressure is monitored on a power end equipped with a pressurized flow lubrication system the filter and strainer should be checked for plugging.

E. Crosshead Extension (Pony) Rod Wipers Crosshead extension rod wipers (Figure J6-2) are the vital barrier between the power end and piston rod chambers, confining gear oil to the power end and the splashing or spraying water and drilling mud to the rod chamber.

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Figure J6-2 Crosshead Extension (Pony) Rod Wipers

At least two and as many as four wipers or seals are used on each crosshead extension rod; and in some designs, grease is pumped between the seals to form an additional barrier against mud entering the power end. Neglect of these wipers is probably the most frequently seen power end maintenance problem on slush pumps. Failure to maintain the rod wipers will inevitably lead to water, sand, and mud entering the power end and contaminating the gear oil, subsequently resulting in rapid wear of the gears, crossheads, and bearings. Gear oil seepage into the rod chambers can also occur, necessitating the addition of expensive gear oil to the power end. Figures J6-3 and J6-4 are examples of severe mud contamination in the power end of a slush pump due to poor crosshead extension rod wiper maintenance.

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Figure J6-3 Drilling Mud Contamination of Triplex Slush Pump Power End

Figure J6-4 Faulty Wipers Cause Mud Contamination

FIGURE J6-4: Faulty wipers shown on the crosshead extension rod caused the power end contamination shown in Figure J6-3. Crosshead extension rod wipers should be inspected daily for sign of fluid leakage and lip wear. If a grease fitting is installed in the wiper housing, the seals should be greased daily with one or two strokes of a hand grease gun. To maximize protection of the power end, an annual change out of these wipers should be performed.

F. Settling Chamber Many triplex slush pumps are equipped with a power end lubricant settling chamber (Figure J6-5) or sludge trap located beneath the crossheads and forward of the gear oil sump.

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Figure J6-5 Settling Chamber

The purpose of this settling chamber is to provide a means for collecting and segregating water and other contaminants from the gear oil. Water can condense in the power ends of the mud pumps or enter the power end, together with drilling mud and sand, through worn crosshead extension rod wipers. If these contaminants were permitted to settle abundantly in the main gear oil sump, they would be continually mixed with the gear oil and recirculated through the pump. Excessive contamination of the gear oil would then lead to rapid wear of moving components. To help minimize power end lubricant contamination, lubricant flow from the crosshead area is directed into the settling chamber. Solid material and water will settle to the bottom of the chamber, while the lighter gear oil rises to the upper part of the chamber and flows back into the gear oil sump. The settling chamber is usually equipped with cleanout plates and drain plugs on each side of the pump. Once a day the drain plugs should be pulled to permit any water accumulation in the chamber to be drained off. During routine oil changes the cover plates should be removed and the chamber cleaned of all mud, sludge, and debris.

G. Gear Oil Reservoir The gear oil sump must be thoroughly cleaned during every regular oil change. Accumulations of drilling mud and sludge must be removed to avoid contaminating the new gear oil. The gear oil reservoir and power end frame walls must also be routinely cleaned to facilitate the proper dissipation of heat from the lubricant to the air surrounding the sump. Small cover-plates are usually provided on the sump to permit access for cleaning.

H. Lubricant Dipstick and Sight-glasses The gear oil dipstick or sight-glass is a very simple instrument attached to the power end reservoir, yet it is probably the most important maintenance tool provided to the slush pump mechanic. The dipstick or sight-glass not only permits checking of the lubricant level in the pump, but frequently assists the mechanic in monitoring contamination buildup in the gear oil. Failure to maintain the proper oil level within the power end can result in: marginal lubrication of moving components, pump overheating, and rapid wear of components. The lubricant level in the power end reservoir should be checked at least once a day with the pump shut down. It is usually best to wait several minutes at, er shutting a pump down before checking the lubricant level. This will allow the lubricant level to stabilize in the reservoir and permit accurate readings.

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I. Pump Storage When slush pumps are to be put into storage certain precautions must be taken to prevent corrosive deterioration of pump components. The cost of the precautionary measures is usually small compared to the loss of drilling time and expenses involved in reconditioning and replacing corrosion damaged bearings, seals, piston rods, and fluid cylinder components. The power end sump and settling chamber should first be drained and thoroughly cleaned. A rust inhibiting oil should be sprayed on all bearings, finished surfaced, and the entire inside surface of the power end. To provide air circulation and prevent condensation build up, the drain plug may be removed and a wire mesh screen (for rodent exclusion) secured over the opening. On pump equipped with pressurized, forced flow lubrication systems, clean gear oil should be induced into the oil circulating pump, filter housing, heat exchanger, etc. If the exterior paint on the pump has begun to deteriorate or is extensively chipped, a quality machinery paint should be applied. For maximum frame protection against rusting, all painting operations should be preceded by the necessary sanding and surface preparations. To provide corrosion protection for the fluid end of the pump, the valves, valve seats, piston rods, and liners should be removed from the fluid cylinders, and all components thoroughly cleaned and dried. Coat the cylinder bores, all valve cover and cylinder head components, and the reusable expendable parts with a rust preventative or grease. The triplex pump's liner spray system must also be protected against corrosion while in storage. All water, sand, and debris should be flushed from the liner spray pump, coolant reservoir and associated hoses, spray nozzles and tubes. Spray all components with a rust inhibiting oil and fill the liner spray pump housing with oil. While in storage the pump should be thoroughly inspected at least once each month and recoated, where necessary, with a rust inhibiting oil. Always rotate the pump gears during each inspection. This procedure will permit redistribution of the rust inhibiting oil over the surfaces of the bearings.

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Chapter J: Pumps

J7. Preventive Maintenance I. Planned Preventative Maintenance The primary goal of a Preventative Maintenance Program is to help the contractor realize and control fluid circulating equipment costs. It is possible to control mud pump costs, if the life of fluid end parts can be reasonably predicted so that they can be pulled before failure. This will save money because when a part is run to failure, the pump goes down -- likely when it is needed most, and the odds are that another part is damaged or is due to fail soon. At this time, money is being lost; money is coming out of the contractor's pocket. Some of this lost money is: Lost Footage -- that all-important portion of the hole before the driller reaches contract depth, each hour of not drilling represents lost revenue new to be recovered. Damage to Other Parts -- A piston run to complete failure will almost invariably take the liner with it. A liner costs four (4) to eight (8) times more than a piston. Man Hours on the Pump -- In addition to the cost of the liner, how often does the crew complain about always going into the pump? How many times has someone been hurt working on the pump? How does a Preventative Maintenance Program operate? If a part is replaced before it fails, the changeout can be made at a time most convenient to the contractor -- not when it is unexpected or costly to be down. Parts that are left in will not be damaged and can be expected to run their full life. Those few cents per hour wasted, Figure J7-1, by the item pulling apart with few hours life left on it, are more than saved. Figure J7-1 If a Part is Replaced Before it Fails

The "Cost per Hour" is out on the flat portion of the curve and the savings are very small compared to the risk involved. How much do you save by running the risk of shutdown attempting to get another 50-100 hours use out of a part. Schedule pump downtime, reduce pump downtime, and rig downtime, by changing parts in groups. If a part is worn out, its companion is very nearly so. By changing parts of the pump in a group, you eliminate the

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continual going into the pump. Since you can program a part and know when it is time to be replaced, you can then plan all your events or activities so that the pump is never down while drilling is in progress. Compare Figure J7-2 to Figure J7-3 where pump is shut down 12 times in 3600 hours compared to 28 times in 3600 hours. Figure J7-2 Maintenance Schedule Chart

Figure J7-3 Maintenance Schedule Chart

II. Establishing a Preventative Maintenance Program FIRST, run sufficient parts in the pump as to establish what can be expected for parts life. For example, what is the average liner life? How long does a piston last? How long does a rod last? What is the 'life of the rod packing and liner packing? How long do valves and seats last? SECOND, once you have determined "the average life of these components", can the products with similar life be operated as a unit? For example, can a piston and a rod called Unit "A" be operated for say 300 hours, or 500 hours, or 600 hours? Can a liner and liner packing called Unit "B" be operated for 600 or 1000 or 1200 hours? What is the life of valves and seats called Unit "C", 1200 hours, 2000 hours, or 2400 hours?

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THIRD, can these units be arranged in some multiple of each other? For example, two Unit "A's" for one Unit "B"? That would require changing two pistons and two rods for each liner, or can two Unit "B's" be changed for one Unit "C"; in other words, every second liner change the valve and seats. If these products have similar life and can be operated as a unit, then we are ready to start programming, Table J7-1

Table J7-1 Parts Life Program

FIRST: Run Sufficient Parts to Establish What Can Be Expected for Parts Life. Liner Life Piston Life Rod Life Rod Packing Life Liner Packing Life Valve and Seat Life SECOND: Can The Products With Similar Life Be Operated As a Unit? Possible Combinations Pistons and Rods

Unit A

300

Liners and Liner Packing Unit B Valves and Seats

Unit C

500

600

600 1000

1200

1200 2000

2400

THIRD: Can These Units Be Arranged in Some Multiple of Each Other? 2 Unit A's for 1 Unit B (Change 2 Pistons and Rods for Each Liner) 2 Unit B's for 1 Unit C (Change 2 Liners for 1 Valve and Seat Change) When to replace parts is "just before failure!" This gives the longest life and the lowest replacement cost. When the pump pressure falls, it is too late! There is a wash out somewhere, between: piston and rod, piston and liner, liner and pump, valve and seat, seat and deck, line pipe and drill pipe, etc., usually somewhere in a joint. Two pieces are damaged or destroyed.

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This is what programming does; pull the part just before failure.

III. Advantages of programming: 1. If you know when an event is to occur, then plan your operation or activity around it. 2. It is the most economical way to operate. a. No lost footage. b. No rig downtime. c. No damage to other parts because of failure. d. Reduce man-hours working on pumps. 3. Able to plan material flow so that sufficient parts are at rigs, warehouse, or supply stores. 4. Material requirements for overseas or isolated locations can be determined beforehand. 5. Fluid end costs known beforehand and can be used in bidding. 6. Crew can be instructed beforehand as to what to change and when to change.

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Chapter K: BOP Equipment, Procedures

Chapter K Well Control Equipment and Procedures

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Table of Contents - Chapter K Well Control Equipment and Procedures Disclaimer and Credits ....................................................................................................................... K-3 K-1 Blowout Preventer Stack Equipment .................................................................................................. K-5 I. Annular Type Blowout Preventer ..................................................................................................... K-5 II. Ram Type Blowout Preventer ......................................................................................................... K-6 III. Typical Bop Stack Arrangement And Testing Procedures For A Surface Stack ............................ K-11 IV. Inside Blowout Preventers ........................................................................................................... K-36 V. Choke Manifold .......................................................................................................................... K-43 VI. Diverter Systems ........................................................................................................................ K-46 K2. Blowout Preventer Control Systems ................................................................................................. K-54 A. Surface Bop Stacks, (Land Rigs, Offshore Jackups, And Platforms) ............................................. K-54 B. Subsea Bop Stacks ...................................................................................................................... K-61 C. Remote Operated Choke Controls ............................................................................................... K-71 D. Diverter Control Systems ............................................................................................................. K-73 E. Control Systems Typical Capacity And Performance Data / Calculations ....................................... K-77 K3. Well Control Procedures .................................................................................................................. K-92 Basic Principles ................................................................................................................................ K-92 II. Pre-kill Procedures ...................................................................................................................... K-93 III. Formation Pressure Integrity Information ..................................................................................... K-96 IV. Kill Techniques ............................................................................................................................ K-99 K-4 Glossary of Well Control Terms ..................................................................................................... K-108

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Chapter K Well Control Equipment, Procedures The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study. The following industry representatives have contributed to the development and updating of this chapter: MEMBERS OF THE TASKFORCE John Altermann Reading & Bates Drilling Company Bill Bingham

MH Koomey, Inc.

Richard Grayson

Reading & Bates Drilling Company

Ralph Linenberger

Global Marine Drilling Company

Fred Mueller

Reading & Bates Drilling Company

Larry Odelius

Cooper Oil Tools

Robert Taylor

Zapata Offshore

Disclaimer and Credits The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study.

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The following industry representatives have contributed to the development and updating of this chapter: Bill Bingham, Chairman MH Koomey, Inc. John Altermann Reading & Bates Drilling Company Paul Helfer

MH Koomey, Inc.

Ralph Linenberger

Global Marine Drilling Company

Fred Mueller

Reading & Bates Drilling Company

Larry Odelius

Cooper Oil Tools

Robert Taylor

Zapata Offshore

Richard Grayson

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Chapter K: BOP Equipment, Procedures

K-1 Blowout Preventer Stack Equipment I. Annular Type Blowout Preventer A. General Background The is installed at the top of the BOP stack (see Figure K1-1A) and has the capability of closing (sealing off) on anything in the bore or completely shutting off (CSO) the open hole by applying closing pressure. Figure K1-1A Annular BOP

The sealing device of an annular blowout preventer is referred to as the "packing element". It is basically a donut shaped element made out of elastomeric material. To reinforce the elastomeric material, different shapes of metallic material are molded into the element. This keeps the elastomeric material from extruding when operating system pressure or well bore pressure is applied to the bottom of the packing element. Since the packing element is exposed to different drilling environments (i.e. drilling fluid/mud and or temperature of the drilling fluid), it is important to make sure that the proper packing element is installed in the annular preventer for the anticipated environment of the drilling operation. During normal wellbore operations, the preventer is kept fully open by leaving the piston in the open (down) position. This position permits passage of drilling tools, casing, and other items which are equal to the full bore size of the BOP. The blowout preventer is maintained in the open position by relaxing all hydraulic control pressures to the closing chamber. Application of hydraulic pressure to the opening chamber ensures positive control of the piston.

B. Close Preventer Operation In order for the annular BOP to close on anything in the bore or to perform a complete shut-off, CSO, closing pressure must be applied. As the piston is moved to the closed position, the elastomer packer is squeezed inward to a sealing engagement with anything in the bore or on the open hole. Compression of the elastomer throughout the sealing area assures a strong, durable seal off against any shape, even with a previously used or damaged packer.

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The piston is moved to the closed position by applying hydraulic pressure to the closing chamber. Guidelines for closing pressures are contained in the operational section for each manufacturers type of annular blowout preventer and in the Operator's Manual. The correct closing pressure will ensure long life, whereas excessive or deficient closing pressures will reduce packer life. The pressure regulator valve of the hydraulic control unit should be adjusted to the manufacturer's recommended closing pressure. Subsea applications may require an adjustment of closing pressure due to effects of the hydrostatic head of the control fluid and of the drilling fluid column in the marine riser. The applicable Operator's Manual will explain these requirements.

C. Stripping With An Annular Bop Drill pipe can be rotated and tool joints stripped through a closed packer, while maintaining a full seal on the drill pipe. Longest packer life is obtained by adjusting the closing chamber pressure just low enough to maintain a seal on the drill pipe with a slight amount of drilling fluid leakage as the tool joint passes through the packer. The leakage indicates the lowest usable closing pressure for minimum packer wear and provides lubrication for the drill pipe motion through the packer. A pressure regulator valve should be set to maintain the proper closing pressure. For stripping purposes, the regulator valve is usually too small and cannot respond fast enough for effective control, so a surge bottle is connected as closely as possible to the BOP closing port (particularly for subsea installations). The surge bottle is precharged with nitrogen, and is installed in the BOP closing line in order to reduce the pressure surge which occurs each time a tool joint enters the closed packer during stripping. A properly installed surge bottle helps reduce packer wear when stripping. Check manufacturers recommendations for proper nitrogen precharge pressure for your particular operating requirements. In subsea operations, it is advisable to add an accumulator to the opening chamber line to prevent undesirable pressure variations.

II. Ram Type Blowout Preventer A. General Background A ram type blowout preventer is basically a large bore valve. (See Figure K1-1B) Figure K1-1B Ram Type BOP

The ram blowout preventer is designed to seal off the well bore when pipe, casing, or tubing is in the well. In a BOP stack, ram preventers are located between the annular BOP and the wellhead (see Figure K1-2B).

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Figure K1-2B Subsea BOP

There are typically 3 or 4 ram preventers in a BOP stack. Flanged or hubbed side outlets are located on one or both sides of the ram BOPs. These outlets are sometimes used to attach the valved choke and kill lines to. The outlets enter the wellbore of the ram preventer immediately under the ram cavity. Other than sealing off the well bore, rams can be used to hang-off the drill string. A pipe ram, closed around the drill pipe with the tool-joint resting on the top of the ram, can hold up to 600,000 lbs. of drill string. Several different types of rams are installed in the ram type BOP body. The four main types of rams are Pipe Rams, Blind Rams, Shearing Blind Rams, and Variable Bore Rams. Following is a brief description of each type: Blind Rams Blind Rams - the rubber sealing element is flat and can seal the wellbore when there is nothing in it, i.e. "open hole". (See Figure K1-3B)

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Figure K1-3B Blind Rams

Pipe Rams Pipe Rams - the sealing element is shaped to fit around a variety of tubulars, which include production tubing, drill pipe, drill collars, and easing that will seal off the wellbore around it. (See Figure K1-4B) Figure K1-4B Pipe Rams

Variable Bore Rams Variable Bore Rams - the sealing element is much more complex and allows for sealing around a particular range of pipe sizes. (See Figure K1-5B)

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Figure K1-5B Variable Bore Rams

Shearing Blind Rams Shearing Blind Rams - the blade portion of the rams shears or cuts the drill pipe, and then a seal is obtained much like the blind ram. (See Figure K1-6B) Figure K1-6B Upper and Lower Shearing Blind Rams

NOTE - Special shear rams can be made capable of shearing multiple tubing strings and large diameter tubulars while maintaining a reliable wellbore pressure seal.

B. Operation And Use Of Pipe Rams As described earlier, pipe rams are designed to fit around certain diameter tubulars to seal off the wellbore (annulus) in a blowout situation. Most pipe rams are designed with replaceable elastomer packers and top seals. Besides sealing off the wellbore in an emergency situation, the pipe rams can be used for stripping. Use of two ram-type preventers would only be resorted to if the annular preventer was badly worn. However, stripping drill pipe through rams can be done with less string weight than if the annular preventer is used, since there is no closure around the larger diameter of the tool joints. One additional ram-type BOP must always remain available below any used for

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stripping, to allow the well to be closed in safely.

C. Stripping With Ram-type Bops Stripping through ram-type BOPs requires at least three preventer ram cavities fitted with the proper size rams for the pipe to be stripped. If the pipe string is a tapered string, i.e., having more than one size pipe in the string, two preventer ram cavities will be required for each size of pipe in the string. A tapered pipe string can be stripped using only two preventer ram cavities provided variable (multiple) bore rams are used. Variable bore rams have a specified pipe size range and will seal off on any size pipe within the size range. The two preventer ram cavities used for stripping should be spaced sufficiently far apart so that closed rams in each preventer cavity will clear the length of a pipe connecting joint. This also includes any upset (increased pipe diameter) portions adjacent to the connection. The distance between the two preventer ram cavities should provide enough additional space so that positioning 'the pipe joint between the cavities does not require an excessive amount of precise positioning. When operations indicate that a considerable amount of stripping may be required, it is advisable to include a third preventer ram cavity fitted with pipe rams for added safety and to permit replacement of the ram packers in the stripping preventers. The pipe rams in the upper two preventer cavities would be considered the "stripping" rams while the pipe rams in the third preventer cavity would be "safety" rams. Stripping pipe through ram packers causes wear on the packers and packer replacement is sometimes required. The safety rams in the third preventer cavity will permit well pressure to be shut in below the stripping preventers when required. The preventer with safety rams is only closed on a stationary pipe string and therefore the rams do not receive much wear, thus always providing a reliable backup closure. Stripping requires no special equipment beyond what is normally available on a drilling rig; however, as the pipe string becomes insufficient to overcome the upward force of the well pressure acting on the pipe, provisions must be made for restraining the pipe string against upward movement. At this point, the stripping operation becomes a "snubbing" operation. Capability for pipe snubbing is also required when starting a pipe down into the wellbore against well pressure.

D. Ram Locking Device A ram locking device is necessary to be fitted to all ram blowout preventers. This device is used whenever it is necessary to remove hydraulic operating pressure from the "close" side of the ram operating system, but maintain the ram preventer in the close position. On BOP stacks that are used in a surface application, the ram locking device is a threaded rod, referred to as a "lock screw". This lock screw reacts between the operating piston in the ram operating system, and the housing of the lock screw. The locking device on a ram preventer that is used in a subsea application must be designed to be remotely actuated by either the BOP hydraulic control unit, or by the actual movement of the operating piston in the ram operating system.

E. Operation And Use Of Shearing Blind Rams Under normal operating conditions, shearing blind rams are used as blind rams. The large front packer in the upper shear ram seals against the front face of the lower shear ram, resulting in prolonged packer life similar to that of standard blind packers. If emergency conditions make it necessary to shear the drill pipe, the closing shearing blind rams will shear the pipe and seal the wellbore whether the fish (the lower section of sheared pipe) is suspended on the lower pipe rams or dropped. If the fish is not dropped, the lower shear ram will bend the sheared pipe over a shoulder and away from the front face of the lower shear ram which then seals against the packer in the upper shear ram. If different grades, weights, or large diameter pipe has to sheared, each oil tool manufacturer has a variety of shear rams available to perform the shearing operation.

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F. Recommended Shearing Procedures 1) Raise the bit off the bottom and position the pipe in the preventer so that the tool joint is positively NOT in the shear ram cavity. 2) To ensure proper alignment for shearing, a set of pipe rams may be closed before the shearing blind rams are closed. Also, if the fish is not to fall downhole after being sheared, a tool joint may be landed on closed and locked pipe rams at least 30" below the shear rams. The tool joint and upset portion of the drill pipe must be below the lower edge of the shear ram cavity to ensure that the pipe is sheared successfully. 3) Close the shearing blind rams with 3000 psi on the BOP operating system. The accumulator system should be sized such that the pressure does not fall below 2700 psi during the shearing operation. The hoses for the open and close functions of the BOP are recommended to be at least one inch in diameter. 4) Lock the shearing blind rams in the closed position by actuating the manual lock or applying locking (closing) pressure to the appropriate locking mechanism as required. 5) If the lower fish is suspended in pipe rams below the shearing blind rams, killing mud may be circulated through a BOP outlet between the shearing blind rams and the pipe rams and into the lower fish in order to circulate a kick out of the hole in the conventional manner.

G. Care And Maintenance Of All Blowout Preventer Stack Equipment Each manufacturer bas individual care and maintenance manuals for each product of the blowout preventer stack. They should be contacted for detailed information regarding their specific recommendation on each piece of equipment. Proper care and maintenance is essential to keep the equipment working.

III. Typical Bop Stack Arrangement And Testing Procedures For A Surface Stack A. BOP Descriptions, for Surface Stack - API Standards The American Petroleum Institute has established standard nomenclature for describing BOP components and ratings. API RP53 Bulletin contains the following information: BOP Component Codes: CODE

COMPONENT

A

Annular

G

Rotating Head

R

Single Ram

Rd

Double Ram

Rt

Triple Ram

S Pressure Code

Drilling Spool M = 1000 psi Rating Working Pressure

Example of API BOP Stack Description: 5M - 13-5/8" SRRA, describes a 5000 psi W.P., 13-5/8-5M" bore stack with components from bottom up, consisting of a drilling spool, single ram, single ram and annular BOP.

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For control of any well, blowout preventer stacks and associated kill/choke lines and valving must be arranged to provide a high degree of backup and flexibility. API RP53 illustrates typical arrangements for BOP (Figure K1-1C) and choke/kill manifolds. Figure K1-1C BOPs for 10M and 15M WP, Surface Installations

Notes on Figure K1-1C: ARRANGEMENT RSRRA * Double Ram Type Preventers, Rd, Optional. ARRANGEMENT SRRRA * Double Ram Type Preventers, Rd, Optional. ARRANGEMENT RSRRA *G* Double Ram Type Preventers, Rd, Optional. *Annular preventer, A, and rotating head, G, can be of a lower pressure rating. However, this API RP deals with the subject only in a general way. The rest of this section will be devoted to analyzing several specific BOP stack arrangements. Before doing this, first consider certain general facts concerning BOP design and arrangements.

B. BOP Design Considerations For Surface Stack The principle BOP design considerations are to:

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1. Confine Well Bore Pressure; and 2. Provide for Passage of Tools. Controlling bottom hole pressure while killing a well is the primary purpose of a BOP. In most cases, the BOP working pressure exceeds the limit of all other well control system elements. A BOP stack should be able to contain the maximum anticipated surface pressure which is essentially the full bottom hole formation pore pressure. Obviously, the BOP bore must be large enough for passage of anticipated tool sizes. On occasion, under reamers must be used to open the hole because of BOP bore restrictions. Pilot holes are sometimes drilled to investigate formation pressure and the BOP is removed to open the hole and run casing. This practice could be disastrous. The BOP bore should be sufficient to provide protection during any drilling process.

C. Bop Arrangement Considerations Specific BOP arrangements are based on the following considerations: 1. Governmental Regulations; 2. Company Policy; 3. Physical size and cost; and 4. Flexibility and safety. 1. Governmental Regulations or Company Policy Rules and regulations governing the operation of a BOP in the USA outer continental shelf areas are contained in the Mineral Management Service (MMS) 30 code of Federal Regulations Part 250. These rules and regulations must be complied with. Likewise in other areas of the world, governments will usually have local regulations governing the use and testing of BOP stacks. 2. Company Policy Both the Operator and the Contractor will usually have their own policies concerning BOP stack configuration and testing. The operator should be made aware of the Contractors "policies" prior to the "occurrence" of any kick. 3. Physical Size and Cost If physical size and cost is no consideration, the ideal situation would be to have only one BOP stack of sufficient bore, working pressure and back-up components to drill the complete well. Such stacks are actually being built for deepwater subsea operations where such designs can be justified. Most non-floating rig BOPs are surface mounted. Two independent stack arrangements are normally used. A large bore relatively low-pressure stack consisting of an annular only, or an annular plus one or two rams, is used for well control until surface casing is set. This large bore stack sometimes is used as part of a diverter system. After setting surface casing, a small bore stack of higher working pressure is normally used to TD. 4. Flexibility and Safety The rest of this section will analyze two BOP stack arrangements used for maintaining control below surface casing on non-floating type rigs. Both arrangements consist of a singular annular and three (3) rams. The advantages and disadvantages of these arrangements in terms of flexibility and safety will be discussed.

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Also, included are recommendations for developing a safe, efficient BOP test procedure and the description of a specific test sequence for one of the subject stack arrangements. There can be no "best" standard stack arrangements since each drilling environment and rig influences, to some degree, BOP equipment configuration. But a closer look at several good hookups highlights principles that will be helpful to anyone responsible for arranging or inspecting BOP stacks.

D. Bop Arrangements Surface Stacks The following discussion is an excerpt from a paper by John A. Altermann, III. Used with permission. "Practical Considerations for Arranging, Testing BOP Stacks," World Oil, May 1980. The drilling business is often a series of compromises, both in equipment and practices. This is certainly true with BOP stack arrangements. 1. Location of the Blind Ram Consider placement of blind rams in a 3-ram surface BOP stack. If blind (or shear) rams are placed at the bottom of the stack, with no flowlines below, then the BOP stack has the advantage of a "master valve" for open hole situations, or a last resort valve if all else fails during a kick. But this placement also imposes limitations on stack use. For example, drill pipe cannot be hung off on pipe rams below the blind ram and the well killed by circulating through the drill stem. This arrangement may also force placement of pipe rams so close together that adequate space is not available for ram-to-ram stripping. On the other hand, if blind rams are placed at the top of the ram BOP stack, they can be replaced with pipe rams for ram-to-ram stripping operations to either protect the lower pipe ram or in the event of a tapered string, to furnish the pipe ram size that will fit the size of drill pipe being stripped. But this arrangement also presents a problem because it prevents the utilization of the blind ram as a master valve in open hole situations, for repair of items above it, or changing to casing rams. It also may force spacing of pipe rams so close that the ram-to-ram stripping is impossible. The question arises as to how to best maximize advantages of both of these placements and minimize disadvantages. The two compromise arrangements illustrated in this section (Figures K1-2C and K1-3C) place blind rams on top for tapered string drilling and in the middle when one size drill pipe is being used. This allows hanging off pipe in the pipe rams and circulation through the drill stem when kill and choke lines are placed properly; adequate clearance for ram-to-ram stripping; and partial utilization of the blind ram as a master valve for equipment out of hole repairs (top ram change to casing size obviously being safer with the blind ram in the middle). Notes 2b. and 3a. for Figure K1-3C (arrangement for tapered strings) indicates that space between the blind rams and small pipe rams limits certain activities. For tapered string application, this space problem could be eased by stacking the single ram unit on top of the double ram unit. Figure K1-3C shows the double on top, another compromise. In field use it is not practical to rearrange the BOP stack just before picking up a smaller drill pipe string.

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2. Arrangement of a Double and a Single Ram Unit A standard size 13-5/8 inch, 5,000 psi flanged double ram should be mounted on top of a single ram unit. This provides sufficient space for shearing above a standard 5 inch API NC50 connection hung in the bottom pipe ram as illustrated in Figure K1-4C.

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Bop Arrangement For One Pipe Size Figure K1-2C BOPs for One Pipe Size

Figure K1-4C Shearing w/K1-2C BOP Setup

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Figure K1-5C

Figure K1-6C

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Figure K1-7C

Activities Possible 1. Normal kill down drill pipe using either pipe ram. a. Choke flowlines 2 and 4 below each pipe ram. 2. Kill with blind or shear ram closed. a. Double ram unit must be on top of single ram to provide sufficient space for hang off and shear. b. Kill flowline 1 and choke flowline 4 must be arranged as shown. 3. Ram to ram stripping. a. Blind ram must be in middle to provide sufficient space. b. Kill flowline 1 to equalize pressure before opening bottom ram. c. Choke flowlines 2 and 4 to bleed fluid and monitor pressures below each ram during stripping. d. Kill flowline 3 to lubricate in fluid (volumetric method when bleeding gas) or kill below bottom ram. e. Could also strip between annular and either ram and do items 2, 3, or 4 above. 4. Location of blind ram in the middle. a. More room for ram to ram stripping as previously mentioned. b. Safe "out of hole" top ram change, annular element change or repairs to the single ram unit or annular. NOTE: Location of primary choke flowline 2 at alternate location 2a will allow all previously mentioned activities but is somewhat more exposed to mechanical damage.

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Bop Arrangement For Two Pipe Sizes Figure K1-3C BOPs for Two Pipe Sizes (Tapered String)

Figure K1-8C

Normal kill down drill pipe using either pipe ram. Figure K1-9C

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Kill with blind or shear ram closed. Figure K1-10C

Ram to ram stripping.

Activities Possible 1. Normal kill down drill pipe using either pipe ram. a. Choke flowlines 2 and 4 below each pipe ram. 2. Kill with blind or shear ram closed. a. Can hang off in large pipe (bottom) rams, shear, and kill. b. Can hang off in small pipe (top) rams but cannot shear due to small space so must back off before closing blind rams. c. Kill flowline 1 and choke flowlines 2 and 4 must be arranged as shown. 3. Ram to ram stripping. a. Could change blind ram to large pipe size and strip ram to ram but the arrangement shown provides i nsufficient space to strip small pipe ram to ram. b. Kill flowline 1 to equalize pressure before opening bottom rams. c. Choke flowlines 2 and 4 to bleed fluid and monitor pressures below each ram during stripping. d. Kill flowline 3 to lubricate in fluid (volumetric method when bleeding gas) or kill below bottom ram. e. Could also strip between annular and either small or large ram and do items 2, 3, and 4 above. NOTE: Relocation of kill flowline 1 required to accomplish kill procedures mentioned in items 2c and 3b. 4. Location of Blind Rams on Top. a. Can accomplish kill with either size pipe hung off. b. Can change to large pipe size for ram to ram stripping.

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c. Can change to either pipe size thereby minimizing wear on lower pipe rams, which inevitably occurs when pipe is worked with rams closed. d. A disadvantage is open hole exposure while installing casing rams while out of hole. NOTE: If the single ram unit were arranged on top of the double unit or there was enough space between the top and the middle ram is provided some other way, then small pipe ram-to-ram stripping might be possible. The illustration in K1-4C is for a standard length API NC50 pin and box joint. An extra long joint would probably not clear the shear ram in a standard 5M BOP. Each arrangement must be reviewed on a case-by-case basis. Some contractors prefer to assemble the single on top so that the annular and the single can be separated from the double for purposes of easier handling. Trade-offs may be necessary in this matter. The primary aim here is not to debate each point, but to emphasize the importance of critically reviewing BOP arrangements. Double rams units can be special ordered with enough room between rams to hang-off and shear. This special "long neck" double ram unit could be put on bottom, best satisfying both single and tapered string application. This discussion considers standard height double and single BOP units only, with no spool or special stacks, so the most practical compromise is to place the double ram unit on top. 3. Choke and Kill Flowlines Arranging rams is important, but choke and kill flowline (wing valves) placement is equally important to fully utilize the BOP. Again, compromises are made between the most conservative position of having no flowlines below the bottom ram and a middle road position of arranging the flowline for maximum BOP usage. Check valves, or non-return valves, are located in each "kill" wing valve assembly for the following reasons: a. To stop backflow in case the kill flowline ruptures while pumping into the well at high pressure. b. Other kill flowline gate valves between the check valve and BOP can be left open during kicks for pumping into the well whenever desired without personnel having to open them. Kill lines should not be used as fill-up lines. Constant use could result in erosion of lines and valves which would result in an unsuitable kill flowline. A separate line from the mud standpipe (independent of all choke and kill flowlines) is desirable for filling the hole during trips. Inboard valves adjacent the BOP stack on all flowlines are manual operated "master" valves to be used only for emergency. Outboard valves should be used for normal killing operations. Hydraulic operators are generally installed on the primary (flowlines 1 and 2 in Figures K1-2C and K1-3C) choke and kill flowline outboard valves. This allows remote control during killing operations. Choke/kill flowlines are generally not connected to the casing wellhead outlets but valves and unions are provided there as: 1. Reserve outlets for emergency use only. 2. Relief openings to prevent pressurizing of casing and open hole should a casing head plug tester leak during BOP testing. Flowing through a casing head outlet should be avoided. Should this connection be ruptured or cut out, there is no control. Therefore, primary and secondary choke and kill flowlines should all be connected to heavy duty BOP outlets (or spool outlets) with wellhead outlets used only in an emergency.

E. Suggestions For Rigging Up Surface Stacks The following practices and principles should be considered:

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1. All ring grooves should be cleaned of heavy grease. A ring will not seal properly if the ring groove is full of grease or "puddled" oil. A "light" film of oil only should be applied to ring grooves before nippling up. Avoid using a wire brush which would damage seal surfaces. 2. To achieve proper make-up torque on flange, clamp or BOP bonnets, a power torque wrench is useful. Bonnet bolt makeup torque is high and, if not properly tightened, could vibrate loose during drilling. Makeup torque tables are available from BOP manufacturers. Most tables give required torque using either API 5A thread lube or Molylube. Torque requirements using Moly-lube are much less so always be aware of the relationship between the lubricant and the torque requirement. 3. Plug all BOP control lines not in use to prevent accidental loss of accumulator fluid. Do not couple unused open and close control lines together. Plug them off! 4. All connections in choke, kill and relief lines, and the choke manifold, should have a pressure rating at least equal to the rating of the BOP stack. 5. Choke and kill wing valves are subjected to severe mechanical and vibrational stresses during drilling operations and when handling or controlling a "kick". Where practical, all overhanging valves, piping and connections should be supported. NOTE: When operating wing valves that have pressure on them, proper manufacturer procedures should be observed to prevent explosive decompression of the elastomer. 6. Swivel joint pipe sections in flowlines are necessary for ease of rig-up, but where practical, "choke" flowlines from BOPs to manifold should be straight or curved (hoses). Sharp turns should be minimized, and where practical, targeted tees with lead-filled bull plugs should be used to minimize flow stream erosion. Using swivel joint pipe in kill flowlines is not as bad, because of less severe vibrations and fluid conditions. Choke flowlines conduct well fluid under pressure from the well to the choke manifold. Flow velocities are sometimes greater than through the kill line by virtue of the expansion of gas in the annulus, so small lines may create high pressure drops and erosion. By sizing the primary choke line to a larger size (minimum 3 inch I.D. instead of 2 inch), the line will have greater strength, less frictional pressure loss and be subjected to less wear. 7. Where applicable, all connections, piping and valves in flowlines should be protected from freezing by draining, heating or keeping the line filled with non-freezing fluid. 8. The gas/mud separator (gas box), vessel diameter, gas vent exhaust and mud seal at the discharge should be designed to separate the maximum expected influx and not allow gas to exit the mud discharge or mud to exit the gas vent.

F. Bop Test Procedures Surface Stacks This section contains a typical BOP test procedure using the Figure K1-2C arrangement. Figures K1-11C through K1-14C illustrate each test step.

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Figure K1-11C Test Casing String and Casing Head Valves

Figure K1-12C Test Upper Casing Joints after Drilling Shoe

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Figure K1-13C Test Blind Rams

Figure K1-14C Test Pipe Rams, Annular, Choke and Kill Manifolds, etc

The objective of this test example is to focus on principles that could apply for testing any BOP system.

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Test Frequency and Test Pressures: BOP test pressure and frequency requirements vary between governmental regulators, operator and contractors. The following are general recommendations. 1. Test Frequency a) After initial installation. b) After each easing setting operation. c) Before drilling into any known or suspected high pressure zones. d) Routine test no less than once each seven days of operation. e) After a ram change, maintenance or BOP repair, test the component that was effected. f) Prior to a production test. 2. Test pressures The rams and annulars should be tested in two stage, at a low pressure test of 200 to 300 psi and then at maximum test pressure. Both pressure holding periods should not be less than three minutes. A 5 or 10 minute holding period is common. Rams and choke manifold should be tested to full working pressure upon: a) Initial installation of BOP on wellhead. b) Maintenance or repair. Only test the effected component(s). Routine ram and choke manifold maximum test pressure should be limited to the lesser of: a) 70% of rated working pressure. b) Wellhead rated working pressure. c) 70% of casing minimum internal yield strength. However, in no ease should these or subsequent test pressures be less than the maximum anticipated surface pressure. The annular BOP maximum test pressure should not exceed 70% of rated working pressure or 70% of casing minimum internal yield strength, whichever is less. If governmental regulations or the operator does not stipulate annular BOP test pressures, do not exceed 50% of working pressure. All well control system components should be tested in the direction normally felt by wellbore pressure during a kick. 3. Test Fluids a) For water base muds, use water. b) For oil base muds, use diesel or an acceptable alternative. 4. General Testing Procedures a) All choke manifold and choke and kill flowlines should be flushed out before each test and clean water be inside all systems being tested when pressure is applied. Drilling mud is a good sealant, which makes it an unsuitable test fluid.

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b) Pipe-rams should be closed only when there is pipe in the hole. Closing rams on the wrong size pipe or ON OPEN HOLE could result in ram front packer damage. This fact is often overlooked. c) To prevent collapsed pipe, vent the annulus when closing a pipe ram. If a ram is forced into a closed BOP bore, the trapped fluid pressure will rise rapidly as the operating cylinder rod enters the BOP cavity.

G. A BOP Test Sequence Notations on figures K1-11C through K1-14C generally provide sufficient explanation. The following comments supplement the figure notations where further explanations are necessary. 1. Testing the entire casing string and casing head valves -- Figure K1-11C Some operators prefer to apply casing test pressure when the cement plug bumps. The reasoning is that microcracks in the cement may occur if test pressure is applied after cement has set up. 2. Testing upper casing joints after drilling the shoe -- Figure K1-12C After drilling the casing shoe, all future weekly tests of casing and casing head requires use of a casing cup tester. The cup tester is nothing more than a swab and must have the proper OD to fit upper size and weight casing joints (refer to Figure K1-15C).

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Figure K1-15C Cup Type Tester

The appropriate cup tester is made up on drill pipe and lowered approximately 90 feet (two casing joints) below the easing head. Some operators require that the cup tester be run into the casing to a point below cement on the outside. At, er filling the stack with clean water, the top pipe rams or annular is closed. Pressure is built up by either pumping down the flowlines or by hoisting the drill string slowly (as shown in K1-12C) to provide desired pressure. Hoisting the drill string is preferred over pumping, because there is less chance of accidentally exceeding casing yield or drill pipe strength. Pressure applied to the cup tester directly imposes a load on the drill pipe test string which could cause drill pipe failure, particularly with Grade E. The usual problem is collapsed pipe due to a combination of outside crushing forces and pull. A safe approach is to use Grade S135 or heavy wall drill pipe for all casing tests. Another technique is to run a casing head plug tester in combination with a cup tester. The casing head plug would be spaced out 90 feet above the cup with heavy wall pipe. After landing the casing head plug, test pressure would be applied through the casing head outlets. This allows the cup-induced forces to be supported by the casing head. Regardless of the approach, remember that all cup testers are swabbing devices. To prevent swabbing, pull the cup slowly and never run a test string that is not fully open to atmosphere. In other words, the underside of the cup must always be open through the test string bore.

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a. Before drilling out any casing shoe, test entire casing to operator's specifications, but never exceed 80% of rated casing burst pressure. b. Flush all lines and fill BOP with water. Close blind ram. Pressure up using cementing pump through kill manifold or a special test pump through (alt.) point. This tests entire casing string plus casing head valves. NOTE: Casing tests are the only tests where casing head valves are closed. These valves should always be open for other tests to prevent casing or formation rupture should casing head plug tester leak. a. Run appropriate size and weight casing cup tester on drill pipe to approximately 90 feet below casing head. Fill annulus with water and close top ram. b. Build up test pressure to operator's specifications by lifting drilling pipe, being careful not to exceed 80% of rated easing burst pressure or tensile strength of drill pipe being used. 3. Testing the Blind Ram -- Figure K1-13C Refer to Testing Blind Ram -- Figure K1-13C for Test Procedure Most kill and choke manifold valves, flowlines, and BOP wing valves could be pressured during the Figure K1-13C test. However, the test string arrangement in Figure K1-14C (pressuring down the drill pipe which simulates a well kick) is best suited for this purpose because all valves can be tested in the direction that the pressure is applied during a kick. Therefore, Figure K1-13C test is designed primarily to test the blind ram only by pressuring down a kill flowline. Several precautionary notes are necessary for test steps illustrated in Figures K1-13C and K1-14C. a) Insure that casing head valves are always open when a casing head plug tester is in use. This allows detection of a plug tester seal leak and prevents over pressuring of casing or open hole. b) Casing head plug testers come in many shapes and sizes. Figure K1-16C illustrates a test plug.

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Figure K1-16C Test Plug

Some have special features such as integral peas. Some have open bore with bull plugs provided for testing the blind rams while others are solid bore. Some function as combination plug testers and wear bushing retrievers. Failure to select the proper size and style test plug can cause problems. Casing head hanger contours vary. For example, a CIW Type "F" 5,000 psi tubing head has tapered contours, while the Type DCB head is straight contoured. Insert a Type F plug tester in a Type DCB head, pressure up, and the two will become almost inseparable. Always consult with the casing head manufacturer to insure that the appropriate plug tester is being used. 4. Testing Pipe Rams, Annular -- Figure K1-14C Refer to Testing Pipe Ram -- Figure K1-14C for Test Procedure Test the BOP, and all choke and kill manifolds, flowlines and BOP wing valves. Some casing head plug testers are manufactured with an integral port which allows the BOP bore cavity to be pressured by pumping down the drill pipe test string. If the plug tester is not equipped with an integral port, a perforated sub could be used with the test plug. Be sure the casing head outlet is open to prevent pressuring casing and open hole. Since the BOP bore is being pressured through the drill pipe, all valves can be tested in the normal well kick direction. By sequencing valves, open and closed in proper order, a minimum of repressuring will be necessary. Always leave downstream valves open and remove the spring loaded check in the check valve (when applicable) to insure a valid test on each kill valve. It is important that all manifolds and flowlines be flushed out before this test so that all are clear and full of water. Note: When applying pressure against a casing head plug tester, always open the casing head outlets below the tester seals to recognize a leaking seal and prevent formation or casing damage should the seals leak. BE SURE THE CASING HEAD PLUG TESTER FITS THE CASING HEAD.

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The rams, annular, and hydraulic operated valves should be tested in two stages. API RP53 recommends a low pressure test of 200 to 300 psi held for three (3) minutes before pressuring up to full test pressure. There are several reasons for this: * Many preventers are designed such that the well bore pressure (test pressure) causes a closing force, so the BOP may be more likely to leak at 200 to 300 psi pressure than at full test pressure. * Since actual well kicks are normally closer to 300 psi than full working pressure, the low pressure test is significant. * Finally. mud solids sometimes plug a potential leak hole. A low pressure test will come closer to uncovering this hole than the full test pressure. Some annular preventers will hold maximum test pressure with no more than 700 to 1,000 psi operating pressure. Because of special design features, operating pressure (from accumulator) should be reduced on Hydril GK and 21-1/4 inch MSP annulars as the test (well bore) pressure increases. This greatly reduces element stress. For example, on a GK 16-3/4 inch 5,000 psi annular, if operating pressure is held at 700 psi (closing chamber), the compression force on the element increases from approximately 380,000 lbs. at zero test pressure to about 780,000 lbs. at 3,500 psi test pressure. On the other hand, if operating pressure is reduced according to Figure K1-18C, compression force on the element will actually reduce to about 180,000 lbs. Figure K1- 18C Annular BOPE Operating Characteristics w/5" DP

If an annular BOP of this type is tested, use an operating pressure versus test pressure chart to minimize element stress. Consult the Operating Manual. From Figure K1-18C, the following schedule, Table K1T-19P for test pressure versus operating pressure was developed for a 13-5/8 inch or 16-3/4 inch GK 5,000 psi annular on 5 inch drill pipe. Notice that at test pressures higher than about 2,000 psi, regulated operating pressure is applied to the OPENING chamber instead of the closing chamber.

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Table K1T-P19 Operating Pressure vs Test Pressure

Notes on Table K1T-P19 * Operating pressure may vary with individual packing elements (bags). Adjust operating pressures accordingly, but do not exceed maximum closing pressure of 1,500 psi except on CIW Type D annulars. ** During actual kick situations, for safety's sake, operating pressure should not be applied to the OPENING chamber of well bore pressure. 5. Testing inside BOPs, kelly valves, swivel and rotary hose -- Figure K1-17C Figure K1-17C Test Inside BOPs, Kelly Valves, Swivel and Rotary Hose

Refer to Testing inside BOPs, kelly valves, swivel and rotary hose -- Figure K1-17C for Test Procedure a. All equipment in test should be tested to rated pressure of weakest member. b. Pick up kelly, install full open safety valve on bottom of lower kelly valve. Using an adapter, connect to an independent test pump or cement pump.

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c. Open appropriate standpipe valves and all kelly valves. Fill system with water and close standpipe valve to test standpipe, rotary hose, swivel and kelly. By alternately closing upstream and opening downstream valves, all kelly valves could be tested without pressuring up again, although it may not be possible to operate the upper kelly valve under pressure. d. Although not shown, the inside BOP (float type) can be tested similarly by installing below the safety valve and opening all valves through the standpipe. Remember that each make, size and model annular preventer may have unique characteristics. For example, most annulars require increasing, not decreasing, closing pressure to prevent leaks as test pressure increases. Using incorrect procedures could cause damage or be unsafe. Always consult the manufacturer for testing recommendations. Casing sizes larger than 7 inches might be collapsed by annular element forces if the operating pressure is too high. Recommended maximum operating pressures for closing on various manufactures size casing can be obtained from most annular preventer manufacturers. Figure K1-19C BOP Arrangements SubSea Stacks

H. Bop Arrangements Subsea Stacks Figure K1-20C and K1-21C illustrates typical subsea BOP arrangements.

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Figure K1-20C Subsea BOP Arrangement

Figure K1-21C1 Subsea BOP Arrangement - Block Diagram

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Figure K1-21C2 Subsea BOP Arrangement - Schemetic

Some of the differences when compared to surface stacks are: 1. More backup units needed because of the difficulty of retrieving and deploying a subsea BOP. 2. Upper annular(s) can be recovered with the riser for repairs without removing the "big" stack. 3. Do not normally pull BOP for casing ram change so two annulars are needed for back-up. 4. Variable bore rams usually installed in one of the ram cavities to provide redundancy when tapered strings are used or when running production casing. 5. The blind shear rams are generally set high in the stack to provide more pipe hang-off options below. With the blind shear rams closed over hung-off pipe, the well can be monitored or circulated in pipe or annulus. 6. The choke and kill lines are dual purpose, i.e. either can be used to kill (pump in) or choke (direct to choke manifold). 7. Figure K1-20C illustrates an "alternate" outlet below the upper annular to facilitate purging trapped gas after a kill operation. This is particularly important in deep water operations. 8. Two fail-safe valves for each choke and kill BOP outlet that are fail-safe in the closed position. 9. Two hydraulic or electro hydraulic control PODs each with 100% redundancy. 10. All rams equipped with remote operated ram locks.

I. Testing Procedure For Subsea Bops 1. SS BOP Test Pressures And Test Frequency Test pressures and test frequency are similar to surface stacks with the following notable exception: All subsea BOP stack rams and valves are generally tested at surface (on a test stump) to their rated working pressure. The annular is generally tested to 70% of rated working pressure: The subsea stack, once deployed and connected to the conductor casing wellhead is not disconnected until the well is complete. Therefore, a higher stump test pressure is required than is normal for surface stacks.

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2. Tests before lowering the BOP stack. All subsea BOP stack components should be installed, checked, and pressure tested to their rated working pressure and to a low pressure of 250 psi while the stack is mounted on the test stump. After the surface tests, all clamp connections and all studded connections should be checked for tightness. The complete BOP operating unit should be tested in accordance with manufacturers' recommendations and pressure tested to its rated working pressure. The test should include at least the following: * to test every BOP control; * to check that each function is properly connected; * to activate the functions which are indicated from both control pods; * to check and record test volumes and response times for each function. The choke manifold, valves, kill-and choke lines and fail-safe valves should be pressure tested with water to the rated working pressure of the ram type preventers, or the rated working pressure of the manifold, whichever is the lower. The kelly or top drive and kelly stop-cocks should be pressure tested to their rated working pressure with a test sub. 3. Tests after connecting BOP stack When running the BOP stack on riser joints, the kill and choke lines should be pressure tested at least when the stack is below the splash zone and both before and after landing. More frequent testing may be stipulated, i.e. each 5 or 10 riser joints. After the BOP stack is connected to the wellhead, a full function test on both pods, plus a low pressure test of 250 psi should be carried out. The pressure test upon initial and any subsequent mating of the BOP and wellhead should be performed with sea water to the maximum anticipated pressure at TD of the well to confirm connector/wellhead integrity. This pressure is only required against one pipe ram if the stack has been completely stump tested prior to running. For routine tests, the BOP will be tested with the fluid in the hole at the time of the test. In deep water, a serious well control problem could develop due to loss of hydrostatic head, with the choke and kill line full of water. Therefore, after initial and subsequent mating of the BOP on the wellhead, the choke and kill lines will be kept full of in-hole drilling fluid. All lines should be flushed daily to ensure they are not blocked. In shallow water (less than 1500 ft), operators may prefer to keep the choke/kill lines filled with sea water to prevent solids from settling out. Blind shear rams are normally tested against casing prior to drilling out; to 250 psi and then again at a higher pressure as indicated on the actual drilling prognosis. The blind shear rams are generally not retested during the normal test intervals as is done with the other BOP components unless the seal integrity is in question, but will be retested prior to drilling out of subsequent casing strings. 4. Routine Tests The opening/closing times and the volumes of hydraulic operating fluid required for the operation of the various underwater stack components (i.e. rams, kill-and choke line valves, annular preventers, hydraulic connectors, etc.) shall be recorded during testing of the stack underwater. These results shall be compared with the normal opening/ closing times and volumes required of the hydraulic system. Any major differences are an indication that the

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system is not operating "normally" and shall require further investigation and possible repair. Pressures of the wellhead or preventers should be to the anticipated wellhead pressure with a maximum limit for the annular preventer of 70% of its working pressure. It should also be pressure tested to a low pressure of 250 psi.

IV. Inside Blowout Preventers There are several pieces of equipment in addition to the primary blowout prevention equipment that are sometimes necessary to control a kick. The equipment which furnishes closure inside the drill string is called an "inside" blowout preventer. A number of devices serve this purpose. The "names" of these devices are often confusing. The IBOP table classifies inside BOP's to eliminate this confusion. Also refer to Figures A through G2 below.

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Table K1T-P26 Inside Blowout Preventers

Figure A Upper Kelly Valve

Figure B Lower Kelly Valve

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Figure C Safety Valves In Top Drive System

Figure D1 Splined Top Drive Safety Valve

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Figure D2 Plain Top Drive Safety Valve

Figure E Inside BOP

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Figure F Wireline Retrieval and Drop-in Check Valve

Figure G1 Bit Float

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Figure G2 Poppet Type and Flapper Type Floats

1a. Upper Kelly Valve The upper kelly valve, or kelly cock (Figure A), is installed between the kelly and the swivel and normally has left hand threads. Because it is installed above the kelly, it is always available. The basic purpose of this valve is to isolate the fluid in the drill string from the swivel, rotary hose or standpipe and to prevent leaks or rupture under well conditions. If the drill pipe pressure exceeds the rating of the rotary hose, closing the valve allows a safe change to higher pressure connections. It also permits removal of the swivel so that wire lines or tools may be run into a pressurized drill string. The most common design has a flapper as shown in Figure A. The other design is a full open ball similar to the lower kelly valve. The upper kelly valve should have a WP rating equal to or greater than that of the blowout preventer assembly being used, and should have an inside opening equal to that of the kelly. To operate this valve, a special wrench is required, and should be kept in an accessible place on the rig floor.

1b. Lower Kelly Valve A lower kelly valve (Figure B) sometimes called a lower kelly cock. It is installed on the lower end of the kelly, and is used when the upper kelly valve is damaged or not easily accessible. If the kill pressures approach the rotary hose ratings, this valve is closed, the kelly broken out and set back and the cement standpipe hose is connected via a circulating head to the lower kelly valve.

1c. Safety Valve During trips on rigs with kelly drive, the kelly and both upper and lower kelly valves are stored in the rat hole. For this reason, another valve, identical to the lower kelly valve, is stored close by so it can be quickly installed on the drill pipe during a trip should a kick occur. When used in this manner, it is called a safety valve. If a tapered drill string is being used, then a safety valve for each size pipe and crossovers to drill collar connections must be available on the rig floor.

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All of these kelly and safety valves should be operated at the beginning of each tour. They should be tested when the BOP is tested and the pressure should be applied in the direction pressure would be felt should the well be closed.

2. Upper Remote Safety Valve and Lower Safety Valve The upper and lower safety valves on top drive systems are connected together. They are a ball type design. Both are very likely to be inaccessible should a kick occur during drilling operations, so the upper valve is remote operated as shown in Figure C. The body on this particular design is splined to accommodate the pipe handler system. Some top drive units use a different kind of torquing mechanism which does not require a special O.D. profile on the upper safety valve. In these cases, the upper and lower safety valves may be identical except that the upper is fitted with a remote actuator crank and the lower is plain manual operated. Figure C illustrates the two valves installed in the top drive assembly. Figure D1 & Figure D2 show these two valves separated. During trips with the top drive system, the swivel and safety valves are not set back but rather are hoisted with the drill string. Should a kick occur during the trip, the safety valves are immediately connected to the drill string, and the upper valve remotely closed. There is no need to have another safety valve on standby as with kelly drive operations.

3a. Inside BOP Although all valves that secure the drill string bore are "inside" BOPs, the check valves discussed in the following paragraphs are the only ones commonly called "inside BOPs" (Figure E). They are normally used for stripping in the hole under pressure when a kick occurs off bottom during a trip. By utilizing a special tool, the inside BOP or check valve may be kept open to permit stabbing into the drill string when the well is kicking. Once made up in the drill string, the tool is released and the check valve closes. However, check valves are more difficult to stab against drill pipe flow than are full open ball valves. Therefore, the full open safety valve should be installed first and then the "inside" BOP (check valve) installed if it is necessary to strip back in the hole.

3b. Drop In Check Valve Another type inside BOP is the pump down or drop-in type which requires a special sub near or in the bottom hole assembly of the drill string. These inside BOPs are often used in stripping operations and particularly stripping "out" operations. Some are wireline retrievable. Figure F shows one type of drop-in check valve.

3c. Bit Float A bit float (Figure G1 & Figure G2) may be considered an "inside" preventer. It is basically a flapper or poppet type check valve that is installed in the bit sub to prevent backflow during connections; however, it is subjected to severe wear by the drilling mud and may not function when needed. A common practice is to use a slotted flapper. This reduces backflow to a minimum, yet allows stabilized closed-in pipe pressure to be easily read should the well kick.

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Most operators discontinue the use of bit floats after setting surface casing. Kicks are more likely to occur below surface casing and the bit float might interfere with a good stabilized closed in drill pipe pressure reading. Bit floats are most useful in top hole drilling where backflow during connections is more likely due to imbalanced annular fluid density.

V. Choke Manifold 1. Purpose If the hydrostatic head of the drilling fluid is insufficient to control subsurface pressure, formation fluids will flow into the well. To maintain well control, back pressure is applied by routing the returns through adjustable chokes until the well flow condition is corrected. The chokes are connected to the blowout preventer stack through a arrangement of valves, fittings, and lines which provide alternative flow routes or permit the flow to be halted entirely. This equipment assemblage is designated the "choke manifold."

2. Design Considerations Choke manifold design should consider such factors as anticipated formation and surface pressures, method of well control to be employed, surrounding environment, corrosivity, volume, toxicity, and abrasiveness of fluids.

3. Installation Guidelines Recommended practices for planning and installation of choke manifolds for surface installations include: 1. Manifold equipment subject to well and/or pump pressure (normally upstream of and including the chokes) should have a working pressure equal to the rated working pressure of the blowout preventers in use. This equipment should be tested when installed to pressures equal to the rated working pressure of the blowout preventer stack in use. 2. Components should comply with applicable specifications to accommodate anticipated pressure, temperature, and corrosivity of the formation fluids and drilling fluids. 3. For working pressures of 3M and above, flanged, welded, or clamped connections should be employed on components subjected to well pressure.. 4. The choke manifold should be placed in a readily accessible location, preferably outside of the rig substructure. 5. The choke line (which connects the blowout preventer stack to the choke manifold) and lines downstream of the choke should: a. Be as straight as practicable; turns, if required, should be targeted. b. Be firmly anchored to prevent excessive whip or vibration. c. Have a bore of sufficient size to prevent excessive erosion or fluid friction: 1) Minimum recommended size for choke lines is 3-in. nominal diameter (2-in. nominal diameter is acceptable for Class 2M installations). 2) Minimum recommended size for vent lines downstream of the chokes is 3-in. nominal diameter. 3) For high volumes and air or gas drilling operations, 4-in. nominal diameter lines are recom mended. 6. Alternate flow and flare routes downstream of the choke line should be provided so that eroded, plugged, or malfunctioning parts can be isolated for repair without interrupting flow control.

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7. Consideration should be given to the low temperature properties of the materials used in installations to be exposed to unusually low temperatures. 8. The bleed line (the vent line which by-passes the chokes) should be at least equal in diameter to the choke line. This line allows circulation of the well with the preventers closed while maintaining a minimum of back pressure. It also permits high volume bleed-off of well fluids to relieve casing pressure with the preventers closed. 9. Although not shown in the typical equipment illustrations, buffer tanks are sometimes installed downstream of the choke assemblies for the purpose of manifolding the bleed lines together. It also provides a large chamber for gas expansion and reduction in gas velocity. When buffer tanks are employed, provision should be made to isolate a failure or malfunction without interrupting flow control. 10. Pressure gauges suitable for drilling fluid service should be installed so that drill pipe and annulus pressures may be accurately monitored and readily observed at the station where well control operations are to be conducted. 11. All choke manifold valves subject to erosion from well flow should be full-opening and designed to operate in high pressure gas and drilling fluid service. Double, full-opening valves between the blowout preventer stack and the choke line are recommended for installations with rated working pressures of 3M and above. 12. For installations with rated working pressures of SM and above the following are recommended: a. One of the valves should be remotely actuated. b. Double valves should be installed immediately upstream of each choke. c. At least one remotely operated choke should be installed. If prolonged use of this choke is anticipated, a second remotely operated choke should be used. d. A valve should be installed downstream of the choke to provide isolation from the buffer tank when changing wear items while circulating through the second choke. e. Downstream of the choke, a decrease of one pressure rating, ie. 5M down to 3M, 10M down to 5M, etc., may be considered for the valves and buffer tank. 13. Spare parts for equipment subject to wear or damage should be readily available. 14. Testing, inspection, and general maintenance of choke manifold components should be performed on the same schedule as employed for the blowout preventer stack in use. 15. All components of the choke manifold system should be protected from freezing by heating, draining, or filling with proper fluid. 16. Figures K1-1E through K1-3E illustrate typical choke manifolds for various working pressure service.

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Figure K1-1E 2000 & 3000 psi Manifolds

Figure K1-2E 5000 psi Manifold

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Figure K1-3E 10000 & 15000 psi Manifolds

Refinements or modifications such as additional hydraulic valves and choke runs, wear nipples downstream of chokes, redundant pressure gauges, and/or manifolding of vent lines will be dictated by the conditions anticipated for a particular well and the degree of protection desired. The guidelines discussed and illustrated represent typical industry practice. For economic reasons it may be desirable at the beginning of a drilling operation to install a manifold with a pressure rating equivalent to that of the highest pressure rated system which will be used on that well. This will preclude the necessity of always matching manifolds with BOP stack ratings, minimizing time lost changing choke manifolds, and reduce the number of manifolds held in inventory. Screwed connections are optional for only the 2M manifold; all others shall be welded or flanged. IADC recommended configurations are shown in Figure K1-1E, 2E, and 3E, for 2M and 3M, 5M, 10M, and 15M manifolds respectively.

VI. Diverter Systems A. General 1. Function. The function of a diverter system is to provide a low pressure well flow control system to direct controlled or uncontrolled wellbore fluids or gas away from the immediate drilling area for the safety of personnel and equipment involved in the drilling operation. The diverter system is not designed to shut in or halt well flow. 2. Sour Gas Environment (H2s). Diverter system equipment that can be exposed to a hydrogen sulfide environment should comply with NACE MR-01-75: "Material Requirements Sulfide Stress Cracking Resistant Metallic Materials for Oil Field Equipment", latest edition.

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3. System Description. A diverter system is comprised of the following components: a. Annular Sealing Device. The annular sealing device is available in three different designs. These designs are: b. Annular Packing Element. Figure K1-1F is an example of an annular sealing device that utilizes an annular packing element as the sealing mechanism. Figure K1-1F Diverter w/Annular Packing Element

The annular packing element can effect a seal on any pipe or kelly size in the wellbore, or can effect a seal on open hole where no pipe is present. This is often times referred to as "complete shut-off" (CSO). c. Insert-type Packing Element. Figure K1-2F is an example of an annular sealing device that utilized an insert-type packing element as the sealing mechanism.

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Figure K1-2F Diverter w/Insert Type Packing Element

An insert-type packing diverter element uses a group of inserts. The inserts are placed one inside the other. Each insert in the group is designed to close and seal on different ranges of pipe diameters. A hydraulic or mechanical function serves to latch each insert in place. The correct size insert should be in place for the pipe size in use. In order to pass large bottom hole assemblies, it is necessary to remove some or all of the inserts. An insert-type packing element can not CSO. d. Rotating Head. A rotating head can be used as a diverter to complement a blowout preventer system. The stripper rubber is energized by the wellbore pressure to seal the rotating head element against the drill pipe, kelly, or other pipe to facilitate diverting return wellbore media and can be used to permit pipe movement. e. Vent Outlet(s). Vent outlet(s) for the diverter system are located below the annular packing element. One or more vent outlets can be used in a system. Vent outlet(s) may either be incorporated in the housing of the annular sealing device, or may be an integral part of a separate drilling spool/mud cross that is assembled using a flange or clamp type connection just below the annular sealing device. Design considerations for the connection between the vent outlet(s) and the vent line(s) should include ease of installation, leak-free construction, and freedom from solids accumulation. Regarding the size of the vent outlet(s), different regulator bodies have different requirements, depending on the area of operation. For example, the requirements for drilling operations that utilize a surface wellhead configuration in areas regulated by the U.S. Minerals Management Service (reference CFR 30, Chapter II, 7-1-88 Edition, paragraph 250.59) require that no spool outlet or diverter line shall have an internal diameter less than 10 inches; except in the case where dual outlets are provided, in which case the minimum internal diameter of each vent outlet is 8 inches. For drilling operations where a floating or semi-submersible type drilling vessel is used, the vent outlet internal diameter shall not be less than 12 inches. For drilling activity outside the United States, the drilling contractor is advised to become familiar with the regulations for that particular area of operation.

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f. Drilling Spool/Mud Cross. If a drilling spool/mud cross is utilized under the annular scaling device, the throughbore diameter of the drilling spool/mud cross should be equal to the through-bore diameter of the annular sealing device. The design working pressure rating of the drilling spool/mud cross should be equal to the design working pressure rating of the annular sealing device. g. Valves. Valves used in a diverter vent line(s), or in the flow line to the shale shaker in a floating drilling operation, should be full-opening, have at least the same through-bore opening as the vent outlet that it is attached to, and should be capable of opening with maximum anticipated pressure across the valve sealing mechanism. Several types of fullopening valves which can be used in this application are gate valves (various types), ball valves, knife valves, switchable three-way targeted valves (see Figure K1-3F), and valves that are integral to the annular sealing device. Any valve used in a diverter system application should be fitted with remote actuators capable of operation from the rig floor. The actuators can be operated either with hydraulics or pneumatics. The actuator should be sized to open the valve with the maximum system rated working pressure across the closed valve sealing mechanism, with hydraulic or pneumatic pressure that is available from the diverter system remote control unit. The trim of the internal components of the valve actuator should be suitable for the media that is going to be used to operate the actuator. If a water-base fluid is the media, the actuator trim should be suitable for water service; corrosive. Excessive resistance due to drilled solids in the valve should be kept in mind, especially if using a pneumatic system where variations in rig air pressure are common.

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Figure KI-3F Switchable 3-Way Target Valve

Figure K1-4F Typical Diverter System with Control Sequenced Flow System

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Figure K1-5F Example of Purpose Designated Diverter with Built-In Vent Valving

Figure K1-6F Substructure Mounted Diverter System for Onshore and/or Bottom-Supported Offshore Installation

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Figure K1-7F Substructure Mounted Diverter with Annular Packing Element

Figure K1-8F Diverter for Foater Installations with Built-In Flow Line and Vent Line Packing

h. Vent Line Piping. There are various considerations that need to be investigated for the vent line piping in a diverter system. These considerations are as follows: i. Sizing. The vent line piping in a diverter system should be sized to minimize back pressure on the wellbore while diverting wellbore media. The vent line should be run as straight as possible, keeping in mind that bends, tees, and elbows not only create higher back pressure than straight pipe, but are more susceptible to erosion during a diverting operation than straight piping. Just as with the vent outlet(s) discussed in the above paragraph, government regulatory bodies have minimum requirements for the internal diameter of the vent line piping. The drilling contractor should be familiar with the requirements for the area where the drilling operation is going to take place. j. Flexible Lines. Flexible lines with integral end couplings can be employed in a diverter vent line piping system. If used, the flexible lines should have the same or larger internal diameter as the vent outlet and valve, they should be resistant to fire and erosion, have end couplings that are compatible with those utilized in the hard piped section(s) of the vent line piping system, and supported adequately. k. Routing.

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The vent line(s) used in a diverter system should be routed so that at all times one line can vent wellbore media to the downwind side of the rig. Routing changes should be as gradual as possible. Long radius bends are preferred over short radius bends. In the ease of a 90

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K2. Blowout Preventer Control Systems A. Surface Bop Stacks, (Land Rigs, Offshore Jackups, And Platforms) 1. System Description Control systems for surface mounted blowout preventers used for well drilling are usually "closed loop" design hydraulic systems. This means two lines are required for all pressure open/pressure close BOP stack functions, and that fluid in one line is returned to the control unit reservoir when the other line is pressurized. These systems lend themselves to use of petroleum base fluids for the control system operating fluid. Since there is a possibility of an "ecological incident" in the event of a system leak, many offshore contractors are turning to the use of water base control system fluids. Water base fluids have no detrimental effect on operations as long as: 1. Environmentally safe lubricating agent is added to the water. 2. Freeze protection is provided if the system is to be operated in cold climates. 3. The fluid is regularly inspected and bacteria growth is checked either by addition of chemical agents or timely replacement of the fluid. Water base control system fluid can be premixed in proper ratios in accordance with the control system manufacturers recommendations. The control system manufacturer should specify control system fluid which is compatible with the equipment seals and materials.

2. Installation The main accumulator with its hydraulic control manifold, separate hydraulic manifold, or hydraulic panel should be installed in a safe area protected from falling debris or gas accumulations during a blowout. All of the control functions should be operable from the drill floor by use of a remote control panel. A second remote control panel is recommended. This panel is normally located in the tool pushers office or in a safe egress area and is intended as a last means to close in the well as the rig is being abandoned. The initial installation, (and each time the rig is moved), should be fully tested to ensure proper leak free operation and correctness of function. Hydrostatic test should be to full working pressure and/or ten percent below any relief valves in the line. Piping downstream of pressure reducing and regulating valves should be tested to the maximum (full open) regulator settings. Automatic pump system cut off devices should be tested to ensure the pump(s) cut off at the maximum system design working pressure. The system design capacities should be verified at the initial installation and interface of the control system to the BOP stack. The contractor must ensure that all companies, local statues, governmental and other governing agencies at the drilling venue have been met in the design. In particular, the contractor must ensure the following: 1. The control system design meets or exceeds the performance requirements of the most stringent of the regulatory bodies in force. 2. Accumulator precharge is maintained within the control system manufacturer's specification. 3. Pump system cut "on" and cut off automatic set points are maintained at the control system manufacturer's specification for the system design. 4. Closing response times from activation at any control point are within the time limits of the most stringent of the regulatory bodies in force. NOTE: The minimum performance and capacities recommendations for surface BOP well drilling control systems is listed in API RP 16E, Section 16E.2. Refer to latest edition.

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3. Operation Well control procedures are discussed in Section K3. These procedures are intended to inform of possible well control practices that have proven practical. They should not be interpreted to be a solution to all problems. Control system manufacturers generally make the following operational recommendations. 1. During normal drilling, the blowout preventer control valves are typically in the "open" position, kill and choke valves are typically in the "closed" position. This will hydraulically lock the BOP in position, give visual indication of the annular, ram or valve position and most importantly, indicate leaks in the valves, lines or BOP which can be detected by the pumps coming on too frequently. 2. Ensure all pump system (air and electric) power is "on line" at all times. 3. Ensure all accumulator banks are "on tine" at all times. 4. Ensure pump system automatic "on"/"off" limits are properly set. Setting the pump system cut off too low results in significantly reducing usable fluid capacity o f the accumulator system. Setting the pump system "on" point too low results in accumulator pressure being too low, and the usable fluid capacity reduced significantly so that the BOP performance is adversely affected. 5. Ensure the nitrogen precharge in all of the accumulators is properly maintained within the specified limits. Reduced precharge decreases the recoverable (usable) fluid from the accumulator. Zero precharge (probable ruptured bladder) equals nil recoverable fluid. The nitrogen precharge must be measured when there is zero hydraulic pressure on the accumulators. This means they must be bled back to the reservoir to measure precharge. 6. Operate with the fluid reservoir approximately half full. Reservoirs are typically sized to hold at least twice the recoverable (usable) fluid of the accumulator system. This means bleeding down all of the accumulators is possible without overflowing the reservoir. Newer systems built in accordance with API RP 16E have twenty-five percent (25%) accumulator bank isolation. They also have isolation and bleed valves on each bank permitting checking precharge on one bank at a time without shutting down operations. 7. Ensure all components of the BOP control system are in proper working order, clean, and, where required, lubricated.

4. Typical Maintenance Items While BOP control systems by various manufacturers may vary widely in color, size, configuration, and layout, they are functionally very similar. The following tables K2-1A "Typical Surface BOP Control System" and K2-2A. "Preventative Maintenance Schedule Check List" are not intended to promote any manufacturer's product. They are intended to highlight areas that need to be identified and properly maintained to ensure the capability or the control system to perform to its design intent.

5.

Nitrogen Back-up Systems

A. Nitrogen back-up systems used for closing blowout preventers in the event hydraulic capability is lost. Nitrogen back-up to operate the BOP's was originally intended to be an alternative to one of the "power source" system on the BOP closing unit. Refer to API RP53, Second Edition, May 25, 1984, Paragraph 5.A.13.d and e. Since nitrogen obviously cannot operate electric pumps, and is inefficient to run air operated pumps for the time required to be practical, the nitrogen is introduced directly into the hydraulic supply piping to operate the BOP's. NOTE: Nitrogen bottles are charged to between 2,000 psi and 2,500 psi. Each 22.5 cubic foot bottle equals 6.2 gallons however, the normal operating system pressure of 3,000 psi cannot be met. Nitrogen bottles are not under the jurisdiction of ASME. They are covered by D.O.T. (Department of Transportation) 3AA2015. They are rated for 2,015 psi and hydrostatically tested to 3,360 psi. Users should therefore monitor the conditions of the nitrogen

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bottles for evidence of corrosion that may decrease wall thickness and replace them if necessary. Control system manufacturers generally consider nitrogen back-up the least attractive of the alternatives. Nitrogen gas expands rapidly when exposed to the atmosphere (ie: reservoirs require adequate venting). Consequently, the following nitrogen back-up system operation procedure should be followed when using nitrogen to close the BOP's. B. Nitrogen back-up systems used to back-up air supply system for control system remote controls. Since more operators are insisting on, and/or more drilling contractors are complying with API recommendations to move the main hydraulic power unit and control manifold off the drill floor, it is becoming more important that the remote control panel located in the area of the driller is operational even in the event of utilities failure. Many electric remote control systems either operate off the emergency generating system which automatically takes over when the main power system fails, or they have dedicated emergency battery back-up systems like subsea control systems have had for years. In most cases, the neglected area is the lack of provisions for the pneumatic back-up of electro-pneumatic remote control systems. Figure K2-1b Surface BOP Control System

Table K2-1A Hydraulic BOP Control System - Legend for Figure K2-1b 1A Hydraulic BOP Control System - Legend Table K2-1A Hydraulic BOP Control System - Legend NOTE for Table K2-1A: Shown for Air Remote Control Panel operation. System designed to meet API RP 16E must have Electric Remote Control Panels if they are used on offshore rigs.

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1. CUSTOMER AIR SUPPLY: Normal air supply is at 125 psi. Higher air pressure may require an air regulator for No. 88860 air pumps. 2. AIR LUBRICATOR: Located on the air inlet line to the air operated pumps. Use SAE 10 lubricating oil. 3. BYPASS VALVE: To automatic hydro-pneumatic pressure switch. When pressures higher than the normal 3,000 psi are required, open this valve. Keep closed at all other times. 4. AUTOMATIC HYDRO-PNEUMATIC PRESSURE SWITCH: Pressure switch is set at 2,900 psi cut-out when air and electric pumps are used. Otherwise set at 3,000 psi for air pumps alone. Adjustable spring tension control. 5. AIR SHUT-OFF VALVES: Manually operated -- to open or close the air supply to the air operated hydraulic pumpS. 6. AIR OPERATED HYDRAULIC PUMPS: Normal operating air pressure is 125 psi, (For No, 88550 pumps, maximum air pressure is 200 psi and for No. 88660 pumps maximum air pressure is 125 psi.) 7. SUCTION SHUT-OFF VALVE: Manually operated. Keep normally open. One for each air operated hydraulic pump suction line. 8. SUCTION STRAINER: One for each air operated hydraulic pump suction line. Has removable screens. Clean every 30 days. 9. CHECK VALVE: One for each air operated hydraulic pump delivery line. 10. ELECTRIC MOTOR DRIVEN TRIPLEX OR DUPLEX PUMP ASSEMBLY. 11. AUTOMATIC HYDRO-ELECTRIC PRESSURE SWITCH: Pressure switch is set at 3,000 psi cut-out and 250 psi cut-in differential. Adjustable. 12. ELECTRIC MOTOR STARTER (AUTOMATIC): Automatically starts or stops the electric motor driving the triplex or duplex pump. Works in conjunction with the automatic hydro-electric pressure switch and has a manual overriding on-off switch. 13. SUCTION SHUT-OFF VALVE: Manually operated, normally open, Located in the suction line of the triplex pump. 14. SUCTION STRAINER: Located in the suction line of the triplex or duplex pump, 15. CHECK VALVE: Located in the delivery line of the triplex or duplex pump. 16. ACCUMULATOR SHUT-OFF VALVE: Manually operated. Normally in open position when the unit is in operation. Close when testing or skidding rig or when applying pressure over 3,000 psi to open side of ram preventers, OPEN WHEN TEST IS COMPLETED. 17. ACCUMULATORS: Check nitrogen precharge in accumulator system every 30 days, Nitrogen precharge should be 1000 psi +/- 10% CAUTION: Use NITROGEN when adding to precharge. Other gases and air may cause fire and/or explosion, 18. ACCUMULATOR RELIEF VALVE: Valve set to relieve at 3,500 psi. 19. FLUID STRAINER: Located on the inlet side gl the pressure reducing and regulating valves. Clean strainer every 30 days. 20. PRESSURE REDUCING AND REGULATING VALVE: Manually operated. Adjust to the required continuous operating pressure of ram type BOP's. 21. MAIN VALVE HEADER: 5000 psi W.P., 2" all welded.

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22. 4-WAY VALVES: With air cylinder operators for remote operation from the control panels. Keep in standard operating mode (open or close), NEVER IN CENTER POSITION. 23. BYPASS VALVE: With air cylinder operator for remote operation from the control panels. In CLOSE position, it puts regulated pressure on main valve header (21), and in OPEN Position it puts full pump pressure on that header. Keep in CLOSE position unless 3000 psi (or more) is required on ram type BOPs. 24. MANIFOLD RELIEF VALVE: Valve set to relieve at 5,500 psi. 25. HYDRAULIC BLEEDER VALVE: Manually operated-normally closed, NOTE: This valve should be kept OPEN when precharging the accumulator bottles. 26. PANEL-UNIT SELECTOR: Manual 3-way valve. Used to apply pilot air pressure to the air operated pressure reducing and regulating valve, either from the air regulator on the unit or from the air regulator on the remote control panel 27. PRESSURE REDUCING AND REGULATING VALVE -- AIR OPERATED: Reduces the accumulator pressure to the required annular BOP operating pressure. Pressure can be varied tar stripping operations. Maximum recommended operating pressure ut the annular preventer should not be exceeded. 28. ACCUMULATOR PRESSURE GAUGE. 29. MANIFOLD PRESSURE GAUGE. 30. ANNULAR PREVENTER PRESSURE GAUGE. 31. PNEUMATIC PRESSURE TRANSMITTER FOR ACCUMULATOR PRESSURE. 32. PNEUMATIC PRESSURE TRANSMITTER FOR MANIFOLD PRESSURE, 33. PNEUMATIC PRESSURE TRANSMITTER FOR ANNULAR PREVENTER PRESSURE, 34. AIR FILTER: Located on the supply line to the air regulators. 35. AIR REGULATOR FOR PRESSURE REDUCING AND REGULATING VALVE -- AIR OPERATED, 36. AIR REGULATOR FOR PNEUMATIC TRANSMITTER (33) FOR ANNULAR PRESSURE. 37. AIR REGULATOR FOR PNEUMATIC PRESSURE TRANSMITTER (31) FOR ANNULAR PRESSURE. 38. AIR REGULATOR FOR PNEUMATIC PRESSURE TRANSMITTER (32) FOR MANIFOLD PRESSURE. NOTE: Air regulator controls for pneumatic transmitters normally set at 15 psi. Increase or decrease air pressure to calibrate panel gauge to hydraulic pressure gauge on unit. 39. AIR JUNCTION BOX: To connect the air lines on the unit to the air lines coming from the remote control panels through air cable. 40. RIG TEST CHECK VALVE. 41. HYDRAULIC FLUID FILL PORT. 42. INSPECTION PLUG PORT. 43. RIG TEST OUTLET ISOLATOR VALVE: High pressure, manually operated. Close when rig testing -- open when test is complete. 44. RIG TEST RELIEF VALVE: Valve set to relieve at 6500 psi. 45. RIG TEST PRESSURE GAUGE.

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46A. RIG SKID OUTLET and 46B. VALVE HEADER ISOLATOR VALVES: Manually operated. Close valve header isolator valve and open rig skid isolator valve when rig skidding. Open valve header isolator valve and close rig skid isolator valve during normal drilling operations. 47. RIG SKID RELIEF VALVE: Valve set to relieve at 2500 psi. 48. RIG SKID PRESSURE GAUGE. 49. ACCUMULATOR BANK ISOLATOR VALVES: Manually operated, normally open. 50. RIG SKID RETURN. Customer's connection. 51. RIG SKID OUTLET. Customer's connection. 52. ELECTRIC POWER. Customer's connection. 53. RIG TEST OUTLET. Customer's connection. Nitrogen back-up can, implemented successfully, fill this void if the rig stored air system is not designed to handle it. The nitrogen back-up system should include pressure regulation, relief valve protection, and either automatic intervention in the event rig air pressure is interrupted, or be selectively available from the driller's panel and at least one "safe area" remote panel.

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Table K2-2A Preventative Maintanence Schedule

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C. Nitrogen Back-up System Operation WARNING -- FAILURE TO FOLLOW THESE INSTRUCTIONS COULD RESULT IN RUPTURING THE FLUID RESERVOIR 1. Set Annular Regulator to highest regulated pressure. 2. Place Manifold Regulator Bypass Valve in the "HIGH" position. 3. Ensure Nitrogen Bottle Valves are open and place the Nitrogen System Isolator Valve in the "OPEN" position. 4. Close appropriate BOPs for Well Control situation. NOTE: Leave BOPs closed until they can be opened hydraulically, (Refer to following steps). 5. Remove four (4) inch tank inspection plugs at top end of Reservoir. 6. Close Nitrogen Isolator Valve (after emergency). With BOPs still closed, open the Manifold Bleed Valve and slowly bleed Nitrogen back to the Reservoir. 7. If Nitrogen was used to close the Annular, slowly decrease the Annular Regulator setting allowing Nitrogen to bleed back to the Reservoir. 8. Re-establish hydraulic pressure and return the Manifold Regulator Bypass to the "LOW" position. 9. Reset the Annular Regulator to the correct operating pressure. 10. Open the BOPs hydraulically.

B. Subsea Bop Stacks General In addition to the equipment required for surface mounted BOP stacks, subsea control systems use pilot signals and readbacks which are transmitted to and received from subsea control valves in order to effect control of the subsea BOP. Dual (redundant) controls are utilized for increased reliability and hydraulic supply power fluid subsea. Two independent pilot signal transmission and readback means are provided to control the two subsea control pods mounted on the LMRP (lower marine riser package). The two control pods each house the pilot operated control valves for directing power fluid to and readback from the BOP stack functions. The subsea control system types include hydraulic control systems, Electrohydraulic control systems and multiplexed Electro-Hydraulic control systems.

1. System Description And Operation Of The Hydraulic Pilot Control Accumulator Volumetric Capacity Calculation The accumulator volumetric capacity is sized to the requirements of the individual BOP stack to be controlled. Accumulators may be mounted on the subsea BOP stack to reduce response time and/or to serve as a backup supply of power fluid. The stored capacity should be protected from discharge through the supply lines by suitable devices such as pilot operated check valves. Note: The minimum performance and capacities recommendations for subsea BOP well drilling control systems is as listed in API RP16E, latest edition.

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The subsea accumulator capacity calculations should compensate for subsea hydrostatic pressure gradient at the rate of 0.445 psi per foot of true vertical water depth. For example, the hydrostatic head at 500 foot water depth is 222.5 psi. This requires that all pressure values related to accumulator sizing be increased this additional amount. (See Section K1-2E). Response Time The control system for a subsea BOP stack should be capable of closing each ram BOP in 45 seconds or less. Closing response time should not exceed 60 seconds for annular BOP's. Operating response time for choke and kill valves (either open or close) should not exceed the minimum observed ram close response time. Time to unlatch the LMRP should not exceed 45 seconds. Measurement of response time begins at pushing the button or turning the control valve handle to operate the function and ends when the BOP or choke or kill valve is closed effecting a seal, or when the hydraulic connector(s) is fully unlatched. A BOP may be considered closed when the regulated pressure has recovered to its nominal setting and the nominal fluid volume of the function is indicated on the flow meter. If confirmation of seal off is required pressure testing below the BOP or across the valve is necessary. Requirements For Accumulator Valves Multi-bottle accumulator banks should have valving for bank isolation. The isolation valves should have a rated working pressure at least equivalent to the designed working pressure of the system to which they are attached. The valves must be in the open position except when the accumulators are isolated for servicing, testing, or transporting. Accumulator Types Both separator or float type accumulators may be used. Hydraulic Fluid Mixing System The hydraulic fluid reservoir should be a combination of two storage sections: one section containing mixed fluid to be used in the operation of the blowout preventers and the other section containing the concentrated water-soluble hydraulic fluid to be mixed with water to form the mixed hydraulic fluid. This mixing system should be automatically controlled so that when the mixed fluid reservoir level drops to a certain point the mixing system will turn on and water and hydraulic fluid concentrate will be mixed into the mixed fluid reservoir. The mixing system should be designed to mix at a rate equal to the total pump output. In cold climates an extra storage section and triple component mixing system may be needed for glycol additive. Pump Systems The subsea BOP control system should have a minimum of two independent pump systems (i.e. one electric and one pneumatic or two electric powered by two separate electrical power sources). The combination of all pumps should be capable of charging the entire accumulator system from the established minimum working pressure to the maximum rated system pressure in fifteen minutes or less. Isolated accumulators may be provided for the pilot control system which may be supplied by a separate pump. The dedicated pump, if used, can be either air powered or electric powered. Air pumps should be capable of charging the accumulators to the system working pressure with 75 psi minimum air pressure supply. Provision should be made to supply hydraulic fluid to the pilot accumulators from the main accumulator unit should the dedicated pump fail to perform.

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The Central Control Point A subsea hydraulic control system should have a central control point. For a hydraulic system this should be a manifold capable of controlling all the hydraulic functions on the blowout preventer stack. The hydraulic control system will consist of a power section to send hydraulic fluid to subsea equipment and a pilot section to transmit signals subsea via pilot lines. When a valve on the control manifold is operated a signal is sent subsea to a control valve which when opened allows hydraulic fluid from the power fluid section to operate the blowout preventers. Pressure regulators on the surface control manifold send pilot signals to subsea regulators to control the pressure of the hydraulic fluid at the preventers. The surface control system will normally include a flow meter which by a measure of the volume of fluid going to a particular function will indicate if that function is operating properly. Remote Control And Monitoring Panels General The subsea BOP control system should have capability to control all of the BOP stack functions, including pressure regulation and monitoring of all system pressures from at least two separate locations. One location should be in a non-classified (non-hazardous) area (i.e. as defined in API RP 500B). In addition to the driller's panel and main hydraulic control unit at least one additional remote control panel is normally provided for BOP stack and diverter functions. Umbilical Control Hose Bundles, Rigid Conduit And Subsea Accumulators Umbilical control hose bundles are used to provide the main supply of power fluid and pilot signals from the surface hydraulic control manifold to the subsea control pods mounted on the BOP stack. The surface jumper hose bundle is a fixture on the rig that extends from the manifold to the hose reel. The subsea umbilical is run retrieved and stored on the hose reel. The pilot signals are routed to the hose reels through the appropriate length of surface umbilical jumper hose bundle from the hydraulic control manifold to the junction boxes located on the hose reel side plate. The main hydraulic power fluid supply can be carried by a steel pipe run communicating through a swivel fitting on the hose reel through a supply hose in the hose bundle to the subsea control pod. Alternatively, a larger diameter rigid conduit can be included on the riser to supply fluids to the subsea control pod. Hose Reels Hose reels are used to store run and retrieve the umbilical hose bundles. The hose reels are equipped with hose reel manifolds having valves, regulators, and gauges for maintaining control through the subsea umbilical of selected functions during running and retrieving of the pod or LMRP and/or the BOP stack. The hose reel drum is normally equipped with a brake capable of overriding and stalling the motor. The brake should be capable of supporting the weight of the fully deployed subsea umbilical when it is suspended in water. Operation should be slow, smooth, and deliberate so as not to overstress the drive and braking assemblies. Fast operation can build momentums that are difficult to control. The hose reel drum will normally have a mechanical locking device that positions the hose reel manifold and junction box in an accessible position. Two independent hose reels are provided. Each reel should be clearly identified regarding which subsea control pod it services. Standard practice is to color code the reels or the hose reel manifolds one blue and one yellow corresponding to the color of the associated pod.

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Hose Reel Manifold The hose reel manifold provides control of selected functions through the pilot lines when the hydraulic jumper hose to the control manifold has been removed to permit rotation of the hose reel drum. All functions required to land and retrieve the LMRP and/or the BOP stack remain fully active during landing and retrieval. Hose Sheaves Hose wheel or roller sheaves facilitate running and retrieving the subsea umbilical from the hose reel through the moonpool and support the moonpool loop which is deployed to compensate for vessel heave. The sheaves are normally positioned directly over the LMRP mounted control pods (or valve manifolds). They are normally hung off the rig structure, a davit or an extendable arm. Hose sheaves should be mounted to permit three-axis freedom of movement of the umbilical. Wheels or rollers which support a bend in the subsea umbilical should have a minimum are of one hundred seventy degrees of load bearing support and provide a bend radius greater than the minimum bend radius recommended by umbilical manufacturer. Subsea Control Pods / Manifolds There should always be two fully operational and completely redundant control pods/manifolds on the blowout preventer stack. The control "pods" may be retrievable or non-retrievable. Manifolds would be considered as rigidly fixed equipment added to the LMRP and not separable as a unit (i.e. pod). Each control pod/manifold will contain all necessary valves and regulators to operate the LMRP and blowout preventer stack functions. Should a problem occur within one pod/manifold, the control can be switched to the other pod/manifold. It is common for both pods/manifolds to have the pilots function in parallel so that if a switch is made from one pod to the other (by switching the main hydraulic supply from one to the other), the previously selected functions remain as originally selected. The hoses from each control pod should be connected to a shuttle valve that is connected to the function to be operated. A shuttle valve is a slide valve with two inlets and one outlet which prevents movement of the hydraulic fluid between the two redundant control pods.

2. System Description And Operation -- Electrohydraulic And Multiplex Control Systems For Subsea General Electrohydraulic and multiplex control systems are used in deep water where response times of hydraulic signals would be too lengthy. Electrical command signals transmitted over lengthy subsea umbilical cables have nearly instantaneous response times. Electrical command signals operate subsea solenoid valves which, in turn, provide hydraulic pilot signals directly to operate the pod valves that direct power fluid to the subsea functions (i.e. BOP's, connectors, choke and kill valves). Electrohydraulic systems have conductor wires in the subsea umbilical cable dedicated to each function. Multiplex (MUX) systems serialize and code the command signals which are then sent subsea via shared conductors (normally four, for redundancy) in the umbilical cable. Subsea data are electrically transmitted to the surface.

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Electrical Control Unit An electrical control unit may be the central control point (corresponding to the hydraulic control manifold of a hydraulic control system). This unit typically does not have individual function control buttons for operating. Alternatively, this unit may be eliminated and each control panel may communicate directly and independently with each subsea control pod. The electrical control unit is normally supplied electrical power from an uninterruptible power supply. A bank of batteries are typically used as a back-up to the main electrical supply. If the main power is lost, the battery bank will supply "uninterrupted" power for approximately two hours. All functions are operable from and monitored from a remote control panel located on the rig floor interfacing with the central control unit. Another electrical panel in the toolpusher's office has the same or limited functions as found on the driller's panel. The electrical control unit should maintain function status memory in The event of power interruption. Upon restoration of power, the system should display the status of all functions as they were prior to the loss of power. Remote Control And Monitoring Panels -SUBSEA UMBILICAL CABLES AND CONNECTORS The subsea umbilical cable is run, retrieved and stored on a cable reel. The subsea umbilical electrical cable supplies power, communications and control of the subsea control pods. The electrical conductors, electrical insulation/jacketing, and end terminations must be carefully handled so as not to stretch, kink, puncture or crush any of these elements causing failure and rig shutdown. A wheel or roller sheave, with appropriate bend radius to suit the umbilical being used, is positioned directly over the lower marine riser package (LMRP) mounted control pods (or valve package). It is normally hung off the rig structure, a davit or an extendable arm. CABLE REELS The cable reels are designed to run and retrieve the cable without damaging or kinking. Certain functions required to run, !and and retrieve the LMRP and/or the stack should remain fully active during running, landing and retrieval. This is typically accomplished by use of an electrical slip ring assembly at the reel shaft so that these certain functions remain "live" when reeling cable out or in. A mechanical locking mechanism should be used to lock the drum in position when the reel is to remain stationary. The cable reel may have payout and take up controls located on the reel or at a remote location. Operation should be slow, smooth and deliberate so as to not overstress drive and brake assemblies. Fast operation can build momentum that is difficult to control. Umbilical Hoses And Rigid Conduits (As Required) Subsea Control Pods/Manifolds and Electrical Equipment The control pod serves as the subsea control valve manifold and contains all the pressure regulators and valves required to operate the subsea LMRP/BOP functions. Two control pods/manifolds should always be fully operational to provide backup control of all subsea functions. Should a problem occur within one pod/manifold, the control can be switched to the other pod/manifold. It is common for both pods/manifolds to have the pilots function in parallel so that if a switch is made from one pod to the other (by switching the main hydraulic supply from one to the other), the previously selected functions remain as originally selected. The surface electrical control point directs function commands through the umbilical cables to operate the pressure regulators, valves and straight through functions installed in the pod.

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A cable strain relief/radius guard should be employed at the cable/pod interface to prevent kinking or cutting the umbilical. The subsea pressure regulators in each pod/manifold should provide regulated pressures to ensure proper operation of the designated function. Manufacturers of equipment to be functioned (i.e. BOP's, connectors and choke/kill valves) will provide operation pressure data. The valves and regulators should be sized to supply the volume required to operate each function within the specified response time (per company policy). The pods may or may not be retrieved independently of the LMRP. A retrievable control pod assembly would be comprised of the retrievable control pod and at least two pod receivers (single receiver assembly or multiple stab type). One receiver would be mounted on the LMRP to provide the landing and seal interface between the pod and LMRP functions (LMRP receiver). The second receiver would be mounted on the BOP stack to provide the landing and seal interface between the pod or LMRP and the BOP stack functions (BOP stack receiver). Proper alignment between the control pod and receivers should be maintained to ensure fluid seal integrity. Usually, one elastomeric/steel seal assembly is dedicated to each function interface. A retrievable control pod is equipped with a locking mechanism to lock the control pod to the LMRP or receiver. If conditions dictate, the control pod locking mechanism may be capable of being unlocked by means of a mechanical override. Non-retrievable control pods/manifolds are usually fixed to the LMRP and may require only the BOP stack receiver to provide the landing and fluid seal interface for the control pod to the BOP stack. Corrosion in the subsea control equipment should be minimized by implementing measures such as anticorrosive coating/lubricant selection, corrosion resistant material selection for replacement parts, modifications utilizing anticorrosive materials, cathodic protection, etc. SUBSEA ELECTRICAL EQUIPMENT All electrical connections which may be exposed to seawater should be protected from over current to prevent overloading the subsea electrical supply system in the event of water intrusion into the connection. Auxiliary subsea electrical equipment which is not directly related to the BOP control system should be connected in such a manner to avoid disabling the BOP control system in the event of a failure in the auxiliary equipment. Subsea electrical equipment should be galvanically isolated from any surface exposed to seawater.

3. Maintenance Procedures Referenced From Service Interval Chart A. Hydraulic Power Unit 1. General Inspection Inspect The hydraulic power unit daily for leaks at The following points, and correct if necessary: a. Piping b. Reservoirs c. Accumulators d. Air supply manifold e. Electric pumps (1) crankcase (2) packing

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f. Air pumps (1) Power end (2) Packing 2. Panel Valves Whenever rig operations permit, check the panel valves for leaks with the following procedure: a. Turn off all pumps. b. Close the isolation valves on the accumulators. c. Observe the panel gauges. A slow decrease in pressure indicates a leak. Troubleshoot the hydraulic system and repair as necessary. Caution: Do not perform the following tests during critical drilling operations. Loss of pressure in the pilot lines may cause stack components or the control pod selector to change position. 3. Fluid Reservoirs (lubricant, glycol, and mixed fluid) a. Inspect the fluid levels of the fluid reservoirs daily, and add fluid if necessary. b. Inspect the mixed fluid reservoir every 1 to 2 months for bacterial buildup, scum, and sludge with the following procedure: (1) Check for an unpleasant odor, which indicates the presence of bacteria. (2) Check for scum floating on top of the fluid and adhering to the reservoir walls. c. Remove the bacterial buildup, scum, and sludge with the following procedure: (1) Add an environmentally safe biocide to a fresh batch of reservoir fluid to kill the bacteria. (2) Charge the accumulators to 3000 psi. (3) Wait at least 30 minutes for the bacteria to die. (4) Drain the reservoir and the accumulators. (5) Flush the system with clean, fresh water. (6) Fill the reservoir with the correct mixture of fresh water, soluble lubricant, and ethylene glycol. (7) Charge the accumulators to 3000 psi. (8) Open the purge valve or disconnect the tubing, and flush the fluid from the pilot lines at the subsea control valve until fresh fluid appears. 4. Pumps a. Air Pumps (1) Visually inspect air pumps daily for leaks, and correct if necessary. (2) Inspect air pumps weekly with the following procedure: (a) Turn off electric pumps. (b) Turn on air pumps.

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(c) Relieve accumulator pressure until air pumps start to operate (approximately 2750 psi). (d) Observe and listen to pump operation. If the sound of the pump stroke is uneven or if the pump rod moves faster on one stroke, the pump could be leaking on either the forward or reverse stroke. See the Maintenance Procedures for repair instructions. (e) The pumps should stop operation at 3000 psi. If the pumps continue to operate slowly after the pressure reaches 3000 psi, the pump governor or bypass valve is defective. See the Maintenance Procedures for repair instructions. b. Electric Pumps (1) Visually inspect electric pumps daily for leaks, and correct if necessary. (2) Inspect electric pumps weekly with the following procedure: (a) Relieve accumulator pressure until electric pumps start to operate (approximately 2750 psi). (b) Observe and listen to pump operation. (c) Pumps should start smoothly, and pressure should start to build up immediately. (d) Visually inspect the rod packing for leaks. (e) Listen to and feel the suction and discharge line relief valves for discharges caused by leaks. (f) If a leak is detected, see the Maintenance Procedures for repair instructions. (3) Inspect the oil level in the electric pumps weekly, and add oil if necessary. (4) Change the oil in the electric pumps every 6 months. Use nondetergent SAE 10 or SAE 20 motor oil for temperatures below 40 degrees F and SAE 30 or SAE 40 for temperatures above 40 degrees F. (5) Inspect the tension of the belts weekly. Depress the belt with thumb pressure; movement should be no more than 1/2". 5. Air Lubricators a. Inspect the oil level of the air lubricators weekly, and add oil if necessary. b. Use nondetergent SAE 10 motor oil to fill air lubricators. 6. Air Regulators a. Clean air regulator strainer screens monthly with detergent and water. b. Test air regulators monthly by verifying that the set pressure is maintained during air flows. c. Inspect air regulator settings every six months by reading the discharge pressure gauges. 7. Accumulators Inspect accumulator precharge every six months, at each rig move, or when a problem is suspected, whichever occurs first. Note: Install a repair kit in each accumulator every three years.

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A. Use the following procedure on each accumulator to determine if any of the accumulators have defective valve assemblies that are not closing completely or are leaking nitrogen. (1) Turn off all pumps. (2) Close the isolation valves on all accumulators except the one to be tested. Note: It may be necessary to drain fluid from the reservoir before relieving accumulator pressure. (3) Relieve the pressure in the accumulator being tested to zero psi with the bleeder valve on the accumulator return line, and listen for a bubbling sound. (4) If no bubbling sound is heard in the reservoir after the pressure is relieved, the accumulator valve assembly is working correctly. Repeat steps (1) through (4) for each accumulator and proceed to step 7b. (5) If a bubbling sound is heard in the reservoir after the pressure is relieved, the accumulator valve assembly is not closing completely or is leaking nitrogen. Repair the valve assembly accord ing to the following instructions: (a) Relieve the nitrogen precharge pressure in the accumulator with the nitrogen needle valve on the valve assembly. (b) Remove the valve assembly, and repair it. See the Maintenance Procedures for repair instructions. (c) Precharge the accumulator. See the Maintenance Procedures for precharge instruc tions. (6) Close the bleeder valve on the accumulator return line. (7) Repeat step 7A for each accumulator before continuing to step 7B. B. Determine if any of the accumulators do not have sufficient precharge pressure with the following procedure: Note: This procedure will not determine if any of the accumulators have submerged floats. See step 7c to determine if an accumulator has a submerged float. (1) Ensure that all pumps are turned off. (2) Ensure that The bleeder valve on the accumulator return line is closed. (3) Ensure that the accumulator pressure gauge registers zero psi. (4) Turn on the pumps. Wait 4 to 5 seconds for electric pumps, slightly longer (until the pump reaches a steady level of operation) for air pumps. (5) Observe the accumulator pressure gauge. (a) If the accumulator pressure gauge registers from 900 psi to 1100 psi, all accumulators have sufficient precharge pressure. (b) If the accumulator pressure gauge registers below 900 psi, one or more accumulators has insufficient precharge pressure. Continue to step 7C. C Perform the following tests on each accumulator to determine which accumulator(s) has insufficient precharge pressure or a submerged float: (1) Close the isolation valves on all accumulators except the one to be tested.

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(2) Close the bleeder valve on the accumulator return line. (3) Ensure that the accumulator pressure gauge registers zero psi. (4) Turn on the pumps. Wait 4 to 5 seconds for electric pumps, slightly longer (until the pump reaches a steady level of operation) for air pumps. (5) Observe the accumulator pressure gauge. (a) If the accumulator pressure gauge registers from 900 to 1100 psi, the accumulator has sufficient precharge pressure. (b) If the accumulator pressure gauge registers below 900 psi, the accumulator does not have sufficient precharge pressure. See the Maintenance Procedures for precharge instructions. (c) If the accumulator pressure gauge registers a steady pressure increase from zero psi to 3000 psi, the float is submerged. Note: As an option, to verify the accumulator precharge pressure, install a test gauge in the nitrogen needle valve on the accumulator valve assembly. (6) Repeat step 7C for each accumulator. B. Hose Reels 1. Inspect the oil level of the air lubricator and chain lubricator weekly, and add oil if necessary. 2. Use nondetergent SAE 10 motor oil to fill the lubricators. C. Lower Riser Assembly - Control Pods Inspect each subsea control pod on the lower riser assembly, using the following procedure, every time the pods are retrieved. 1. Remove the protection covers from the pods. 2. Wash all valves, stingers, and piping thoroughly with fresh water. D. BOP Stack 1. Wash The pod baseplates with fresh water to remove all mud and foreign objects. 2. Inspect the female with the following procedure: a. Inspect the female for internal scoring and freedom of movement. If scoring is found, use an emery cloth to remove protruding metal. b. Lubricate the female with clean, lightweight, waterproof grease. c. Cover the female when not in use.

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C. Remote Operated Choke Controls Purpose While it is possible to control a well kick using a manual adjustable choke at the choke manifold, this method is not convenient because the manifold is usually some distance from the drilling floor. Also the distance involved and the noise associated with drilling operations may make communication between the driller and the choke operator difficult or impossible thus creating a potentially dangerous situation. Therefore, most choke manifolds are equipped with at least one remotely operated drilling choke which requires a choke control system located on the drilling floor. The purpose of this section is to describe some of the design considerations in a choke control system, identify and describe the functions of the major components, and provide some installation guidelines for the system.

Design Considerations The functional requirements for drilling choke control systems are specified in API Spec 16C. It is the responsibility of the control console manufacturer to ensure that his equipment meets these requirements in addition to the specific performance requirements also listed in Spec. 16C. The interested reader should consult Spec. 16C for more detail.

Major Control System Components The major components in a remote drilling choke control system are as follows: Drilling Choke and Actuator. A drilling choke is essentially a pressure reducing valve of very robust design. Its function in the control system is to provide for the control of drilling system pressures while circulating out a kick. The choke actuator is usually the hydraulic piston type which moves the choke open or closed by the application of hydraulic pressure to one side or the other of the piston. Choke Position Transmitter. During choking operations, it is necessary to know what position the choke is in, and to have this information displayed at the console. The position transmitter is usually attached to the rear of the actuator and is driven by a rod which extends through the back of the actuator. The transmitter produces a signal, usually pneumatic, hydraulic, or electric, which is proportional to the choke position. This signal is sent to the position indicator display on the console face. Choke Control Console. The console provides the choke operator with the controls needed to change the choke position in addition to the various displays which provide the operator with the information needed for proper kick control. The console also contains the hydraulic power system which drives the choke actuator. The major pieces of equipment contained in the console and their function is as follows: Hydraulic Power System. The hydraulic power required for the choke is usually supplied by an air driven hydraulic pump. In addition to the pump the system usually contains a hydraulic oil reservoir and may contain an accumulator. When present, an accumulator provides for smoother operation of the choke and also provides a power reserve usually sufficient to operate the choke through one or more complete cycles should there be a failure of the rig air supply. The hydraulic system also contains an emergency hand pump which can be used to drive the choke should rig air fail. The hydraulic system pressure is monitored with a pressure gauge in the face of the console.

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Choke Operation System. The choke position is usually controlled with a hydraulic spool valve which will deliver oil to either the open or closed side of the choke actuator. The valve is generally a spring centered type which when released will automatically return to the center position which closes both hydraulic lines leading to the actuator. This action effectively locks the choke in its last position (if there are no hydraulic oil leaks). The choke position at any time is indicated by a choke position indicator located in the face of the console. The choke operation system will frequently contain a choke speed control valve. This is usually a small needle valve located upstream of the choke control valve. By partially closing this valve the speed of opening or closing the choke can be reduced thus providing for precise positioning of the choke. Standpipe and Casing Pressure Gauges. The pressure condition in both The standpipe and casing is monitored by large diameter pressure gauges mounted in the face of console. These gauges are usually calibrated in 25 psi, or smaller, increments. The gauges are connected by flexible high pressure hose to their respective monitoring points. The hoses are usually oil filled to prevent entry of drilling mud. This is accomplished through the use of isolators at the standpipe and manifold pressure connection points. These isolators contain either a flexible diaphragm or floating piston which allows pressure to be transmitted into the hose. In higher pressure systems (greater than 10,000 psi) the piston type isolator will provide a 4:1 pressure reduction ratio in order to allow the use of lower working pressure hoses. The gauge faces are calibrated to actual system pressure, but have a working pressure four times less than the maximum gauge reading. An alternative method for measuring and displaying these pressures is through the use of low pressure pneumatic pressure transducers. These transducers are located at the standpipe and manifold pressure monitoring points and are supplied with low pressure air from the console. The design is such that the signal returned through the separate signal line is proportional to the mud pressure being monitored. This signal pressure will generally not exceed 30 psi. The console gauges will display actual system working pressure, but will in fact be low pressure pneumatic gauges. Pump Stroke Counter. The console also contains a pump stroke counter. This counter takes its input signal from the limit switches located at the mud pumps. The counter will accumulate total strokes and the count totalizer may be reset to zero when needed. In addition to the stroke totalizer the unit will also contain a stroke rate indicator which reads in strokes per minute. The stroke counter unit will generally allow for switching from one pump to another if that is necessary. The stroke counter unit may be powered externally, but is most usually battery powered with lithium batteries. These batteries will generally provide a life of up to five years. The unit may be constructed to meet explosion proof requirements, but many are built to be intrinsically safe which leads to a lighter weight unit.

Installation Guidelines The following practice is recommended for the installation of a drilling choke control console and the other control system components in a typical drilling rig. A location for the console should be selected so that it is near enough to the driller so that easy spoken communication between the driller and the console operator is possible. This consideration is critical to the safety of the operation when kick control is required. The console should be securely attached to the floor. This attachment should be permanent if the control system is owned by the rig owner. If the control console and drilling choke is rental equipment, the attachment means is necessarily temporary, but the attachment must be sufficient to prevent the console from moving as a result of rig vibration. Should the console move around, the hydraulic and/or other lines connected to the console may be

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damaged. The air supply line, the hydraulic power lines from the choke actuator, the standpipe and easing pressure lines, the choke position transmitter lines, and the pump stroke counter lines need to be routed so that they do not become kinked or otherwise damaged during the normal course of drilling operations. Any excess line should be carefully rolled up and stored near the console, but in a location where it will not interfere with operations or become damaged. Care needs to be taken to ensure that all lines to the console are connected to the proper port on the console. For example the casing pressure line should be connected at the choke manifold pressure transmitter and also to the console pea which leads to the casing pressure gauge on the face of the console. The design of the console may be such that the various hydraulic and pressure lines have different size connectors so that they can be connected to only one port on the console, but this may not be the case so care must be exercised. The limit switches for the pump stroke counter must be installed on the frames of the mud pumps in such a way that they are tripped by the pump plunger during each stroke of the pump. If the control system is rented, the limit switches are usually supplied with a "C" clamp to facilitate attachment to the mud pump frame. After all the lines are properly routed and attached, the oil reservoir should be checked to ensure that it is filled to the proper level. The hydraulic pump should then be started by opening the air supply line. As soon as hydraulic pressure in the system builds up to the point where the pump shuts down, the choke control valve (or valves) should be cycled in order to move the choke actuator from open to closed and back several times to facilitate removal of any air from the hydraulic system. It may be necessary to add oil to the choke actuator during this operation.

D. Diverter Control Systems Diverters Diverter Systems are used where shallow gas is anticipated during the initial drilling of the well prior to reaching the stable formation where the casing is cemented. Once this "shoe" is established, the B.O.P. stack can be installed and the well closed in should a "kick" be encountered during further drilling. Prior to cementing and establishment of the "shoe", gas encountered during The initial drilling must be diverted. Normally two diverter lines are employed at right angles to the prevailing wind. Diverting is accomplished by opening one or both of the diverter lines, then closing the annulus space, (flowline access) with the "packer" element. This directs gas away from the rotary and mud pits, through the diverter vent lines and harmlessly away from the rig. The shallow pocket of gas will normally loose its pressure and bridge closed in a matter of minutes. The critical issues when shallow gas is encountered and as soon as the "kick" is detected is to respond quickly and correctly. Quickly because in the shallow well there is little hydrostatic head pressure and little distance for the gas to travel before a blowout. Correctly because closing in the well could cause a blowout to occur around the conductor allowing gas to migrate up the outside of the conductor and to the drill floor. To prevent closing in the well, at least one vent line must be open prior to closing the diverter packer (flowline access to the annulus). The most common diverter systems used on land, or fixed offshore rigs consist of an annular type blowout preventer with a top mounted bell nipple which has an outlet for the flowline to the shale shaker/mud pits and one or two diverter lines to vent the diverted gas overboard. When the diverter packer closes on the drill pipe it closes the annulus space shutting off the flow of drilling mud through the flowline. Even in simple systems like this, it is prudent to have the diverter control system designed in a manner to prevent closing the diverter packer until at least one diverter vent is open. It is even more imperative in the more complex platform diverter systems and subsea diverter systems that critical functions occur automatically and that safeguards are employed to prevent

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erroneous operation which could result in injury, damage to the rig and damage to the environment. Generally accepted diverter control system recommended practices are listed in API RP 16E.5.

General Information The master hydraulic diverter control manifold or panel should be treated in the same manner as the B.O.P. hydraulic control unit as stated in API RP16E.2.6.7. It should be located in a safe (protected) area away from the drill floor but accessible to rig personnel in case the drill floor has to be evacuated in an emergency. This means that the diverter functions should be capable of remote control from the driller's position. The automatic sequencing circuitry and safety interlock circuitry should always be established in the master hydraulic diverter control manifold. If these circuits were to be established in the remote control panel, they could be inaccessible or rendered inoperative by damage if the drill floor was evacuated because of gas, fire or falling debris.

Diverter Types Diverter Types Brief Description: Hydril MSP NORMAL AUTO SEQUENCE Placing the diverter packer control valve in the close position automatically opens the pre-selected overboard valve. NORMAL SAFETY INTERLOCK -- Hydraulic pressure to close the diverter packer is prevented until at least one overboard control valve has been shifted to open. Vetco KFL NORMAL AUTO SEQUENCE -- Placing the diverter packer control valve in the close position automatically opens the pre-selected overboard valve and locks The insert packer. NORMAL SAFETY INTERLOCK -- Hydraulic pressure to close the diverter packer is prevented until at least one overboard control valve has been shifted to open and the insert packer control valve has been shifted to lock. Hydril FSP NORMAL AUTO SEQUENCE Not required in the control system. NORMAL SAFETY INTERLOCK -- Not required in the control system. NOTE: The FSP diverter is designed so that when the piston moves up to close the diverter packer closing the flow line out of the top mounted bell nipple, it clears the bottom outlet to the vent line which is blocked when the piston is down (diverter packer open). The vent line cannot be closed. There is a selector deflector to select port or starboard. Vetco KFDJ NORMAL AUTO SEQUENCE Placing the diverter packer control valve in the close position automatically shifts The pre-selected overboard control valve to the open position, and ensures The inflowing valves shifts to the position indicated if they are rot already in that position: Insert Packer

Lock

Diverter Lock Dogs

Lock

Flowline Seals

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Overshot Packer

Pressurized

Flowline / shaker Valve

Close

Trip Tank Valve

Close (if applicable)

Fill-Up Valve

Close (if applicable)

NORMAL SAFETY INTERLOCKS -- Hydraulic pressure to close the diverter packer is prevented until the following pilot signals are sensed: 1. At least one overboard valve has been actuated to open. 2. The insert packer has been actuated to lock. 3. Pressure is applied to both the flowline and overshot packer seals. TIME DELAY CIRCUITS second delay:

The following circuits should be designed so they can be overridden after a 10 to 60

1. Overboard valve can be shifted to port open / starboard close or starboard open / port close. 2. Flowline valve can be opened or closed at the operators discretion. 3. Trip tank valve can be opened or closed at the operators discretion. 4. Riser fill valve can be opened or closed at the operators discretion. NOTE: If overriding these functions is desired by the operator with the overboard valves closed, the diverter-test valve can be placed in the test position interrupting the auto sequence. This is normally required for low pressure testing of the diverter lines.

Additional Features Common To Platform Diverters: 1. Safety circuit to prevent venting the flowline seals or overshot packer when the diverter packer is closed. 2. Optional divert/strip function. 3. Divert/test mode function allows closing all diverter functions for low pressure testing. 4. Low deadband failsafe pneumatic motor driven remote controlled regulators. Normally only the diverter packer pressure regulator is remotely operated. All regulators can be remotely operated. Remotely operated regulators should be sensitive to down stream pressure changes within plus/minus 150 psi. 5. KFDJ and KFDS diverter control systems should include a "Diverter Ready" indicator to indicate when the safety interlock circuits have been preset to their proper position. 6. Hydraulic safety logic should be used to reduce the dependence on pneumatic circuitry. 7. Pneumatic circuits should be minimized for safety. Air supply for a minimum of two times the volume to sequence the diverter controls should be check, valved in and stored in the panel for emergency operation. 8. Low air supply pressure and low hydraulic supply pressure warning lights should be included in diverter control systems with electric remote control. Function position status indication should also be included. Vetco KFDS The normal auto sequence, safety interlocks, delay circuits and additional features described in the KFDJ diverter brief descriptions are generally applicable to the KFDS diverter controls for subsea systems. KFDS systems usually have more hydraulic functions than the KFDJ and will include a slip joint packer which may be energized by air or hydraulic pressure.

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KFDS diverter control systems are normally self-contained units. They include dedicated pumps, reservoirs and accumulators.

Diverter Remote Controls The master hydraulic diverter control manifold or control panel should be located off the drill floor in an area relatively safe from gas, fire and falling debris and should be accessible to the drilling crew for operation in an emergency. This means that the diverter control functions should be capable of remote control from the driller's location. On offshore drilling rigs, the control panel at the driller's location should as a minimum include the following features: 1. Control and status position indication of all diverter control functions. 2. Control of the diverter packer regulator to increase/decrease function. 3. Low hydraulic supply and low air supply to the master panel alarms. If the diverter control system is a "selfcontained" unit, low reservoir level of the diverter control fluid reservoir should be included. 4. Electric pump running light. (Self-contained units with electric pump.) 5. "On battery power" indicator (units so equipped with emergency battery back-up). 6. Nitrogen back-up initiated (if so equipped). 7. Indication of all system pressures. 8. Function controls oriented and represented in a graphic display of the diverter system. The driller's remote control panel should be designed in accordance with the recommendations of API RP16E.2.6 (see API RP16E.5.6). Driller's panels should be suitable for installation in explosive gas environments. Diverter control panels can frequently be incorporated with the B.O.P. control system panels to conserve space. Diverter functions should be electrically independent of the B.O.P. control functions.

Diverter Back-up Systems The response time recommendation to sequence the diverter system and close the diverter packer within 30 seconds for diverter packers up to 20 inch nominal bore size and 45 seconds for diverter packers over 20 inch nominal bore size (Ref. API RP16E.5.1) can be met with a nitrogen back-up system or dedicated hydraulic accumulators (Ref. API RP16E.5.3.2). The back-up system can have manual intervention as long as it is selectable on demand (remote control from the driller's panel) or otherwise, automatic. Automatic hydraulic back-up systems sense the loss of a hydraulic pilot signal and automatically open the back-up accumulator supply into the hydraulic control manifold of the diverter control system. Automatic nitrogen back-up systems likewise sense the loss of hydraulic pilot pressure and automatically inject stored nitrogen pressure into the manifold circuit for sequencing the diverter functions and closing the diverter packer. Either system can be "unit" mounted or "separate skid" mounted. Hydraulic back-up systems, whether unit mounted or separate skid mounted, must be designed with consideration of the reservoir size for the additional fluid volume of the back-up accumulators.

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Pump up time for initially charging the back-up system accumulators need not be considered when sizing pump systems in accordance with API RP16E.5.31. The back-up accumulators will remain charged after the initial charging unless operated in an emergency according to their design intent.

E. Control Systems Typical Capacity And Performance Data / Calculations Blowout prevention equipment such as annular preventers and ram preventers are normally opened or closed by fluid pressure. The fluid to accomplish this is stored in the accumulator. The pressure used must meet the capacity and operator pressure requirements of the particular blowout preventer in order for it to perform as designed. The performance characteristics of blowout preventers are discussed in paragraph K1.8. The capacity requirements, operator chamber design working pressure, and opening and closing ratios of most major manufacturers' blowout prevention equipment are shown in the Quick Reference Tables K1.8.1 through K1.8.5.

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Table K1-8-1 MK Koomey Annular BOPs - Operating Characteristics

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Table K1-8-2 Hydril Annular BOPs - Operating Characteristics

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Table K1-8-3 Cameron Annular BOPs - Operating Characteristics

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Table K1-8-4 Shaffer Annular BOPs - Operating Characteristics

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Table K1-8-5 Hydril Ram BOPs - Operating Characteristics

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Table K1-8-6 MH Koomey Ram BOPs - Operating Characteristics

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Table K1-8-7 Cameron Ram BOPs - Operating Characteristics

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Table K1-8-8 Shaffer Ram BOPs - Operating Characteristics

Closing Time Of Preventers Fast response capability is a key factor in blowout prevention and overall rig safety. API recommendations specify that ram BOPs for surface equipment should be capable of closing within 30 seconds of actuation regardless of size. Closing time for annular preventers smaller than 18-3/4 inch nominal bore should not exceed 30 seconds from actuation and annular preventers 18-3/4 inches and over should not exceed 45 seconds. When the BOPs are located on the ocean floor (subsea systems), an additional 15 seconds is generally acceptable to allow for pilot signals from the surface which actuate the control valves mounted in control pods which are located on the lower marine riser package. In order to have the fluid capacity at the pressure required to operate the BOPs within the specified time limit, accumulator bottles are used to store this energy. Accumulator bottles are pressure vessels pre-charged with nitrogen gas to store the operating fluid under pressure. The basic principle of operation of the accumulator is that when the volume of gas is reduced by pumping liquid into the bottle, its pressure increases. Boyle's Law defines this relationship between the volume of gas and its pressure as given below;

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"The absolute pressure of a confined body of gas varies inversely to its volume provided its temperature remains constant". This means that if a volume of gas is compressed to 1/3 of its original size, the pressure will be 3 times greater than before compression at,er it has been allowed to cool to its original temperature (compression generates heat). Boyle's Law can be expressed by the following equation: P1 x V1 = P2 x V2 Where: P1 = initial pressure (nitrogen pre-charge) V1 = initial gas volume electro-pneumatic

P2 = pressure at a later time

V2 = gas volume at a later time There are two important considerations to Boyle's Law that have not been taken into account. One is absolute pressure and the other is temperature effects.

Absolute Pressure A pressure gauge is calibrated to read zero psi when it is unconnected regardless of atmospheric pressure, elevation, or barometric pressure. This is written as psig, pounds per square inch - gauge. At sea level, the weight of air produces an atmospheric pressure of 14.7 psi. if pressure is to be stated in absolute terms for solving problems using Boyle's Law, atmosphere pressure must be added to The gauge reading to obtain the absolute pressure level and this should be written psia, pounds per square inch - absolute.

Temperature Nitrogen gas is used to pre-charge accumulators primarily because it is an inert gas. This means it does not easily take part in chemical reactions. Therefore, nitrogen has the advantage of not being combustible under pressure in conjunction with petroleum based hydraulic fluid. While there are other inert gases that could be used, nitrogen gas is relatively cheap and readily available in many parts of the world. If compression and expansion of the nitrogen gas is allowed to occur slowly providing sufficient time for heat to be dissipated, this condition is referred to as isothermal and no allowance for the relationship between gas and temperature is entertained. The safety factors included in standard calculations normally are sufficient to compensate for absolute pressure and temperature effects. These effects are therefore not considered in order to simplify the calculations for the rig personnel.

Application Of Boyle's Law For Calculating Stored Usable Fluid In Surface Accumulator Bottles Since accumulator bottles are normally pre-charged to 1000 psi, that becomes the initial pressure (P1). Let us say that the accumulator bottle has 10 gallons of capacity (V1), the minimum pressure required to operate the BOP function is 1200 psi, and the maximum pressure that will be placed in the bottle is 3000 psi. It is important to note that the "stored usable fluid" contained in the accumulator bottle is that amount pushed out of the bottle by the expanding nitrogen gas bubble as pressure falls from 3000 psi to 1200 psi. Any fluid remaining in the bottle at that time is not considered "usable". We can calculate (under isothermal conditions) that amount not considered usable by solving the Boyle's Law equation for V2 as given below:

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V2 = P1 x V1/P2 = 1000 x 10 / 1200 = 8.3 gallons nitrogen Where: V2 = gallons of nitrogen at minimum system pressure P1 = initial pressure (nitrogen pre-charge), psia V1 = initial gas volume in gallons P2 = minimum system pressure, psia So as the pressure in the bottle rises from 1000 psi (pre-charge pressure) to 1200 psi (minimum system pressure), the nitrogen gas is compressed from 10 gallons to 8.3 gallons or 1.7 gallons of liquid was forced into the bottle causing the pressure rise. This 1.7 gallons is not considered stored usable fluid. The total volume of liquid in the bottle at the maximum system pressure can also be calculated using Boyle's Law as given below: V3 = P1 x V1 /P3 = 1000 x 10 / 3000 = 3.3 gallons nitrogen Where: V3 = gallons of nitrogen at maximum system pressure P1 = initial pressure (nitrogen pre-charge) V1 = initial gas volume in gallons P3 = maximum system pressure in psi Now we know that as the pressure in the bottle rises from 1000 psi (pre-charge pressure) to 3000 psi (maximum system pressure), the nitrogen gas is compressed from 10 gallons to 3.3 gallons or 6.7 gallons of liquid is now in the bottle. Remembering that the 1.7 gallons is not usable, we can determine the stored usable fluid in the bottle by the following equation: Stored Usable Fluid = (6.7 - 1.7) gal = 5.0 gallons. Said another way, as the pressure in the 10 gallon accumulator falls from 3000 psi to 1200 psi, 5.0 gallons of liquid are forced out of the bottle and into the system. NOTE: Accumulator bottles come in various sizes. Some manufacturers state the size in regard to their gas volume while others state the physical inside volumetric capacity as the size. It is sometimes necessary to subtract the bladder or float displacement from the physical inside volumetric capacity in order to arrive at the true gas volume or stored usable fluid volume. For example, an 11 gallon accumulator bottle becomes 10 gallon capacity when subtracting approximately 1 gallon for bladder displacement.

Sizing Accumulator System Capacity For Surface Blowout Preventers Referring to the tables in K1.8, above, let us say that we have a surface BOP stack that requires the following closing volumes of fluid: Annular gallons to close

= 17.98 gallons

3 Rams @ 5.8 gal. ea. to close = 17.40 gallons Total galonage required: 35.38 gallons Plus 50% Safety Factor

17.69 gallons

Stored Usable Fluid Required = 53.07 gallons

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Having previously calculated the stored usable fluid in a 10 gallon accumulator bottle, we can calculate the number of bottles required according to the following equation; Accumulator = (Stored Usable Fluid Required) / (Stored Usable Fluid per Bottle) = (53.07 gallons )/(5.0 gallons/bottle) = 10.6 or 11 bottles Government regulations of various countries and some oil companies have specific requirements regarding accumulator capacity. The preceding references and calculations are only intended to explain the considerations and fundamentals of calculating accumulator capacity using Boyle's Law which is a widely accepted method. Maximum charging pressure, pre-charge pressure, and minimum working pressure of the accumulator system may vary on certain "high pressure", (10,000 psi and above) BOP systems. These pressures may be changed as a result of requirements to close ram type BOPs against full well bore pressure. Control system manufacturers may recommend alternative accumulator capacity calculations in order to optimize performance of the system while minimizing cost. IADC recommends contacting a reputable control system manufacturer when proper accumulator capacities are in question.

Application Of Boyle's Law For Calculating Stored Usable Fluid In Subsea Accumulator Bottles BOP control systems used to control blowout preventers which are connected to the wellhead at the ocean floor sometimes have accumulator bottles mounted on the BOP stack as well as surface accumulator bottles. These subsea bottles serve to give a quicker response by holding some of the stored usable fluid very close to the preventers. Also, if supply from the surface is interrupted, the stored usable fluid in the subsea bottles can be used to close in the well while corrective action is taken. Accumulator bottles mounted below the water's surface are subject to additional pressure proportional to the service depth. When the subsea control valve is piloted sending pressure to close the BOP, the open side valve vents to the sea. As the BOP closes, the fluid is being expelled from against the hydrostatic pressure of the seawater. This pressure can be expressed as hydrostatic pressure or as a pressure gradient. One way to look at hydrostatic pressure is by considering the operating fluid supply line to the accumulator bottles which would be the weight of the column of control system fluid from the surface; the other is to consider the weight of the seawater at the depth of the function which the accumulator must overcome in order to discharge fluid. Control system fluid is basically water which has a weight density of 62.4 pounds per cubic foot or a pressure of 0.433 psi per foot. Seawater has a weight density of 64 pounds per cubic foot or a pressure of 0.445 psi per foot. It is easy to see that whichever way you consider hydrostatic pressure there is not enough difference to be concerned about. Let us use Boyle's Law to calculate the stored usable fluid in a 10 gallon accumulator bottle that is to be operated in 3000 feet of water. In this case the correct pre-charge pressure is calculated as given below: Pre-charge pressure = Seawater Hydrostatic Pressure for Subsea Bottles + Pre-charge Pressure = (0.445 x 3000) + 1000 = 1335 + 1000 = 2335 psi It is important to note that the minimum system pressure is still 200 psi above the pre-charge pressure and maximum system pressure is still 2000 psi above pre-charge pressure. Therefore; Minimum System Pressure = 2335 + 200 = 2535 psi Maximum System Pressure = 2335 + 2000 = 4335 psi The stored usable fluid in our subsea bottle is calculated in exactly the same fashion as for a surface bottle. We can calculate that amount not considered usable by solving the Boyle's Law equation as follows: V2 = P1 x V1 /P2 = 2335 x 10 / 2535 = 9.2 gallons nitrogen

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Where: V2 = gallons of nitrogen at minimum system pressure P1 = initial pressure (nitrogen pre-charge) V1 = initial gas volume in gallons P2 = minimum system pressure in psi So as pressure in the accumulator bottle rises from 2335 psi (pre-charge pressure) to 2535 psi (minimum system pressure), the nitrogen gas is compressed from 10 gallons to 9.2 gallons or 0.8 gallons of liquid was forced into the bottle. This 0.8 gallons is not considered stored usable fluid. The total volume of liquid in the bottle at the maximum system pressure can also be calculated using Boyle's Law as given below: V3 = P1 x V1 /P3 = 2335 x 10 / 4335 = 5.4 gallons nitrogen Where: V3 = gallons of nitrogen at maximum system pressure P1 = initial pressure (nitrogen pre-charge) V1 = initial gas volume in gallons P3 = maximum system pressure in psi Now we know that as the pressure in the bottle rises from 2335 psi (pre-charge pressure) to 4335 psi (maximum system pressure), the nitrogen gas is compressed from 10 gallons to 5.4 gallons or 4.6 gallons of liquid is now in the bottle. Remembering that the 0.8 gallons does not count, we can determine the stored usable fluid in the bottle by the following equation: Stored Usable Fluid = (4.6 - 0.8) gal = 3.8 gallons Said another way, as the pressure in the 10 gallon accumulator bottle falls from 4335 psi to 2535 psi, 3.8 gallons of liquid are forced out of the bottle and into the lines. One problem encountered in deepwater drilling is diminishing stored usable fluid inside subsea accumulator bottles as depth of water increases. NOTE: The maximum system pressure used in this example would exceed the design working pressure of standard 3000 psi WP accumulator bottles. 5000 psi WP accumulator bottles must be used in this application.

Sizing Accumulator System Capacity For Subsea Blowout Preventers Subsea systems because of their isolation by location and greater risk of environmental damage usually are sized for more accumulator volume than surface systems. API RP16E.3.4.1 recommends capacity to close and open all of the ram type BOPs and one annular BOP plus fifty percent reserve. Consideration for minimum pressure is also stated for closing a ram (excluding shear ram) against full rated wellbore pressure or the minimum pressure required to open and hold open any kill or choke valve at maximum rated wellbore pressure. Calculations for surface mounted accumulators are the same as previously described. When part of the accumulator volume is to be placed subsea, the subsea volume requirements can be subtracted from the total volume requirement which leaves the surface volume requirement. In other words, the subsea stored usable fluid volume plus the surface stored usable fluid volume must meet or exceed the total fluid volume required at the minimum system pressure specified in order to operate the BOP function. For explanation purposes let us say the same BOPs are used for the subsea calculations as were previously used: Annular gallons to close = 17.98 gallons

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Annular gallons to open =

14.16 gallons

Rams (3) @ 5.8 gal each to close =

17.40 gallons

Rams (3) @ 5.4 gal each to open =

16.20 gallons

Total gallonage required:

65.74 gallons

Plus 50% safety factor = 32.87 gallons Stored usable fluid required = 98.61 gallons We will say in this instance that the capacity to close the annular and one ram will be mounted subsea. This capacity can be subtracted from the surface capacity as given below: 98.61 gal - (17.98 gal + 5.80 gal) = 74.83 gal Therefore we now know that we need to have enough accumulator bottles at surface to give 74.83 gallons of stored usable fluid and enough accumulator bottles at the BOP stack to give (17.98 gal + 5.80 gal) 23.78 gallons of stored usable fluid. Since we have previously calculated the stored usable fluid in both surface and subsea 10 gallon accumulator bottles, we can calculate the number of bottles required as follows: Surface Accumulator Bottles Required = (Stored Usable Fluid Required)/( Stored Usable Fluid per Bottle) = (74.83 gal)/(5.0 gal per bottle)= 15 bottles at surface Subsea Accumulator Bottles Required = (Stored Usable Fluid Required) /(Stored Usable Fluid per Bottle) = (23.78 gal)/(3.8 gal per bottle) = 6.3 or 7 bottles mounted subsea bottles on SS Stack

Calculating Reservoir Capacity Closed hydraulic system reservoirs used to operate surface mounted BOP stacks should be sized to hold a minimum of two times the usable fluid of the accumulator system. The purpose of the additional reservoir capacity is to allow bleeding the accumulator system hydraulic pressure back to the reservoir without over-filling. This means that during normal operation, if the reservoir is exactly sized for this capacity, it should be operated half full. Open hydraulic system reservoirs used to operate subsea mounted BOP stacks should be at least equal to the total accumulator storage capacity. There should be sufficient space in the reservoir above the upper hydraulic fluid fill valve shut off level to permit draining the largest bank of accumulator bottles back into the tank without overflow.

Sizing Pump Systems Pump systems should be capable of delivering sufficient volume of control fluid with the accumulators isolated from service to meet the greater of the following recommendations: 1. Close one annular BOP (excluding diverter) on open hole and open one choke line valve while attaining sufficient pressure to effect seal off as recommended by the annular BOP manufacturer at zero wellbore pressure (this is nominally 1200 psi). Verification should be by closing on the minimum size drill pipe to be used. The pump system should accomplish this within two minutes. 2. Pump the entire accumulator system up from accumulator pre-charge pressure to full charging pressure (the maximum system pressure)within fifteen minutes. There should be a minimum of two independent pump systems operating from separate power sources. Each of the pump systems should have sufficient sizes and quantity of pumps to meet the preceding recommendation.

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Philosophy This section of the manual is not intended as a training manual, rather it is meant to be a resource to be used at the well site by trained personnel in "remedial" or "secondary" Well control operations.

Scope This section of the manual will be applicable to land, offshore floating, and offshore bottom-supported rigs from close-in to kill.

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K3. Well Control Procedures Basic Principles Definition A kick is an influx of formation fluids into the well bore. A blowout is an uncontrolled kick. The objective of well control procedures discussed in this section is to safely handle kicks and reestablish primary well control.

Primary Well Control During normal drilling operations, formation fluid flow into the wellbore is prevented by greater hydrostatic pressure from drilling fluids in the wellbore. When drilling or wellbore fluids have a hydrostatic pressure which is greater than the pressure found in the formation fluids there is said to be an overbalance.

Circulation Pressures Resistance to flow can be considered as friction. Friction acts in the opposite direction of flow. Because of the inherent resistance of liquids to flow, force must be applied to circulate drilling fluids around the well. Most of the pressure seen on the Drill Pipe Pressure Gauge when drilling is caused by resistance to flow inside the surface lines, the drill string, and at the bit. This pressure is not exerted, or "felt" in the annulus. the pressure caused by resistance to flow in the annulus is applied in the annulus, and the sum of all the annulus friction is focused at the bottom of the hole.

Bottom-hole Pressure (Bhp) Vs Formation Pressure (Fp) Bottom-Hole Pressure may be defined as the total pressure at the bottom of the well. For Well Control Purposes, this may be considered as a downward force. Formation Pressure, the pressure of the fluids in the formation, may be considered an upward force, for Well Control purposes. BHP and FP then act in opposite directions. When primary well control is working as intended -- BHP is greater than FP. When a kick is occurring, FP is greater than BHP. A. BHP when well open and pumps off BHP = Hydrostatic Pressure of Wellbore Fluids B. BHP when well open and pumps on BHP = Hydrostatic Pressure of Wellbore Fluids plus Annulus Friction

Slow Circulating (Kill) Rate / Pressure For well kick killing operations, a circulating pressure can be measured at a convenient slow circulating (kill) pump rate -- frequently one-half or less of the normal circulating rate. It is recommended that the stroke rate and pressure be recorded on the IADC daily drilling report for each pump and redone whenever any of the circulating system pressure parameters is significantly changed, i.e., when drilling fluid density is changed by 0.2 ppg or more, when bit nozzle sizes are changed, when over 500 ft of new hole is drilled, after pump repairs or liner sizes are changed, etc. Slow circulating (kill) rates are usually required when circulating kicks for several reasons: in order that time for drilling fluid mixing (to increase mud density) may be increased, to minimize the amount of cuttings that may be circulated up and through the choke, in order that additional pressure to prevent formation flow can be added without exceeding the pump liner rating, and to better enable the choke operator to make correct adjustments.

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Sub Sea Stack Considerations One widely accepted method to determine Choke Line Friction (CLF) is to pump at each pre-determined slow circulating (kill) pump rate in the normal drilling circulation path, i.e., down the drill string, up the annulus through the BOP and up the riser to the flow line. After pumping in the usual flow path, the flow path should be changed to simulate that of well fluids during a well kill. To simulate the flow path of fluids during a kill, the BOP should be closed and the valves on the BOP stack to the choke line opened, all choke manifold valves to and through the remote choke to the mud/gas separator opened and the choke itself fully opened, as well. After completing the correct line-up, the pumps should then be run at the same slow circulating (kill) rates as through the normal drilling circulation path. The differences between the pressures at the same pump rates on the same pump through the different flow paths is considered the Choke Line Friction (CLF) at that pump rate and must be taken into account when killing wells on floating rigs because it increases the pressure throughout the well. THE SLOW CIRCULATING PRESSURE THROUGH THE RISER IS CONSIDERED THE "KILL RATE PRESSURE" (KRP). For subsea stacks in deep water, slow circulating (kill) rates (less than one-half normal circulating rate) may be required to avoid excessive friction back pressure from pumping drilling fluids up the choke lines from the BOP to the choke manifold (CLF), in addition to those reasons stated earlier in this section. Large changes in ANNULUS HYDROSTATIC PRESSURE occur when a choke line goes from being filled with mud to being filled with gas and later when the choke line goes back to being filled with mud. These ANNULUS HYDROSTATIC PRESSURE changes cause changes in the bottom hole pressure of the well which are more easily compensated for with choke back pressure changes when the circulation rate is slow.

II. Pre-kill Procedures Close-in (Shut-in) Procedures 1. Soft Close-in: A. Pre-kick line up: BOP open Remote choke open Hydraulic valve(s) on BOP stack closed All choke manifold valves to Remote Choke open All choke manifold valves past Remote Choke to Mud/Gas Separator (poorboy degasser) open B. Close-in: Open Hydraulic valve(s) on BOP stack Close Annular Close Remote Choke 2. Fast Close-in: A. Pre-kick line up: BOP open

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Remote choke closed Hydraulic valve(s) on BOP stack closed All choke manifold valves to Remote Choke open All choke manifold valves past Remote Choke to Mud/Gas Separator (poorboy degasser) open B. Close-in: Open Hydraulic valve(s) on BOP stack Close Annular 3.

Hard Close-in:

A. Pre-kick line up: BOP open Remote choke closed Hydraulic valve(s) on BOP stack closed All choke manifold valves to Remote Choke open All choke manifold valves past Remote Choke to Mud/Gas Separator (poorboy degasser) open B. Close-in: Open Hydraulic valve(s) on BOP stack Close Ram

Stabilized Pressures When a kick is detected, the well should be closed in as quickly as possible to minimize kick influx volume. When (and if) the Closed In Drill Pipe Pressure and the Closed In Casing Pressure rise to some pressure and then stabilize, it is assumed that they show what the hydrostatic column in the Drill Pipe or the Annulus lacks to balance the Formation Pressure. If after closing in the well the surface pressures do not stop increasing, there is a strong possibility that there is a gas influx in the hole and that it is rising (migrating) in the hole -- much the same as an air bubble in water. There is also a possibility that the formation has low permeability, and for that reason the total that the wellbore hydrostatic pressure lacks to balance the Formation Pressure is slowly expressed on the Drill Pipe and Casing Pressure Gauges. There is one good way to determine what the amount of underbalance is in a well where the closed-in pressures continue to rise rather than rising and then stabilizing after closing in the well. This method requires that the driller, or whoever monitors the closed-in pressures, write down the closed-in pressure values at some pre-agreed upon time interval, beginning as soon as possible after the initial close-in. The recommended time interval for writing down the Closed-in Drill Pipe and Closed-in Casing (annulus) pressures is once every minute. As the pressures are recorded, they need to be entered on to a sheet of graph paper. Increasing time would be expressed on the axis going from left to right. Increasing pressure would be expressed on the axis going upwards. See example graph on following page. When the rate of increasing pressure changes (slows) the pressure at that point may be considered the amount of underbalance.

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Figure K3-3 Closed-In Drill Pipe Pressure

Closed-in Drill Pipe Pressure When the well is closed in, the bottom hole pressure will rise until equal to formation pressure. As the drill pipe (and annulus) are in communication, the Closed-in Drill Pipe and the Closed-in Casing (annulus) pressures will also rise and stabilize (in the absence of migrating gas) the Closed-in Drill Pipe pressure at this time indicates the amount of underbalance of the hydrostatic pressure in the drill string relative to the formation pressure. It is assumed that the drill string is filled with a column of clean drilling fluid of equal density from the rig floor to the bit, i.e., a known hydrostatic pressure value. In well killing operations, the drilling fluid density is increased by the equivalent value of the Closed-in Drill Pipe pressure. Until circulation begins, if there is gas in the well, surface pressures will continue to rise due to gas migration. Increased drill pipe pressures due to gas migration read after any stabilized reading will indicate excessive drilling fluid density increase.

Gas Migration Considerations Migrating (rising) gas in a closed in well causes pressures to rise throughout the well. the increasing pressure in the well caused by migrating gas can lead to loss of integrity in the circulating system, i.e., lost circulation. Such excessive pressure should be avoided whether gas rises through a static drilling fluid column or if it is circulated out -- by allowing the gas to expand as it rises while maintaining constant Bottom-Hole pressure. When properly using a well kill method which keeps Bottom-Hole pressure constant, any gas in the well will be allowed to expand by the amount necessary to keep Bottom-Hole pressure constant. This also requires that the pits be allowed to gain volume. If it is believed that there is migrating gas in the well when waiting to begin circulation and if the bit is at or near bottom, to avoid excess wellbore pressures the choke should be used to bleed drilling fluid from the casing. the amount of pressure to try to keep constant is the Closed-in Drill Pipe pressure value which reflects the amount of underbalance in the drill string, plus 100 or 200 psi. See page 6 for choke adjustment considerations.

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Closed In Drill Pipe Pressure Determination With A Float In The String To determine the closed-in drill pipe pressure when a back-pressure valve (float) is in the drill string, Closed-in Drill Pipe pressure should be increased slowly in 50 or 100 psi increments using the smallest pump available. After each stage of increasing the Drill Pipe pressure, the Casing (annulus) pressure should be monitored for a change. If the Casing pressure does not change (increase), the float has not opened, and the Closed-in Drill Pipe pressure is less than the underbalance of the hydrostatic pressure in the drill string. When Casing pressure is seen to rise, pumping should be stopped immediately. The current Closed-in Drill Pipe pressure, minus any increase seen on the Casing (annulus) Pressure gauge, is the amount of underbalance of the hydrostatic pressure in the drill string relative to the formation pressure. This is the value to be used when calculating the Kill Weight Mud.

III. Formation Pressure Integrity Information Leak-off Test And Masp A leakoff test is made to determine the pressure at which a formation will begin to leak off. Leakoff tests are usually run after drilling a short distance below the most recent casing shoe. A leakoff test is performed by pumping drilling fluid into the wellbore at a slow rate or in increments of volume, with blowout preventers closed. The resulting pressures are to be carefully plotted versus the volume pumped. The pressure at which the plotted curve begins to flatten, i.e. when the pressure increases a smaller amount for a volume pumped, is the surface leakoff pressure. Pumping should be stopped immediately. The surface leakoff pressure plus the hydrostatic pressure of the drilling fluid at the shoe is the formation leakoff pressure. The formulas to calculate the formation fracture pressure and other Maximum Allowable Surface Pressures are to be found on the kill sheets provided at the end of this section. The gauge to monitor for Maximum Allowable Surface Pressures is the Casing (annulus) pressure gauge.

Formation Competency Test And Masp A formation competency test is made to evaluate if a wellbore will support drilling fluid of a higher pre-determined density than that which is currently in use. The formation competency test is performed by pumping drilling fluid into the wellbore at a slow rate or in increments of volume, with blowout preventers closed. Pumping into the wellbore should be continued until reaching the pre-determined surface test pressure as calculated below: Test Pressure (psi) = 0.052 x Casing TVD (ft) x density difference (ppg)* *density difference (ppg) = desired drilling fluid density-drilling fluid density currently in use. While conducting this test, the surface pressure should be plotted against the volume pumped into the wellbore. If at any time the plotted curve should begin to flatten or the pressure decrease, pumping should be stopped immediately (see page 3, Leak-Off Test, LOT, and MASP).

Kill Objective After a kick has been stopped by well closure, it should be circulated to the surface at constant bottom-hole pressure to avoid both further influx of formation fluids and excessive borehole pressures. Also, drilling fluid density should be increased to reestablish primary well control. A drilling fluid of required density may be pumped while circulating out the kick (Wait and Weight Method), or the kick may be pumped out and then drilling fluid of required density circulated (Drillers Method). In the event of insufficient barite supply, drilling fluid density can be increased temporarily to an intermediate value using either of these methods.

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Establishing Circulation Surface Stacks To establish the slow circulating (kill) rate while keeping a constant bottom-hole pressure, the pump rate should be increased from zero spin to the kill rate spm's while holding a constant casing pressure equal to the closed-in casing pressure. The recommended procedure is as follows: 1. Note the current Closed-in Drill Pipe and Closed-in Casing pressures. 2. Concurrently open the choke and slowly bring the pump up to the slow circulating (kill) rate. 3. While bringing the pump up to speed, adjust choke to hold the casing pressure constant at the closed-in value. By holding the casing pressure constant at the closed-in value for the short time required to bring the pump up to speed, the bottom-hole pressure remains essentially constant. 4. After the pump is running at the desired constant speed and the casing pressure is stabilized at the Closed-in value, wait at least 2 seconds per thousand feet measured depth of the well and then read the drill pipe pressure. It is necessary to wait approximately two seconds per thousand feet of measured depth of the well to allow choke adjustments to be reflected on the drill pipe pressure gauge. The Drill Pipe pressure read at this point is usually termed INITIAL CIRCULATING PRESSURE (ICP), if this pump start-up is taking place at the beginning of the kill. The difference between the closed-in and pumping drill pipe pressures is the pressure required to cause the drilling fluid to circulate at the slow circulating (kill) rate, and is often termed the KILL RATE PRESSURE (KRP). 5. Compare any calculated or expected INITIAL CIRCULATING PRESSURE (ICP) to that which is now seen on the Drill Pipe Pressure gauge. If there is a difference and if the instructions above for establishing Initial Circulating Pressure (ICP) have been followed, the pressure on the Drill Pipe Pressure gauge is correct if the calculated Drill Pipe pressure is appreciably different from what is seen on the Drill Pipe Pressure gauge after establishing INITIAL CIRCULATING PRESSURE (ICP) it is recommended that the cause be identified. 6. After bringing the pump strokes up to the slow circulating (kill) rate, it is absolutely necessary to keep the PUMP STROKES constant in order to keep BOTTOM-HOLE PRESSURE constant.

Establishing Circulation - Subsea Stacks - Method "A" To establish the slow circulating (kill) rate while keeping a constant bottom-hole pressure, the pump rate should be increased from zero spm to the kill rate spm's while holding a constant casing pressure equal to the closed-in casing pressure, MINUS THE CHOKE LINE FRICTION (CLF) VALUE FOR THE PUMP AND PUMP SPEED WHICH ARE TO BE UTILIZED. The recommended procedure is as follows: 1. Note the current Closed-in Drill Pipe and Closed-in Casing pressures. 2. Concurrently open the annulus choke and slowly bring the pump up to the slow circulating (kill) rate. 3. While bringing the pump up to speed, adjust choke to reduce the Casing (Annulus) pressure from the closed-in value to the closed-in value minus the Choke Line Friction (CLF). By holding the casing pressure constant at the closed-in value minus the Choke Line Friction (CLF) value for the short time required to bring the pump up to speed, the bottom-hole pressure remains essentially constant. 4. After the pump is running at the desired constant speed and the easing pressure is stabilized at the Closed-in value minus the Choke Line Friction (CLF) value, wait at least 2 second per thousand feet measured depth of the well and then read the Drill Pipe pressure. It is necessary to wait approximately two seconds per thousand feet of measured depth of the well to allow choke adjustments to be reflected on the drill pipe pressure gauge.

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The drill pipe pressure read at this point is usually termed INITIAL CIRCULATING PRESSURE (ICP), if this pump start-up is taking place at the beginning of the kill. The difference between the closed-in and pumping drill pipe pressures is the pressure required to cause the drilling fluid to circulate at the slow circulating (kill) rate, and is often termed the KILL RATE PRESSURE (KRP). 5. Compare any calculated or expected INITIAL CIRCULATING PRESSURE (ICP) to that which is now seen on the Drill Pipe Pressure gauge. If there is a difference and if the instructions above for establishing Initial Circulating pressure have been followed the pressure on the Drill Pipe Pressure gauge is correct. If the calculated Drill Pipe pressure is appreciably different from what is seen on the Drill Pipe Pressure gauge after establishing INITIAL CIRCULATING PRESSURE (ICP) it is recommended that the cause be identified. 6. After bringing the pump strokes up to the slow circulating (kill) rate, it is absolutely necessary to keep the PUMP STROKES constant in order to keep BOTTOM HOLE-PRESSURE constant.

Establishing Circulation - Subsea Stacks - Method "B" The kill line pressure gauge can be used to monitor choke line friction and surface back pressure when circulation is begun after a kick. 1. The kill line should be opened to the surface manifold and the kill line pressure held constant by adjustment of the CHOKE LINE choke while bringing the pump up to the slow circulating (kill) rate. By holding the Kill Line pressure constant during the pump start-up, the Bottom-hole pressure remains essentially constant. 2. After the pump is running at the desired constant speed and the Kill Line pressure is stabilized at the Closed-in value, wait at least 2 seconds per thousand feet measured depth of the well and then read the Drill Pipe pressure. It is necessary to wait approximately two seconds per thousand feet of measured depth of the well to allow choke adjustments to be reflected on the drill pipe pressure gauge. The drill pipe pressure read at this point is usually termed INITIAL CIRCULATING PRESSURE (ICP), if this pump start-up is taking place it the beginning of the kill. the difference between the closed-in and pumping drill pipe pressures is the pressure required to cause the drilling fluid to circulate at the slow circulating (kill) rate, and is often termed the KILL RATE PRESSURE (KRP). 3. Compare any calculated or expected INITIAL CIRCULATING PRESSURE (ICP) to that which is now seen on the Drill Pipe Pressure gauge. If there is a difference and if the instructions above for establishing Initial Circulating Pressure have been followed, the pressure on the Drill Pipe Pressure gauge is correct. !f the calculated Drill Pipe pressure is appreciably different from what is seen on the Drill Pipe Pressure gauge after establishing INITIAL CIRCULATING PRESSURE (ICP) it is recommended that the cause be identified. 4. After bringing the pump strokes up to the slow circulating (kill) rate, it is absolutely necessary to keep the PUMP STROKES constant in order to keep BOTTOM-HOLE PRESSURE constant.

Choke Adjustment Considerations During the course of either of the kill methods presented here, it may be necessary to make adjustments to the Drill Pipe Pressure gauge by manipulating the choke. The correct method is essential. 1. When it is noted that a change is desired on the Drill Pipe Pressure gauge, note the amount of pressure by which it is to be changed. For example, if the current Drill Pipe pressure is 8:50 psi and the desired Drill Pipe pressure is 1000 psi, the amount of change desired is an additional 150 psi.

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2. Note the current Casing (annulus) gauge pressure and by manipulating the choke, change the Casing (annulus) gauge pressure by the amount of pressure change desired on the Drill Pipe pressure gauge. For example -- continuing from the example in #1, above, if the current Casing (annulus) pressure is 1050 psi, the choke operator should close the choke to increase the Casing (annulus) pressure by 150 psi to 1200 psi. 3. Wait at least two seconds for every 1000 feet of measured depth of the well for the pressure change to come from the choke to the Drill Pipe pressure gauge.

IV. Kill Techniques Drillers Method Please use the following information, the table below, and the Driller's Method kill sheet utilizing this kill method.

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Table K3-P8 Steps of the Driller's Method

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1. The first step of the Driller's Method is most appropriate for use (by itself) when circulating out kicks that have been swabbed in while tripping out of the well. The fact that the mud density is not increased in the first step of the Driller's Method makes it the best choice in that situation. In a swabbed-in kick situation, it is not always necessary to increase the mud density before continuing to pull the string out of the hole. The assumption is that the well was stable with the mud in the hole before coming off bottom, therefore it should only be necessary to circulate out the swabbed-in kick and then the string should be able to be pulled out of the hole. 2. it is assumed that in the second step of the Driller's method there is a column of clean drilling fluid of the same density in both the drill string and the annulus at the beginning of the circulation. As the Kill Weight Mud (KWM) is circulated from the surface to the bit, the Casing (annulus) pressure is held constant at, er bringing the pump up to the slow circulating (Kill) rate. Since the hydrostatic pressure is staying constant in the annulus, and the surface CASING (annulus) pressure is kept constant through choke manipulation, the Bottom Hole pressure is held (essentially) constant. The pressure seen on the Drill Pipe pressure gauge when the Kill Weight Mud (KWM) reaches the bit is the Final Circulating Pressure (FCP) for the Driller's Method. 3. The third step of the Driller's Method begins when the Drill String has been filled with the Kill Weight Mud (KWM). The Kill Weight Mud (KWM) is circulated from the bit to surface in the annulus. Since the hydrostatic pressure in the Drill String stays constant and the surface Drill Pipe pressure is kept constant at the Final Circulating Pressure (FCP) through choke manipulation, the Bottom hole pressure is held (essentially) constant. Also see: Driller's Method, Step-by-Step Alternate Driller's Method

Wait And Weight Method Please use this guide and kill sheet when utilizing this kill method. 1. When the Wait and Weight Method is used, the well is closed in on the kick, drilling fluid density is increased as required, and the kick is circulated out using the weighted fluid. 2. Circulation is established at the kill rate as described on pages 5 and 6. 3. A schedule of drill pipe pressure changes should be prepared and followed if the calculated Initial Circulation Pressure (ICP) conforms to the actual ICP at, er doing a correct pump start-up, as outlined on pages 5 and 6. If there is a difference between the actual (GAUGE) ICP and the calculated ICP, the GAUGE ICP SHOULD BE CONSIDERED CORRECT. If there is a difference between the gauge ICP and the calculated ICP, the Drill Pipe pressure schedule should be adjusted up or down by the difference between the ACTUAL (GAUGE) ICP and the calculated ICP. For example, if the pump start-up is conducted as outlined on pages 5 and 6 and the actual ICP is 1500 and the calculated ICP is 1300, all of the values in the Pressure drop schedule, including the Final Circulating Pressure (FCP) should be increased by the difference (1500 psi - 1300 psi = 200 psi). These corrected values should be followed by. manipulating the choke, if necessary. 4. After Kill Weight Mud has been circulated to the bit, Final Circulating Pressure (FCP) should be held constant on the Drill Pipe pressure gauge until the Kill Weight Mud (KWM) is at the surface, confirmed by weighing the returns.

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Comparison Of Kill Methods -- Advantages And Disadvantages Kill Method Table K3-P9 Driller's Method vs W&W Method

Driller's Method ADVANTAGES Circulation can be started almost immediately. Simpler. Fewer calculations. KWM can be mixed to uniform density while first circulation is completed. Does not require special consideration/modification in directional wells or wells with tapered strings. DISADVANTAGES Minimum of two circulations. More time. Higher annulus pressures. More wear on choke and gas handling machinery. Wait and Weight ADVANTAGES Minimum of one circulation, less time. Lower annulus pressures. Less wear on choke and gas handling machinery. DISADVANTAGES Circulation must wait to start until kill weight mud (KWM) has been mixed (waiting period). More calculations. More complex. Requires special considerations or modifications in directional wells and wells with tapered strings.

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Diverter Usage Where shallow casing strings are set, fracture gradients are often very low and wells may not be able to be safely closed in on a kick without danger of lost circulation and possible broaching to the surface. Gas from shallow sands can be abnormally pressured, increasing the possibility of lost circulation and the possibility of vertical fracturing of shallow formations allowing formation fluids to vent to surface outside of the drilled hole. The time needed to get formation fluids to surface from shallow formations may be less than one minute. This short amount of time leaves the driller little time to react. It is absolutely necessary that the driller know the signs of and the appropriate actions to take in the event of a shallow gas kick. Drilling shallow sands too rapidly can cause excessive gas-cutting of the drilling fluid with cuttings gas to the extent that expansion while being pumped to the surface lowers the hydrostatic pressure enough to cause formation flow because of the lack of Bottom-Hole pressure. Conversely, large amounts of drilled cuttings in the drilling fluid from drilling at high rates of penetration may cause the drilling fluid density to increase to a point that circulation may be lost. When lost circulation occurs the level of fluid may fall in the well, causing the hydrostatic head to drop to a point that may allow the well to flow. A diverter may be used in those areas with possible shallow gas sands to direct well flow away from the rig during kicks. the diverter should be arranged so that a diverter linc automatically opens or is open when the diverter is closed in order to divert the kick fluids and prevent back pressure on the hole. Diversion is usually away from the rig, resulting in loss of drilling fluid from the circulating system. Under these conditions, formation fluid flow continues during the well control operation until the hole bridges or hydrostatic pressure can be built enough to regain primary control or until the formation is depleted. Pumping at a fast rate tends to improve the drilling fluid/gas ratio and also creates a small increase in bottom-hole pressure due to annular friction pressure. Increasing the drilling fluid density at a fast rate increases hydrostatic pressure and may eventually stop flow. Thus, whoa a shallow gas flow occurs, the following actions should be taken immediately: 1. Pump as fast as possible. 2. Increase drilling fluid density as rapidly as possible while pumping. 3. If drilling fluid supply should be exhausted, continue by pumping water. 4. Divert the well fluids in a safe path away from the rig floor. On large drilling rigs in areas with possible shallow gas, a reserve supply of drilling fluid weighted above the current mud weight may be carried in reserve for use in shallow gas kick remediation. Immediate pumping of a pre-weighted kill mud into the well, if shallow gas kick occurs, should be considered as part of a shallow-gas kick contingency plan. If the drilling fluid supply is exhausted, a plug may be attempted. This procedure may serve to (1) increase the hydrostatic pressure, (2) to form a super viscous pill, or (3) to form a fast hardening concrete pill -- depending on the plug type.

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Gas Migration Considerations While Out of The Hole -- Volumetric Method Gas migration considerations when the bit is at or near bottom were discussed on page 4. In the event that the well is shut in with the bit completely out of the well, the Drill Pipe pressure gauge value will be meaningless, i.e., zero. Since the Drill Pipe pressure value cannot be used in the event that the well is closed in while out of the hole, a different logic must be used to control Bottom-Hole pressure than that found in the paragraph on gas migration. the logic discussed in this section is based on monitoring the Casing (annulus) pressure gauge, and making choke adjustments based on well parameters. Please refer to the following paragraphs in this section and the Volumetric Kill Guide at the end of this section when making preparations to use this kill technique. 1. Determine the amount of underbalance. A mechanism for identifying the amount of underbalance in a closed-in well with migrating gas was discussed in the paragraph on stabilized pressures. In the circumstances discussed in this section, the Casing (annulus) pressure gauge value must be used, rather than the Drill Pipe pressure gauge. 2. Calculate the height of a column of mud which is required to be bled from the well in order to lower hydrostatic pressure 100 psi. 100 psi /(0.052 x mud weight, ppg) = the height of a column of mud to needed to change the hydrostatic pressure by 100 psi For example, in a well with 11.2 ppg mud, 100 psi /(0.052 x 11.2 ppg) = 171.7 feet 3. Calculate the volume of mud which is required to be bled from the well in order to lower hydrostatic pressure 100 psi. height of column of mud to change mud hydrostatic pressure 100 psi x Casing Capacity (bbl/ft) = volume For example, using the information immediately above in a well with a casing ID of 9.12 inches: 171.7 feet x {(9.12 x 9.12)/1029.4} = volume of mud to change HP by 100 psi, or 171.7 feet x 0.0808 bbls/ft = 13.87 bbls 4. Allow the Casing (annulus) pressure value to increase to a value which is 200 psi greater than the value which reflects the amount of underbalance in the well, see #1 above. For example, if the amount of underbalance is determined to be 700 psi, the pressure to allow the Casing (annulus) gauge to increase to is 900 psi (700 + 200 = 900). It is now assumed that the bottom-hole pressure is 200 psi greater than the formation pressure. 5. Slowly bleed mud through the choke, maintaining easing (Annulus) pressure constant, until the volume of mud to lower hydrostatic pressure by 100 psi has been bled from the well. For example, continuing with the examples from this section, 13.87 barrels of mud should be bled during the first bleed operation. At the end of the first bleed operation, the pressure on the casing (Annulus) pressure gauge should be the value which reflects the underbalance in the hole plus 200 psi. At this point in the kill it is assumed that the bottom-hole pressure is 100 psi greater than formation pressure. 6. After completing the first bleed operation, the choke should be closed and the pressure allowed to increase 100 psi more.

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For example, continuing with the examples from this section, after bleeding 13.87 barrels from the well -- the choke is to be closed and the pressure on the Casing (annulus) gauge allowed to increase from 900 psi to 1000 psi. It is now assumed that the bottom-hole pressure is 200 psi greater than the formation pressure. 7. Slowly bleed mud through the choke, maintaining casing (Annulus) pressure constant, until the volume of mud to lower hydrostatic pressure by 100 psi has been bled from the well. 8. After completing the above bleed operation, the choke should be closed and the pressure allowed to rise 100 psi more. 9. Repeat #7 and #8 above until gas is at surface, then close the choke immediately. 10. When the gas kick reaches the surface it is necessary to pump mud into the well to replace the gas and to maintain Bottom-Hole pressure equal to or greater than Formation pressure. It will be necessary to pump the mud into the well through the Kill Line and then allow the mud time to fall through the gas. As the mud is pumped into the well through the Kill Line, the gas will be compressed, causing the Casing (annulus) pressure to increase. It is critical that the person(s) conducting this kill note the Casing (annulus) pressure increase due to compressing the gas. 11. Slowly pump the volume of mud necessary to increase hydrostatic pressure by 100 psi into the well, then wait for the gas to separate from the mud. For example, continuing with the examples from this section, note the closed in Casing (annulus) pressure, then slowly pump 13.87 barrels of 11.2 ppg mud into the well, then stop the pump and wait for the mud to fall through the gas. Expected time for the gas to fall through (separate from) the mud is 10 to 20 minutes, Possibly Longer! 12. Slowly bleed GAS (ONLY!) from the choke, lowering the Casing (annulus) pressure to the value found on the Casing (annulus) pressure gauge immediately before pumping the volume of mud necessary to increase hydrostatic pressure by 100 psi, then bleed 100 psi more to compensate for the 100 psi increase in hydrostatic pressure due to pumping the mud into the annulus. 13. Repeat #11 and #12 until gas has been replaced by mud in the annulus. Well should be flow checked, then BOP opened(if dead), and pipe run to bottom.

Well Kills In Directional Wells When considering which of the several Well Kill techniques to utilize which have been presented in this section the following should be considered. A. If the reader is drilling a directional well, it should be noted that inaccuracies in the pressure drop schedules of Wait and Weight Method Kill Sheets (Surface or Sub-sea) can lead to over-pressuring the annulus -- increasing the likelihood of stuck pipe or lost circulation. B. If the reader is drilling a well with a tapered drill string it should be noted that inaccuracies in the pressure drop schedules of Wait and Weight Method Kill Sheets (Surface or Sub-sea) can lead to underpressuring the annulus -increasing the likelihood of large secondary influxes. In order to avoid the problems associated with "A." immediately above, there are several choices available to those charged with deciding which kill technique is to be utilized. The inaccuracies caused by using a "regular" (Surface or Sub-sea) Wait and Weight Method Kill Sheet are unlikely to be equal to or greater than 100 psi if: 1. The angle from vertical is equal to or less than 30 degrees; or 2. The Closed In Drill Pipe Pressure is less than 1000 psi.

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a. If the well being drilled is a Build-and-Hold (two-part) type directional well the reader may use the Deviated Well Pressure Drop Schedule found at the end of this section, especially if the Wait and Weight Method Kill is the preferred method by the decision makers on site. b. If the well being drilled is a Build-Hold-and-Drop (three-part) type directional well, or if the reader does not want to use the Deviated Well Pressure Drop Schedule in a Build-and-Hold (two-part) type directional well, and if "1." and/or "2." above are not true, the Driller's method is recommended. c. For the reason that the inaccuracies caused by using a "regular" Wait and Weight Kill Sheet (Surface or Subsea) are likely to be less than 100 psi if "1." and/or "2." above are not true, it may be advisable to utilize the "regular" Wait and Weight Kill Sheet in that circumstance - if the Wait and Weight Method Kill is that which is preferred by the persons making such decisions on the rig. In order to avoid the problems associated with "B." immediately above, the best of several choices available to those charged with deciding which kill technique is to be utilized is presented immediately below. d. If the smaller diameter drill string is longer than 1000 feet, it is recommended to use the Driller's Method.

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K-4 Glossary of Well Control Terms Accumulator: A pressure vessel charged with nitrogen gas and used to store hydraulic fluid under pressure for operation of blowout preventers. Accumulator Bank: An assemblage of multiple accumulators sharing a common manifold. Accumulator Unit: A hydraulic power unit with accumulators, pumps control fluid reservoir and hydraulic control manifold for operation of blowout preventers. Annular (BOP): A device with a generally toroidal shaped steel reinforced elastomer packing element that is hydraulically operated to close and seal around any size drill pipe or to provide full closure of the wellbore. Annulus: The space between the easing inside wall and the outside of the drill string providing a return path for the drilling fluid to the surface and mud pits. API: American Petroleum Institute ASME: American Society of Mechanical Engineers BHA: Bottom Hole Assembly Blind Ram (BOP): See BOP. A BOP with ram blocks designed to mate against each other when closed to seal off the wellbore when the well bore is open. BOP Ram Type: A device designed or form a seal on the hole with no pipe or in the annular space with pipe in the hole. The equipment can use pipe rams, blind rams, or blind/shear/cutter rams to effect the required seal, according to equipment availability, arrangement of the equipment, and/or existing well conditions. Pipe rams have ends contoured to seal around pipe to close and seal the annular space. Blind rams have ends not intended to seal against any tubulars, rather they seal against each other to effectively close and seal the wellbore. Blind/shear/cutter rams are blind rams equipped with a built-in cutting edge that will shear tubulars that may be in the hole, thus allowing the blind rams to close against each. BOP Preventer Stack: The assembly of well control equipment including preventers, spools, valves, and nipples connected to the top of the casing-head. BOP Preventer Test Tool: A tool to allow pressure testing of the blowout preventer stack and accessory equipment b sealing the wellbore immediately below the stack. Choke Line: A high pressure line connected below a BOP to transmit fluid flow to the choke manifold during well control operations. Choke Manifold: An assembly of valves, chokes gauges, and lines used to control the rate of flow from the well when the blowout preventers are closed. Choke Valve: A valve that permits flow in one direction only. Closing Unit: See Accumulator Unit. Conductor Casing: The first string of pipe cemented in the well on which the casing head is attached for mounting BOP's. The first pipe intended to contain pressure. Dead Band: Term used to describe the change in regulated pressure required before a hydraulic pressure regulator automatically adjust to the change. Also called search band. Drilling Spool: A connection component with ends either flanged or hubbed. It must have an internal diameter at least equal to the bore of the blowout preventer and can have smaller side outlets for connecting auxiliary lines.

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Fail Safe: This is said of equipment or a system so constructed that, in the event of failure or malfunction of any part of the system, devices are automatically activated to stabilize or secure the safety of the operation. Subsea failsafe valve in designed to "Fail Safe" close (spring loaded) should hydraulic operating pressure be lost. Floater: Floating Drilling Rig. Drill ship or semi-submersible vessel where the BOP stack is installed at the sea floor. Hydraulic Control Manifold: The assemblage of regulators and hydraulic control valves used to operate the BOP and well pressure control valves. Normally part of the accumulator unit. IADC: International Association of Drilling Contractors Influx: See Kick. Kick: Intrusion of gas into the well due to an unbalanced condition where hydrostatic pressure in the well is insufficient to prevent the entrance of the higher pressure. Kill Line: A high pressure line between the rig pumps or cement pump to a connections below a BOP. This line allows fluid to be pumped into the well or annulus with the BOP closed during well control operations. Leak Off Test: A pressure test to determine the integrity of the casing, cement or shoe. Establishes the maximum pressure allowed before migration of the drilling fluids into the formation. Marine Drilling Riser: A tubular conduit serving as an extension of the well bore from the equipment on the wellhead at the seafloor to a floating drilling rig. MMS: Minerals Management Service Nipple Down: Disassembly of well control equipment and Precharge: The initial nitrogen charge in the accumulator. The nitrogen gas charge is compressed by the pumps hydraulically charging the accumulators and is used to expel the fluid when the pumps are off. PSI: Pounds per square inch. Pressure. Ram: The closing and sealing component on a blowout preventer. Rams are of three types: blind, pipe, and shear. Pipe rams, when closed, have a configuration such that they seal around the pipe; shear rams cut through drill pipe and then form a seal. Blind rams seal on each other with no pipe in the hole. Ram BOP: A blowout preventer that uses rams to seal off pressure in the well bore; also called a ram preventer. Riser Joint: A riser joint consists of a section of pipe, with couplings on each end. It may have provision for supporting integral and non-integral auxiliary lines (flowlines, choke and kill lines, control bundles, etc.) and buoyancy devices. Rotating Head: A rotating pressure-sealing device used in drilling operations utilizing air, gas, foam, or any other drilling fluid whose hydrostatic pressure is less than the formation pressure. Shear Ram (BOP): See BOP. A BOP with ram blocks designed to cut the drill pipe and seal the wellbore in an emergency. Normally for subsea BOP stacks. Shoe: Established at the bottom end of the conductor easing by cementing. See leak off test and conductor casing. Stripping: The process of running the drill string into or out of the well under "Kick" conditions (see Kick). Normally through a closed annular BOP but may be run ram-to-ram by carefully closing, bleeding off pressure and opening rams to pass tool joints and collars.

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Swabbing: The lowering of the hydrostatic pressure in the hole due to upward movement of pipe and/or tools. Trip: Running the drill string into or out of the well. Usable Fluid: The hydraulic fluid volume recoverable from the accumulator system between the maximum charging pressure and the minimum operating pressure of the accumulator. The minimum operating pressure is established by the pressure at which the precharge pressure closes the accumulator poppet valve stopping further flow from the accumulator. The poppet valve prevents loss of the nitrogen precharge into the hydraulic control lines. WP: Working Pressure (also design working pressure or maximum working pressure). The normal operating pressure to which a component is designed to operate continuously with a safe margin below the point at which the material will yield or burst.

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Chapter L: Derricks and Masts

Chapter L Derricks and Masts

International Association of Drilling Contractors

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Table of Contents - Chapter L Derricks and Masts L-1 Ratings of L Derricks and Masts ........................................................................................................ L-4 Ratings ............................................................................................................................................... L-4 L-2 Inspection Report of Derricks and Masts .......................................................................................... L-20 Derricks And Masts ......................................................................................................................... L-20 A. Derricks And Masts ..................................................................................................................... L-21 B. Substructure And Vertical Extension ............................................................................................. L-25 C. Deadline Anchor And Supports .................................................................................................... L-26

L-2

International Association of Drilling Contractors

Chapter L: Derricks and Masts

CHAPTER L Derricks and Masts The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study.

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IADC Drilling Manual - Eleventh Edition

L-1 Ratings of L Derricks and Masts Ratings The ratings published in this section of the Drilling Manual are those established by the individual manufacturers. They are the maximum ratings for new structures and must not be exceeded. Caution is suggested any time you approach the upper limits of these ratings, a cracked weld, a missing bolt or pin, a leg with a slight bow, metal fatigue and many other factors can cause the structure to yield or fail when highly stressed.

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International Association of Drilling Contractors

Chapter L: Derricks and Masts

Dreco Inc.

International Association of Drilling Contractors

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Dreco Inc.

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International Association of Drilling Contractors

Chapter L: Derricks and Masts

Dreco Inc. Offshore Derricks Vertically Assembled "Bootstrap" Masts For Fixed Offshore Platforms Vertically Telescoping Masts For Fixed Offshore Platforms Free Standing Telescoping Blasts For Land Rigs

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IADC Drilling Manual - Eleventh Edition

Guyed Masts For Wheel Mounted Land Rigs Angle Leg*, Floor Mount, Cantilever Masts Beam Leg, Floor Mounted, Cantilever Masts Raised Floor Masts Beam Leg, Folding Masts Dreco Slingshot Substructure

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Chapter L: Derricks and Masts

IRI International Corp

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L-9

IADC Drilling Manual - Eleventh Edition

IRI International Corp. - (IRI/Ingersoll-Rand Oilfield Products Co./Cabot/Franks) Tilted Masts - Self-Propelled or Trailer Mounted Vertical Masts - Drilling and Offshore IDECO Masts - Full View Series Dualift Series Kwik-Lift Series High Floor Series

L-10

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Chapter L: Derricks and Masts

LTV Energy Co.

LTV Energy Co. - LTV Energy Products Company) EMSCO Derricks Derricks for Platform and Jackups

International Association of Drilling Contractors

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IADC Drilling Manual - Eleventh Edition

Derricks for Semi-Submersibles and Drillships Cantilever Masts NOTES: All dimensions are nominal. Extended heights and guide tracks available on most models for top drive application.

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International Association of Drilling Contractors

Chapter L: Derricks and Masts

Pyramid Manufacturing Co.

International Association of Drilling Contractors

L-13

IADC Drilling Manual - Eleventh Edition

Pyramid Manufacturing Co. Swing-Up Hast On Froot Hast Dynamic Mast Dynamic Derricks NOTE: Hook loads will vary depending on the dynamic conditions of the rig.

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International Association of Drilling Contractors

Chapter L: Derricks and Masts

Woolslayer Companies, Inc.

International Association of Drilling Contractors

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L-16

International Association of Drilling Contractors

Chapter L: Derricks and Masts

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Woolslayer Companies, Inc. Single Trailer Mounted Masts Dual Trailer Mounted Masts Standard Cantilever Masts Cantilever Masts "Dynamic" Cantilever Type Masts Raised Floor Cantilever Type Masts Raised Floor Cantilever Masts Vertically Telescoping Masts

L-18

International Association of Drilling Contractors

Chapter L: Derricks and Masts

Folding Masts "Dynamic" Derricks

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L-2 Inspection Report of Derricks and Masts Derricks And Masts All derricks and masts should receive periodic inspection as outlined in Section L-2 of this manual; however, if any section or part of the structure is damaged or if concealed damage is detected, report it immediately and paint the damaged area with a highly contrasting color of paint. Even slight damage in certain areas may be sufficient cause to condemn the structure until it can be repaired. Contact the manufacturer, give him the size, type and serial number of your structure; detail the damage for him and follow his advice concerning structure loading and repairs. An example of Reports of Visual Field Inspection of Derricks or Masts and Substructures follows. *A Joint Publication by the American Petroleum Institute and the International Association of Drilling Contractors -- December 1971.

Purpose And Scope Of Inspection. This report form and inspection procedure was developed as a guide for making and reporting field inspections in a thorough and uniform manner. It has been approved for reference in API RP 4G, Appendix A: Recommended Practice for Maintenance and Use of Drilling and Well Servicing Structures. The procedure is intended for use by operating personnel (or a designated representative) to the extent that its use satisfies conditions for which an inspection is intended. More detailed and critical inspections may be scheduled periodically, or ordered to supplement a program of these inspections; if masts or derricks are used in the upper range of their load limits, or if structures may have been subjected to critical conditions which could affect safe performance.

Marking Damage. At the time of inspection, damaged sections or equipment must be clearly and visibly marked so that needed repairs may be made. A bright, contrasting spray can paint is suggested for this. When repairs are made, the visible markings should be removed by painting over them. It is also necessary for the inspector to write "None" when no damage markings are needed, as this is his indication that the item has passed inspection. It is recommended that inspection be made with assistance of manufacturer's assembly drawing and operating instructions. For items not accessible or that do not apply, draw a line through the item pertaining to the component.

Bolted Structures. Section XIV is provided for a rig builder to use in reporting the results of his inspection and tightening bolted connections, in making an inspection of a standing derrick. The rig builder is also to make inspection and report his findings as called for in Sections III, IV, VI, VII, IX, X, and XV. Report Of Visual Field Inspection Of Derrick Or Mast And Substructure* Company Name _______________________ Rig No _______________________ Location _______________________

Date

_______________________

Mast/Derrick Identification _______________________ Serial No. _____________ Rig Standing __________ ft Lying Down _________ ft Disassembled ________ ft Inspected By _______________________

Representing ____________________

Original Of Report Sent To _______________________ _______________________

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Chapter L: Derricks and Masts

A. Derricks And Masts I. Crown Assembly A. Sheaves No. ___________ Main Cluster Size ____________ Fastline Size ________________ B. Condition 1.

Sheaves: Warped ______________________________________________ OK _______ Groove: Worn

2.

_____________________________________________ OK _______

Spacers Or Seals: Bad ________________________________ ___________OK _______ Grease Fitting: Missing ___________________________________________OK _______

3.

Bearings: Loose _______ Bad ____________________________________ OK _______

4.

Crown Safety Platform: Minor Damage ___ Badly Damaged _____________OK _______

5.

Handrails: Minor Damage__________ Badly Damaged _________________ OK _______ Cracked Welds _________________________________________________ OK _______

6.

Crown Frame: Bent Beam Flanges____ Beam Webs Bent _______ Cracked Welds __________________ Location ____________

7.

Comment: Rusty ______________ Needs Repairs ______________ Needs Painting _______________ Other ______________________

8.

Number Of Visible Marks Applied _____________________________

II. Additional Sheave Assemblies: Name ________________________________________________________ OK _____ Or _________________ No. of Visible Marks Applied _________________________ III. Crown Support Beams Beam Flanges Bent ____ Beam Webs Bent ________Cracked Welds _________ Needs Repair ________ No. Of Visible Marks Applied ________________ OK _____ IV. Legs A.Front Leg, Drillers Side: Slight Bow _________Bad Bow ___________ Needs Repairing _________ OK ______ Pin Connections: Bad ___________________________________________ OK ______ Pin Hole: Bad ________ Cracked Welds ____________________________ OK ______ Safety Pins: Missing ____________________________________________ OK ______ B.Front Leg, Off-drillers Side: Slight Bow _________Bad Bow ___________ Needs Repairing _________ OK ______

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IADC Drilling Manual - Eleventh Edition

Pin Connections: Bad ________________________________________ OK ______ Pin Hole: Bad ________ Cracked Welds _________________________ OK ______ Safety Pins: Missing _________________________________________ OK ______ C. Rear Leg, Drillers Side: Slight Bow _________Bad Bow ___________ Needs Repairing ______ OK ______ Pin Connections: Bad ________________________________________ OK ______ Pin Hole: Bad ________ Cracked Welds _________________________ OK ______ Safety Pins: Missing _________________________________________ OK ______ D. Rear Leg, Off-drillers Side: Slight Bow _________Bad Bow ___________ Needs Repairing ______ OK ______ Pin Connections: Bad ________________________________________ OK ______ Pin Hole: Bad ________ Cracked Welds _________________________ OK ______ Safety Pins: Missing _________________________________________ OK ______ E. Number Of Visible Marks Applied _______________________________ V. Spreaders (Back Panel Trusses) Slight Damage __________ Badly Damaged __________ Cracked Welds _________ Needs Repairs _______________________________________________ OK ______ Bolt And Pin: Improper Length __________________________________ OK ______ Safety Pin: Missing ____________________________________________OK ______ Bolt And Pin Holes: Oval _______________________________________OK ______ Number Of Visible Marks Applied _________________________________ VI. Girts And Bracing Bent _______________________________________________________ OK ______ Number Bent: Slight _________ Badly ________ Cracked Welds __________ Need Repairs __________________________________________ Number Of Visible Marks Applied ___________________________________ VII. Feet Or Pivots Damaged _______ Cracked Welds _________ Corroded ________ Worn Holes _____ Worn Pins ______________ Needs Repairs __________________ OK _______ Number Of Visible Marks Applied ___________________________________ VIII. A-Frame A.

L-22

Legs: Damaged Members _______________ Cracked Welds __________ OK ______

International Association of Drilling Contractors

Chapter L: Derricks and Masts

B.

Spreaders Or Trusses: Damaged Members ______ Cracked Welds _____ OK ______

C.

Upper Connections: Damaged ___________ Cracked Welds __________ OK ______

D.

Raising Sheaves And Shafts: Damaged ___________________________ OK ______ Lubrication: _________________________________________________ OK ______ Fairings: Missing _____________ Cracked Welds ___________________ OK ______

E.

Lower Connections: Corroded ____________________________________ OK ______ Pin Connections: Loose ________________________________________ OK ______ Pin: Worn ___________________________________________________ OK ______ Safety Pin: Missing ____________________________________________ OK ______

F.

Number Of Visible Marks Applied ____________________________________

IX. Working Platforms A.

Racking Platform: Frame: Damaged ________________ Cracked Welds _________________ OK ______ Pin Connections: Worn __________________________________________ OK ______ Safety Pins: Missing ____________________________________________ OK ______ Fingers: Damaged _______ Cracked Wolds _________ Needs Repairs _____ OK _____

B.

Rod Hangers: Frame: Damaged _______________________________________________ OK ______ Fingers: Damaged ______________________________________________ OK ______ Basket: Damaged

____________ Cracked Welds _____________________ OK ______

C.

Working Platform: Damaged ____________ Cracked Welds _______________ OK ______

D.

Tubing Support Frame: Damaged ____________________________________ OK ______ Connections: Damaged __________ Cracked Welds _____________________ OK ______

E.

Handrails: Damages: Minor _______ Major ____________ Cracked Welds _____________ OK ______ Connections: Need Repairs __________________________________________ OK ______

F.

Number Of Visible Marks Applied ________________________________________

X. Ladders Cracked Welds __________ Bad Rungs ___________ Bad Connections _______ OK _______ Damages: Minor ____________________ Major __________________________ Number Of Visible Marks Applied _______________________________________

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IADC Drilling Manual - Eleventh Edition

Xl. Raising And Telescoping System A. Wireline System - Refer To API Std. 4E For Specifications

B.

1.

Wireline: Frayed __________ Kinked ____________ Corroded ____________OK ______

2.

No. of Cable Clamps: Loose.____________ Properly Installed: ____________ OK ______

3.

Sheaves And Mountings: Damaged ___________________________________OK _____

4.

Equalizer Assembly: Damaged ______________________________________ OK _____

6.

Sockets And Pins: Damaged.________________________________________ OK _____

Hydraulic System: 1.

Hydraulic Cylinders: a. Raising: Leaking ________ Exposed Surface _________ Corroded _______ OK ______ b. Scoping: Leaking ________ Exposed Surface _________ Corroded _______ OK ______

2.

Connections: Leaking ______________________________________________ OK _____

3.

Hoses and Hose End Fitting: Exposed Wire _________ Corroded __________ Damaged _________________________________________________________ OK _____

4.

Pin Holes: Oval ____________________________________________________ OK _____

5.

Scoping Cylinder Stabilizers: Bent _____________________________________ OK _____ Lubrication:________________________________________________________OK______

C.

Mast Guides: Cleaned And Lubricated _____________ Needs Attention ________ OK ______

D.

Number Of Visible Marks Applied _______________________________________

XII. Locking Device and Seats -- Telescoping Masts A.

Pins, Bars or Pawls: Damaged _________________________________________ OK _____

B.

Seats: Deformed ___________________________________________________ OK _____

C.

Mechanism: Damaged __________ Needs Cleaning and Lubrication. ___________ OK _____

D.

Number Of Visible Marks Applied _________________________________________

XIII. Guylines Anchorage

L-24

A.

Guyline: Damaged ______ Needs Adjusting _________ Needs Replacing ________ OK _____

B.

Cable Clamps: Loose ______ Properly installed _______ Some Missing __________ OK _____

C.

Pins And Safety Pins: Missing ___________________________________________ OK _____

D.

Turnbuckles: Locked ___________ Damaged ___________ Replace ____________ OK ______

E.

Anchor and Deadmen: Replace __________________________________________ OK _____

F.

Number Of Visible Marks Applied ________________________________________ OK_____

International Association of Drilling Contractors

Chapter L: Derricks and Masts

XIV. Bolted Structures All bolted connections are to be inspected, tightened, and missing parts replaced or visibly marked as missing or damaged and in need of repair. A. All bolted connections found to be satisfactory as checked and loose bolts tightened, or

OK ______

B. All bolted connections visually inspected end spot checked for tightness and no further bolt -tightening or repairs necessary.__________________________________________________________ OK _______ C. Number Of Visible Marks Applied ____________________________________________ XV. Summary Of Inspection A.

Was Manufacturer's Assembly Drawing Used? _______ Yes _________ No

B.

Appearance: Good _______________ Fair ______________ Poor _______________

C.

Repairs Needed: None __________ Minor ____________ Major ______________

D.

Number Of Missing Parts _________________________________________________

B. Substructure And Vertical Extension I. Shoes, Pedestals, Or Pivots: Damaged Holes: Worn __________________________________________________________OK _____ Bolts: Need Replacing __________________________________________________OK _____ Pins: Worn __________________________________________________________ OK _____ Safety Pins: Missing ___________________________________________________ OK _____ Support Beams: Damaged _________________ Corroded ____________________ OK _______ Number Of Visible Marks Applied ____________________________________________ II.

Flooring: Damages: Minor _________________________ Major _______________________ OK _____ Number Of Visible Marks Applied _______________________________________ OK ______

III. Substructures For Derrick Or Mast Damages: Minor

_________________________ Major _________________________ OK _______

Corrosion: Minor

_______________ Major _______________None _______________ OK ______

Connections: Worn __________________ Cracked Welds ________________________ OK ______ Safety Pins: Missing ______________________________________________________ OK _____ Number Of Visible Marks Applied ____________________________________________________ IV. Subspreaders and Rotary Beams: Damages: Minor

_________________________ Major _________________________ OK _______

Corrosion: Minor

_________________Major ______________None _______________ OK ______

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IADC Drilling Manual - Eleventh Edition

Connections: Worn __________________ Cracked Welds ___________________OK ______ Safety Pins: Missing _________________________________________________OK _____ Number Of Visible Marks Applied ________________________________________________ V. Engine Foundation: Damages: Minor

_________________________ Major ____________________OK _______

Corrosion: Minor

_____________ Major _______________None ____________ OK ______

Connections: Worn __________________ Cracked Welds ___________________ OK ______ Safety Pins: Missing _________________________________________________OK _____ Number Of Visible Marks Applied ____________________________________________________ VI. Engine Foundation Spreaders: Damages: Minor

_________________________ Major ____________________OK _______

Corrosion: Minor

________________Major ________________None _________OK ______

Connections: Worn __________________ Cracked Welds ___________________OK ______ Safety Pins: Missing _________________________________________________OK _____ Number Of Visible Marks Applied ____________________________________________________ VII. Stairways, Landings, And Handrails: Damages: Minor

_________________________ Major ____________________OK _______

VIII. Hold Down And Anchoring Connections: Bolts Tight Bolts ______ Missing ______ Damaged _______Needs Repairing _____OK ________ IX. Foundation: Adequate: Yes _____________ No __________ Why ___________________________________ X.Summary Of Inspection: A.

Was Manufacturer's Assembly Drawing Used? _______ Yes _________ No

B.

Appearance: Good _______________ Fair ______________ Poor _______________

C.

Repairs Needed: None __________ Minor ____________ Major ______________

D.

Number Of Missing Parts _________________________________________________

C. Deadline Anchor And Supports I. Deadline Anchor: Damaged ___________________ Corroded ___________________________ OK _____ II. Supports: Damaged

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____________________ Corroded _____________________ OK _____

International Association of Drilling Contractors

Chapter L: Derricks and Masts

Bolts: Need Replacing ______________________________________________ OK _____ III. Number Of Visible Marks Applied ______________________________________________ Remarks and References To Additional Special Inspection Reports: ____________________________________________________________________________________ _______________________________________________________________________________________________ ___________________________________________________________________________________________ _____________________________________________________________________________________ ____________________________________________________________________________________ _____________________________________________________________________________________ ____________________________________________________________________________________

International Association of Drilling Contractors

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Chapter M: Wire Rope

Chapter M Wire Rope

International Association of Drilling Contractors

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IADC Drilling Manual - Eleventh Edition

Table of Contents - Chapter M Wire Rope M1. Wire Rope: Specifications ................................................................................................................. M-4 I. Introduction .................................................................................................................................... M-4 II. Definition ...................................................................................................................................... M-4 III. Wire Rope Nomenclature ............................................................................................................. M-4 IV. Wire - Rope Sizes And Constructions ........................................................................................... M-6 M2. Care And Handling Of Wire Rope .................................................................................................. M-15 I. Field Care And Use Of Wire Rope ............................................................................................... M-15 II. Socketing Of Wire Rope ............................................................................................................. M-24 III Attachment Of Wire Rope Claps To Wire Rope .......................................................................... M-27 IV. Casing-line And Drilling Line Reeving Practice ............................................................................ M-32 M3. Factors Affecting Service Life Of Wire Rope .................................................................................. M-38 M4. Ton Mile Calculations ..................................................................................................................... M-40 A. Introduction ................................................................................................................................ M-40 B. Examples Of Ton-mile Calculations .............................................................................................. M-44 C. Ton-miles Per Foot Cut ............................................................................................................... M-48 D. Ton Mile Calculations - Drilling Ton Miles for Top Drive (Drilling with Stands) ...................................................................................................................................... M-49 M5. Cut-off Program ............................................................................................................................. M-50 C. Union Wire Rope Cut-Off Program For Rotary Drilling Line ........................................................ M-51 M-6 Drum And Reel Capacity ............................................................................................................... M-84 A. Design Factor ............................................................................................................................. M-84 B. Design Factor Charts .................................................................................................................. M-90 M-7 Wire Rope - Ton Mile Calculations - Special Applications ............................................................ M-105 M-8 Appendix - Ton Mile Formulas .................................................................................................... M-109 1. Round-Trip Operations: ............................................................................................................. M-109 2. Drilling Operations: .................................................................................................................... M-109 3. Coring Operations: .................................................................................................................... M-110 4. Setting Casing Operations: .......................................................................................................... M-111 5. Short Trip Operations: ................................................................................................................ M-111

M-2

International Association of Drilling Contractors

Chapter M: Wire Rope

CHAPTER M Wire Rope The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study. This chapter was updated under the direction of Mr. Bruce Harwell of DI Industries, Inc.

International Association of Drilling Contractors

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M1. Wire Rope: Specifications I. Introduction The drilling line is a machine. It is an assembly of precision parts, each part can move independently, requires lubrication, is static until an external force is applied and it transmits energy. The information which follows will guide you in the selection, care and use of drilling lines. Instructions are included for attaching wire rope clips, socketing wire rope, seizing wire rope, etc. To keep the wire line costs at a minimum the rig crews and all levels of operations management should know how to obtain maximum safe life from the drilling line. The following is basic to that objective. a. Select the proper size and type line to meet the requirements. b. Care for the line to prevent damage. c. Compute the service obtained from the line in Ton Miles. d. Choose a cutoff program which best suits your conditions and follow it carefully. This will greatly increase the service obtained from the line. When a new line is received, the reel number, make and description of the line should bc recorded on the daily drilling report. The ton mile service should bc computed daily and a record kept so cut-offs can bc made at~cr a proper interval of service.

II. Definition Drilling lines and wire lines are known as and are used interehangeably with the term "wire rope". Reference to all three of these terms will be prevalent throughout this manual. Wire Rope is an intricate network of close tolerance, precision made steel wires, much on the order of a machine, where each part has a job to do. Each part must work in a perfect relationship with the other part for the rope to properly function. Proper care and handling is mandatory to receive the highest service at the highest level of safety.

III. Wire Rope Nomenclature Wire Rope is composed of three parts; the CORE, the STRAND and the WIRE (Figure M1-1).

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International Association of Drilling Contractors

Chapter M: Wire Rope

Figure M1-1 Wire Rope Nomenclature

Become familiar with each part; it is surprising how many times a "wire" is reported to be a "strand". Each of the components are detailed later. Wire rope is described and identified with numerals and abbreviations. It is important to understand these terms and to relate them to the wire rope specified within our industry. The following is an example description of a rotary drilling line; the identifying terms are translated and explained individually: 1" x 5000' 6 x 9 S PRF RRL IPS IWRC 1"

= Diameter of Line

500' = Length of Line 6

= Number of Strands per Line

19

= Number of Wires per Strand

S

= Seale Pattern

PRF = Preformed Strands RRL = Right Regular Lay IPS

= Improved Plow Steel

IWRC = Independent Wire Rope Core This translates to a 1" diameter, 5000 foot length of 6-strand rope with 19 wires in each strand laid in a Seale pattern (S). The strands are preformed (PRF) in a helical shape before being laid in a Right Regular Lay (RRL) pattern. The grade of the rope is Improved Plow Steel (IPS) and it has an Independent Wire Rope Core (IWRC). Refer to Table M1-3 for typical wire rope used for oil field service

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IADC Drilling Manual - Eleventh Edition

Table M1-3 Sizes and Constructions of Wire Rope for Oilfield Service

IV. Wire - Rope Sizes And Constructions Diameter Diameter measurements are correct only when made across the "crowns" of the rope strands so that the true diameter is the widest diameter of the rope. Always rotate the caliper on the rope - or rotate the rope inside the caliper to take the measurement. Figure M1-2 Correct and Incorrect Ways to Measure Wire Rope Diameter

Always measure The diameter of any rope at its widest point by turning the caliper on the rope. Most ropes are manufactured larger than the nominal diameter. When first placed in operation strands of new unused rope will "scat in" and "pull down" from its original diameter. Therefore, measurements recorded for future reference and comparison should be taken after the rope has been in service for a short period of time. Table M1-1 Rope Diameter vs. Tope Dia. ins Tol(under,%) 3/16 0 7/32 0 1/4 0 5/16 0 >3/8 0

Tolerances. Tol(over,%) 7 6 6 6 5

A question may develop as to whether or not the wire rope complies with the oversize tolerance. In such eases, a tension of not less than 10 percent nor more than 20 percent of nominal strength is applied to the rope and the rope again measured while under this tension. Wire rope differs in the number of strands and the number and pattern of wires per strand. Most common wire rope constructions are grouped into four standard classifications, based on the number of strands and wires per strand, as shown in Table M1-2:

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International Association of Drilling Contractors

Chapter M: Wire Rope

Table M1-2 Classifications and Construction Classification # of Strands Wires / Strand 6x7 6 7 6x19 6 16-->>27 6x37 6 27-->>49 8x19 8 16-->>26

The number of strands and the number of wires per strand determine the classification of a rope. Within each classification there are specific rope constructions. For example: in the 6 x 19 class some of the rope constructions are 6 x 19 S (scale), 6 x 25 FW (filler wire) and 6 x 26 WS (Warrington scale). Characteristics, such as fatigue resistance and resistance to abrasion, are directly affected by the design of strands. As a general rule, a strand made up of a few large wires will be more abrasion resistant and less fatigue resistant than a strand of the same size made up of many smaller wires.

Basic Strand Constructions Single Layer The "Single Layer principle" is the basis of this strand construction. The most common example is a single wire center with six wires laid around it. It is called a 7-wire (1 - 6) strand. Figure M1-3: Single Layer Wire Rope (7-Wire)

Filler Wire This construction has two layers of same size wires around a center wire, with the inner layer having half the number of wires as the outer layer. Small filler wires, equal in number to the inner layer, are laid in the valleys of the inner layer.

International Association of Drilling Contractors

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IADC Drilling Manual - Eleventh Edition

Figure M1-4: 25 Filler Wire (1-6-6f-12) strand

Seale The Seale Construction has two layers of wires around a center wire with the same number of wires in each layer. All wires in each layer are the same diameter and the strand is designed so that the larger outer wires rest in the valleys between the smaller inner wires. Figure M1-5: 19 Seale (1-9-9) strand

Warrington The Warrington Construction has 2 layers of wires. The inner layer is a single size of wire and the outer layer has two diameters of wire, alternating large and small. The larger outer layer wires rest in the valleys and the smaller ones on the crowns of the inner layer.

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Figure M1-6: 19 Warrington (1-6-(6+6)) strand

Combined Patterns When a strand is formed in a single operation using two or more of the foregoing constructions, it is referred to as a "combined pattern". Beginning from the center wire, the first two layers constitute a Seale pattern. The third layer, with two different wire sizes is a Warrington pattern. The fourth layer of the same diameter wires form a Seale pattern. Figure M1-7: 49 Seale Warrington Seale (1-8-8-(8+8)-16) strand

Preforming Preforming is a process by which strands are helically formed into the shape they will assume in the finished rope. Preforming improves fatigue resistance, ease of handling, and resistance to kinking in a rope by equalizing the load among the strands and among the individual wires of strands. When a preformed rope is cut, the end does not unlay. If strands are unlayed from the rope, they retain their helical shape. When a non-preformed rope is cut, it will open up or "broom" unless the end has been secured (seized) before cutting.

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The superior qualities of preformed ropes result from wires and strands being "at rest" in the rope which minimizes internal stresses within the rope. Because wires and strands are free to move and slide in relation to each other when the rope bends, the rope can adjust more easily while operating on sheaves or drums. Unless otherwise indicated in the rope description, ropes are preformed. Lay The first element in describing lay is the DIRECTION strands lay in the rope - Right or Left. When you look along a rope, strands of a Right Lay rope spiral to the right. Left Lay spirals to the left. Figure M1-8: Right-Lay, Regular-Lay Wire Rope

The second element in describing lay is the relationship between the direction the strands lay in the rope and direction the wires lay in the strands. In Regular Lay, wires are laid opposite the direction the strands lay in the rope. In appearance, the wires in Regular Lay are parallel to the axis of the rope.

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Figure M1-9: Left-Lay Regular-Lay Wire Rope

In Lang Lay, wires are laid the same direction as the strands lay in the rope and the wires appear to cross the rope axis at an angle. Figure M1-10: Right-Lay Lang-Lay

The third element in describing lay is that one rope lay is the length along the rope axis which one strand uses to make one complete helix around the core.

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Figure M1-11 One Rope Lay

Grades Today the greatest portion of all wire rope is made in two grades: Improved Plow Steel (IPS) and Extra Improved Plow Steel (EIP). Virtually all Rotary Drilling Lines are of one of these grades. The grade of rope refers to the strength of a new unused wire rope. Standard 6 strand EIP ropes within the same classification and having an IWRC have a nominal strength 15% higher than IPS ropes. Another grade of rope used in the oilfield is extra extra improved plow steel (EEIP), which has a nominal strength 10% higher than EIP ropes. Galvanized ropes are those in which the individual wires have had a zinc coating applied to their surface to provide increased corrosion resistance. The proper grade of rope to use depends on the specific characteristics of the application.

Cores Wire rope cores are usually one of three types: 1.Fiber Core (FC): Either of natural fiber such as sisal or man-made fiber such as polypropylene. Figure M1-12a Fibre Core Wire Rope

2. Independent Wire Rope Core: Literally an independent wire rope which is called IWRC.

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Figure M1-12b IWRC Wire Rope

3. Strand Core: Strand made up of wires. Figure M1-12c Strand Core Wire Rope

The primary purpose of a core in wire rope is to provide a foundation or support for the strands. Approximately 71/ 2% of the nominal strength of a 6 strand IWRC rope is attributed to the core.

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Table M1-3 Sizes and Constructions of Wire Rope for Oilfield Service

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Chapter M: Wire Rope

M2. Care And Handling Of Wire Rope I. Field Care And Use Of Wire Rope A. Handling on Reel 1. Use of Binding or Lifting Chain: When handling wire rope on a reel with a binding or lifting chain, wooden blocks should always be used between the rope and the sling in order to prevent damage to the wire or distortion of the strands in the rope. 2. Use of Bars: Bars for moving the reel should be used against the reel flange, and not against the rope. 3. Sharp Objects: The reel should not be rolled over or dropped on any hard, sharp object in such a manner that the rope will be bruised or nicked. 4. Dropping: The reel should not be dropped from a truck or platform. Thus may cause damage to the rope as well as break the reel. 5. Mud, Dirt, or Cinders: Rolling the reel in or allowing it to stand in any medium harmful to steel such as mud, dirt, or cinders should be avoided. Planking or cribbing will be of assistance in handling the reel as well as in protecting the rope against damage. 6. Corrosion: To minimize the effects of corrosion on wire rope, care should be taken to store and lubricate the wire rope properly. Corrosion may be particularly severe in environments containing high concentrations of salt or acid. Corrosion reduces a wire rope's strength, resistance to fatigue, and service life. 7. Welding and Flame Cutting: Never use your wire rope in an are welding circuit. The grounding clamp can are or the individual wires can are and damage the line. If using a torch near the wire rope, always protect the rope from the flame and sparks.

B. Proper Steps in Stringing Line 1. Preliminary work: Attach the traveling block to the hang line, or otherwise support in a vertical position. The best position is where the elevators are in pick-up position near the rotary table. 2. Position of the Reel: Provide a permanent location for the reel of drilling line. This should be as close as practical to the dead-line anchor. The reel should be firmly supported on its horizontal axis with the line unwinding from beneath the reel drum (not from the top of the drum). 3. Stringing of Blocks: When leading the line from the reel to the first crown sheave use snatch blocks with large diameter sheaves to guide the line and keep it from rubbing on derrick members and other obstructions.

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4. Braking Reels: Brake the reel flanges so that the rope does not become loose on the reel while being unwound, and so an even tension is applied on the rope between the blocks; do not apply the brake on the rope itself. 5. Tension on Rope: Keep the line in tension to be sure that it is tightly wound on the drum. 6. Tight Spooling: The rope should be spooled under a sufficient load to insure tight spooling. 7. Swivel-Type Stringing Grip: To start stringing the rope, remove the old rope from the dead line anchor and fasten it to the new rope with a swivel grip. The grip becomes tighter as the load increases. This will prevent transferring the twist from one piece of rope to the other. Care should be taken to see that the grip is properly applied. 8. Winding Old Rope: Wind all the old rope on the draw works drum and pull enough of the new rope through to permit attaching to the drum. Keep as much back tension in the rope as possible, because slackness can cause loops and/or kinks to form. 9. Fastening New Line: Fasten the new line so that it will not run back through the blocks. Remove the swivel grip. Then lake the old line off the drum and transfer it to a storage reel. Attach the new line to the draw works drum and provide enough wraps so that the proper number will be on the drum at the pick-up point. 10. Number of Wraps on Draw Works Drum: When the traveling block is at the lower pick-up point, 69 wraps should be on the drum (if grooved). Plain faced drums must have a full layer of line plus 4-6 wraps on the second layer as needed. 11. Deadline Anchor: Hold down sheaves are the best way to anchor the line when cut-off practices are to be employed. Such sheaves should be of sufficient diameter to prevent dog-legging the line and should be at least 15 times the rope diameter. The line should go around the hold-down sheaves in the same direction as it comes over the dead-line sheave and from the storage reel. Never anchor the dead end of the line to a wooden or steel joist if you plan to utilize a cutoff procedure. Such practices will put severe dog-legs in line which will cause premature damage when this section is later moved into service. Great care must be exercised so that the deadline clamps do not kink, flatten, or otherwise crush or distort the rope. 12. Completing String-Up: After anchoring the deadline end, raise the traveling block and take off the supporting line. The block, hook and elevators may then be lowered through the V-door far enough to unreel the line on the drum, so that it can be rereeled tightly. 13. Break-in Period: Whenever possible, a new rope should be run under a light load for a short period after it has been installed. This will help to adjust the rope to working conditions. It is suggested that 15 cycles with 3 joints of pipe would be sufficient break-in. 14. New Coring or Swabbing Line:

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If a new coring or swabbing line is excessively wavy when first installed, two to four sinker bars may be added on the first few trips to straighten the line.

C. Care of Wire Rope in Service 1. Handling: The recommendations for handling as given under A and B inclusive, should be observed at all times during the life of the rope. 2. Design Factor: The design factor should be determined by the following formula: Design Factor = B/W Where: B = Nominal catalog strength of the wire rope, pounds W = Fast line load, pounds a. When a wire rope is operated close to its Minimum Design Factor, MDF, care should be taken that the rope and related equipment are in good operating condition. At all times, the operating personnel should use diligent care to minimize shock, impact, and acceleration or deceleration of loads. b. Successful field operations indicate the following should be regarded as minimum: Cable-tool line

3 MDF

Sand line

3 MDF

Rotary drilling line

3 MDF

Rotary drilling line when setting casing

2 MDF

Pulling on stuck pipe or infrequent operations

2 MDF

Mast raising and lowering line

2.5 MDF

c. Wire rope life varies with the design factor. Therefore longer rope life can generally be expected when relatively high design factors are maintained. 3. Application of Loads: Sudden, severe stresses are injurious to wire rope and such applications should be reduced 'to a minimum. A jerk line may be rigged and clamped to the drilling line when it is necessary to do considerable jarring in one place. 4. Operating Speed: Experience has indicated that wear increases with speed; economy results from moderately increasing the load and diminishing the speed. 5. Maximum Rope Speed: Excessive speeds when blocks are running up light may injure wire rope. For most drums a maximum rope speed of 4000 ft/min rope travel for hoisting or lowering is recommended. 6. Line Fatigue: Fast line fatigue is also caused by line whip and natural vibrations, therefore, a wire line stabilizer must be employed. Reverse bending at the deadline anchor or too small a diameter of the deadline sheave (crown block) may produce a set in the line which will cause excessive wear when a cut-off procedure is utilized.

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7. Sheave Maintenance: Vibration causes drilling line fatigue and shortens line life. Failure due to vibration is most serious at the deadline (crown block) sheave. This stationary point must absorb all the excess energy caused by line whip and vibration. Make certain the reeving system minimizes vibration. Considerable line whip results from fast line movement in the spooling process unless wire line stabilizers are used. As the line goes through sheaves its momentum tends to throw it outward, much as a car rounding a curve on the highway. It is prevented from doing this, however, by the tension on the line. This sudden angular acceleration and deceleration will produce vibrations, which in a long, unsupported, fast moving, flexible line, can result in severe whipping, if a stabilizer is not used. Wobbly sheaves can produce shimmying, which will induce vibration in the drilling line. This may lead to whipping. The wobble may also cause the line to receive abnormal wear from the sides of the sheaves which further reduces rope life. 8. Sheave Alignment: All sheaves should be in proper alignment. The last sheave should line up with the center of the hoisting drum. 9. Sheave Grooves: On all sheaves, the arc of the bottom of the groove should be smooth and concentric with the bore or shaft of the sheave. The centerline of the groove should be in a plane perpendicular to the axis of the bore or shaft of the sheave. Sheave grooves that have been altered by prior ropes are bound to shorten the life of new rope. From the standpoint of wire rope life, the condition and contour of sheave grooves are of material importance. Sheave grooves should be checked periodically with the gauge for worn sheaves and dimensions in Table M2-1 "Gauges for Worn Sheave Grooves." Table M2-1 Gauges For Worn Sheave Grooves

Notes on Table M2-1: * Groove oversize equals one half the wire rope oversize tolerance given in Table 4.1, Std 9A. ** Radius, Ro = 0.5 (Nominal Diameter + Groove Oversize) The sheave grooves should have a diameter of not less than that of the gauge; otherwise a reduction in rope life can be expected.

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Also see Table M2-2 Minimum Groove Radii for Worn Sheaves and Drums Table M2-2 Minimum Groove Radii for Worn Sheaves and Drums

Reconditioned sheave grooves should conform to the recommended radii for new and reconditioned sheaves as given in Table M2-3 "Groove Radii for New & Reconditioned Sheave Grooves." Table M2-3 "Groove Radii for New & Reconditioned Sheave Grooves

Each operator should establish the most economical point at which sheaves should be regrooved by considering the loss in rope life which results from worn sheaves as compared to the cost involved in regrooving. 10. Corrugated Sheaves: If rope is operated very long with heavy loads, or if the metal is too soft, scouring or corrugation of drums and sheaves will occur. When radial pressure causes corrugation in grooves, there is a filing action during every stop and start. When new rope is installed after such corrugations form, it's lay, doubtless, will not fit the imprints left by previous ropes and very rapid wear takes place.

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When these danger signs are found, it is economical to have the grooves turned smooth. In most cases, the sheaves should be replaced. In replacing the sheaves, make sure the metal is sufficiently hard to take the expected loading. Cast steel can stand only about 900 psi of pressure, but other alloy steels will take up to 2,000 psi and will stand wear much longer. If corrugations are occurring even with the best steel, chances are that the rope diameter is too small for the work load or not enough lines are being used between the blocks, or the sheave diameter is too small. Figure M2-P4. Grooves too small, just right, and too big

Notes on Figure M2-P Place sheave gauges in grooves as shown. Detail "A" reflects gauge fit in a sheave. Detail "B" reflects gauge "fit" in a worn (tight groove) sheave. Detail "C" reflects gauge "fit" in a sheave where the groove is too large. 11. Rope Inspection: Equipment that is not maintained properly not only deteriorates itself, but aids in destroying wire rope service life in the process. Frequent inspection of the equipment to determine it's operating condition and replacement of worn or broken parts is good economics when operating a rig. This is preventative maintenance versus remedial maintenance. 12. Fleet Angle: When a wire rope is led from the drum onto the last sheave, it is parallel to the sheave groove only when at one point on the drum, usually the center. As the rope departs from this point either way, an angle is created which starts wear on the side of the rope. This angle is called the fleet angle.

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The fleet angle although necessary, should be held to a minimum. Experience indicates that it should be held to less than 1-1/2 degrees for smooth faced drums and to less than 2 degrees for grooved drums. Any greater angle creates needless wear on the sides of the rope. This holds true for either grooved or smooth drums. Poor fleet angles cannot only cause excessive abrasive wear, but also build-up excessive torque in a rope. To check the fleet angle, Figure M2-1 can be used. This figure shows the relationship between the two critical dimensions used in calculating the fleet angle. See Figure M2-2. Fleet Angle Development The fleet angle is the included angle between a line representing travel of the rope across the drum and a line drawn through the center line of the lead sheave perpendicular to the axis of the drum. Fleet angles for several ratios of "A" & "B" are shown in Table M2-4. Table M2-4. Tangents of Fleet Angles

1. For Smooth Faced Drums, the Maximum angle = 1.5 degrees. 2. For Grooved Drums, the Maximum angle = 2.0 degrees. 3. The minimum angle should be at least 0.5 degrees. 13. Lubrication of Sheaves: In order to insure a minimum turning effort, all sheaves should be kept properly lubricated. 14. Worn Drums: Roughly worn drums may cause excessive wear on the rope. Corrugations cause cutting or ropes. 15. Drum Spooling: Heavy wear to a rotary line occurs while spooling on the drum. Each succeeding layer causes cross-over points and change of layer points. At the cross-over points and change of layer points where the rope climbs from one layer to the next, wear is usually severe. In the portion of the line that spools last when the blocks are raised and loaded, terrific cribbing and wear occur when the load of the drill string is suddenly lifted. In the portion of the line that lies next to the drum, it must withstand the loading of all the other layers, so the crushing is considerable. 16. Proper Spooling: Smooth faced drums are sometimes encountered, and the biggest problem is to get the line to spool evenly and smugly. Unless the rope is started correctly, the wraps in the first layer may tend to spread apart. This can accelerate the "cutting-in" of subsequent layers and the result in flattened, distorted or crushed rope and a loss of thread lay.

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On smooth face drums, where ropes operate on and off the first layer, right lay and left lay ropes are not interchangeable. The proper direction of rope lay is based on the location of the drum attachment and whether or not the spooling is underwind or overwind. The advantage of using the proper lay rope on a smooth drum is that rotation of the rope as it spools on the drum under tension will cause it to hug the preceding wrap. If the improper lay is used, The rope will try to open spool Care must be exercised to prevent over-run in paying out rope to avoid slack rope on the drum which causes excess abrasion on drum and rope at take-up. Slack rope has a tendency to slide across groove dividers which cuts the rope severely when loads are applied. Rope can be parted or severed with a quick take-up of slack. Drum grooves should be checked with a sheave gauge for proper contour before installing a new rope. 17. Poor Spooling: Poor spooling can sometimes be traced to the way the line leaves the dead end side of a smooth faced drum. If it leaves the flange at too great an angle, it maintains this angle all across the drums so that it leaves a big gap at the opposite flange. Thus successive layers of line cross over that initial layer sharply and will tend to cut at the gaps. Line crushing and shorter life result. It is most important to get the first drum layer full and tight without overcrowding so that it will support the succeeding layers. That is to say the first layer acts as a sort of a "grooving" for following layers. One way to assist proper drum winding is by means of a riser strip or wedge on the dead end side. These strips are as high as the rope diameter and taper from 0 to the diameter rope in width. The starter strip travels flush around the dead end flange, it keeps the first wrap straight and tends to eliminate the gap at the other flange. Piling up of wraps at the flange is prevented by turn-back rollers or kick plates. 18. Grooved Drums: Wear due to cross-over points cannot be completely avoided. It can be reduced by controlled spooling, which is provided by grooved drums. In any type of spooling there must necessarily be two crossover points with each wrap. As a lower layer proceeds in one direction across the spool, the next layer must proceed in the other direction. Along most of the turn the upper wrap rides in a groove between two wraps of the lower layer. The rope must leave this groove in order to cross to the next groove and in doing so, crosses over a wrap of the line in the lower layer. Two ropes are crossed over in each drum revolution. With smooth faced drums, and where wire line slipping is employed, new rope is spooled onto worn rope. The worn rope has a smaller diameter and when it is wound tight, the new line will not track. The new line instead will jump a wrap and leave a gap into which the line of the next layer will cut. Therefore, we suggest that slipping is only helping to temporarily relieve a wearing condition in the drilling line between blocks. 19. Pyramid Spooling: Utilizing grooving allows an upper layer of line to track a lower, despite the fact the lower layers may be worn. In this manner, cutting in is reduced. However, it is necessary that the grooving includes filler plates at each end so that when the second and following layers start, they start smoothly and leave no gap for cutting in. An improvement in spooling methods is the controlled cross-over system. This is a grooving system where the cross-over points are controlled thereby reducing wear and vibration. Instead of being a helical shape like a coiled spring, most of the grooves are parallel to the drum flanges. Normally at the cross-over points, pitch changes rapidly where the line is crossed from one groove to the next. In controlled spooling the change in pitch is less severe. In controlled pyramid spooling wear and cutting-in is parallel and there is no tendency for the line to slip over. 20. Counter-balanced Pyramid Spooling:

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Considerable vibration of the spooling drum and wire line at high speed results from the eccentricity of spooled line on the drum when one cross-over point is present. This makes the center of gravity slightly off center of the drum. Counter-balanced spooling was developed to overcome this problem. Counter-balanced Spooling consists of 2 cross-over points on opposite sides of the drum. This is achieved by making the pitch at each cross-over point only half that of the single cross-over drum. The grooves are still parallel, but those on one side of the drum are displaced half a groove width from those on the other side. This along with special pitch control bars at the flanges cause a line to move only 1/2 of the rope diameter at a time. 21. Block and Hook Weight: Slack line causes severe wear because of cutting and scrubbing of one layer of line against the next. This condition is most likely to occur when going back in the hole, where the traveling block is brought up fast with no load other than the weight of the block and hook to hold the line in tension. When the full load of the drill string is picked up from this position, the top layer from the drum may cut into the loosely spooled layers. To keep this line tight and to minimize the spooling damage to the line, it is important to use a heavy traveling block and hook. See Table M4-1 for theoretical weights of blocks, hooks, links and elevators. 22. Seizing of Wire Rope: Before cutting, a wire rope should be securely seized on each side of the cut by serving with soft wire ties. Either seizing strand or annealed wire may be used. For socketing, at least two additional seizings should be placed at a distance from the end equal to the length of the basket of the socket. For large ropes the seizing should be several inches long and securely wrapped. This prevents the rope untwisting and helps maintain equal tension in the strands when the load is applied. 23. Procedure for Seizing Wire Rope: The recommended procedure for seizing a wire rope as shown in Figure M2-3. a. The seizing wire should be wound on the rope by hand. The coils should be kept together and considerable tension maintained on the wire. Wind seizing strand around rope at least seven times. b. After the seizing wire has been wound on the rope, the ends of the wire should be twisted together by hand in a counterclockwise direction so that the twisted portion of the wires is near the middle of the seizing. c. Using "Carew" cutters, The twist should be tightened just enough to take up the slack. Tightening the seizing by twisting should not be attempted. Even though most wire ropes today are preformed, eliminating the tendency to "explode" or fly apart when cut, it is advisable to place seizings (or servings) securely on each side of the point where a cut is to be made. the important point is that servings be drawn taut enough to prevent any strand being even slightly displaced. While two servings are sufficient for a small diameter rope, three or more should be used for larger diameters. Recommended Sizes of Seizing Wire Rope Rope Diameter Inches

Strand

Strand Diam.

Or Use

Gauge

Inches

Annealed Wire

3/16 -- 3/8

25

1/16

No. 19

7/16 -- 5/8

22

3/32

No. 16

3/4 -- 1-3/4

19

1/8

No. 14

1-7/8 -- 3

17

5/32

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Note: At least two, and preferably three, servings should be placed on each side of point where rope is to be cut.

II. Socketing Of Wire Rope A. Zinc-Poured Socketing The following steps, in the order given, should be carefully adhered to. 1. Measure the Rope Ends to be Socketed: The rope end should be of sufficient length so that The ends of the unlaid wires (from the strands) will be at the top of the socket basket. 2. Apply Serving at Base of Socket: Apply a tight wire serving band, at the point where the socket base will be, for a length of two rope diameters. 3. Broom Out Strand Wires: Unlay and straighten the individual rope strands and spread them evenly so that they form an included angle of approximately 60 degrees. Unlay the wires of each individual strand for the full length of the rope end -- being careful not to disturb or change the lay of the wires and strands under The serving band. Unlay the wires of an independent wire rope core in the same manner. A fiber core should be cut out and removed as close to the serving band as possible. 4. Clean the Broomed-Out Ends: A suggested cleaning solvent for this step is SC-5 Methyl Chloroform. It is also known under the names Chlorothane VG and 1-1-1 Trichlorethane. CAUTION: Breathing the vapor of this solvent is harmful; it should only be used in a well-ventilated area. Be sure to follow the solvent manufacturer's instructions, and carefully observe all instructions printed on the label. Swish the broomed-out rope end in the solvent, then brush vigorously to remove all grease and dirt-making certain that the wires are clean to the very bottom close to the serving band. Additionally, a solution of muriatic acid may also be used. If, however, acid is used the broomed-out ends should be rinsed in a solution of bicarbonate of soda so as to neutralize any acid that may remain on the rope. Care should be exercised to prevent acid from entering the core; this is particularly important if the rope has a fiber core. Where it is feasible, the best and preferred cleaning method for rope ends prior to socketing is ultrasonic cleaning. After this cleaning step, place the broomedout end upright in a vise allowing it to remain until all solvent has evaporated and the wires are dry. Solvent should never be permitted to remain on the rope or on the serving band since it will run down the wires when the rope is removed from the vise. 5. Dip the Broomed-Out Rope Ends in Flux: Prepare a hot solution of zinc-ammonium chloride flux comparable to Zaclon K. Use a concentration of 1 lb of zinc-ammonium chloride to 1 gallon of water; maintain this at a temperature of 180 degrees to 200 degrees Farenheit. Swish the broomed-out end in the flux solution, then place the rope end upright in the vise until such time as the wires have dried thoroughly. 6. Close Rope Ends and Place Socket: Use clean wire to compress the broomed-out rope end into a tight bundle that will permit the socket to be slipped on easily over the wires. Before placing the socket on the rope, make certain that the socket itself is clean and heated. This heating is necessary in order to dispel any residual moisture, and to prevent the zinc from cooling prematurely. A word of caution: Never heat a socket after it is placed on the rope. To do so may cause heat damage to the rope.

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After the socket is on the rope end, the wires should be distributed evenly in the socket basket so that zinc can surround each wire. Use extreme care in aligning the socket with the rope's centerline, and in making certain that there is a minimum vertical length of rope, extending from the socket, that is equal to about 30 rope diameters. Seal the socket base with fire clay or putty but make certain that this material does not penetrate into the socket base. Should this occur, it would prevent the zinc from penetrating the full length of the socket basket thereby creating a void that would collect moisture after the socket is placed in service. 7. Pour the Zinc: The zinc used should meet ASTM Specification designation B6-49 Grade (1) High Grade, and Federal Specification QQ-Z-351-a Amendment 1, interim Amendment 2. Pour the zinc at a temperature of 950 degrees to 970 degrees; make allowances for cooling if the zinc pot is more than 25 ft from the socket. Caution: Do not heat zinc above 1200 degrees Farenheit or its bonding properties will be lost. The zinc temperature may be measured with a portable pyrometer or a Tempilstik. Remove all dross before pouring. Pour the zinc in one continuous stream until it reaches the basket top and all wire ends are covered; there should be no "capping" of the socket. 8. Remove Serving: Remove the serving band from the socket base; check to make certain that zinc has penetrated to the socket base. 9. Lubricate the Rope: Apply wire rope lubricant to the rope at the socket base, and on any rope section where the original lubricant may have been removed.

B. Thermo-Set Resin Socketing Before proceeding with a thermo-set resin socketing procedure, check manufacturer's instructions carefully. Give particular attention to selecting sockets that have been specifically designed for resin socketing. Follow the steps, outlined below, or manufacturer's directions, in the order given. 1. Seizing and Cutting the Rope: Follow rope manufacturer's directions for a particular rope size or construction with regard to the number, position, length of seizings and the seizing wire size. The seizing, located at the base of the installed fitting, must be positioned so that the ends of the embedded wires will be slightly below the level of the top of the fitting's basket. The best means to cut the rope is with an abrasive wheel. 2. Opening and Brooming the Strand Wires: Before opening the rope end, place a short temporary seizing directly above the seizing that represents the broom base. Temporary seizing prevents brooming the wires the full length of the basket and also prevents loss of lay in the strands and rope outside the socket. Remove all seizing between the end of the rope and the temporary seizing. Unlay the strands comprising the rope. Starting with the IWRC, or strand core, open each strand of the rope and broom or unlay the individual wires. (Note: A fiber core in the rope may be cut at the base of the seizing; some prefer to leave the core in. Consult the manufacturer's instruction.) When the brooming is completed, wires should be distributed evenly within a cone so that they form an included angle of approximately 60 degrees. Some types of sockets will require a somewhat different brooming procedure, in which case the manufacturer's instructions should be followed. 3. Cleaning the Wires and Fittings:

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Different types of resin with different characteristics require varying degrees of cleanliness. In some cases, merely using a soluble cleaning oil has been found effective. For one type of polyester resin, on which over 800 tensile tests on ropes in sizes 1/4" to 3-1/2" diameter were made without failure in the resin socket attachment, the cleaning procedure was as follows: Clean wires thoroughly so as to obtain resin adhesion. Ultrasonic cleaning in recommended solvents such as trichloroethylene or 1-1-1 trichloroethane or other non-flammable grease-cutting solvents is the preferred method of cleaning the wires in accordance with OSHA Standards. Where ultrasonic cleaning is not available, brush or dip-cleaning in trichloroethane may be used; but fresh solvent should be used for each rope and fitting and discarded after use. After cleaning, the broom should be dried with clean compressed air or in other suitable fashion before proceeding to the next step. The use of acid to etch the wires before resin socketing is unnecessary and not recommended. Also, the use of a flux on the wires before pouring resin should be avoided since this adversely affects resin bonding to the steel wires. Since there is much variation in the properties of different resins, manufacturers' instructions should be carefully followed. 4. Close Rope Ends and Place Socket: Place rope in a vertical position with the broom end up. Close and compact the broom to permit insertion of the broomed end into the base of the fitting. Slip the fitting on, removing any temporary banding or seizing as required. Make certain the broomed wires are uniformly spaced in the basket, with wire ends slightly below the top edge of the basket, and that the axis of the rope and the fitting are aligned. Seal the annular space between the base of the fitting and the exiting rope to prevent leakage of the resin from the basket. A non-hardening butyl rubber-base sealant is satisfactory for this purpose. Make sure that the sealant does not enter the base of the socket so that the resin will be able to fill the complete depth of the socket basket. 5. Pouring the Resin: Controlled heat-curing (no open flame) at a temperature range of 250 - 300 degrees Farenheit is recommended. If ambient temperatures are less than 60 degrees Farenheit, this is required! When controlled heat curing is not available and ambient temperatures are not less than 60 degrees Farenheit the attachment should not be disturbed and tension should not be applied to the socketed assembly for at least 24 hours. 6. Lubrication After Socket Attachment: After the resin has cured, re-lubricate the wire rope at the base of the socket to replace any lubricant that may have been removed during the cleaning operation. 7. Acceptable Resin Types: Commercially-available resin properties vary considerably. Hence, it is important to refer to the individual manufacturer's instructions before using any one type. General rules cannot, of course, be established. When properly formulated, most thermoset resins are acceptable for socketing. These formulations, when mixed, form a pourable material which will harden at ambient temperatures, or upon the application of moderate heat. No open flame or molten metal hazards exist with resin socketing since heat-curing when necessary, requires a relatively low temperature (250 - 300 degrees Farenheit) obtainable by electric resistance heating. Tests have demonstrated that satisfactory wire rope socketing performance can be obtained with resins having characteristics and properties shown under M2-C, below.

C. General Description The resin shall be a liquid thermoset material that will harden after being mixed with the correct proportion of catalyst or curing agent. 1. Properties of Liquid (Uncured) Material:

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Resin and catalyst are normally supplied in two separate containers. After thoroughly mixing them together, the liquid can be poured into the socket basket. Liquid resins and catalysts shall have the following properties: a. Viscosity of the Resin-Catalyst Mixture: 30-40,000 CPS at 75 degrees Farenheit immediately after mixing. Viscosity will increase at lower ambient temperatures and resin may need warming prior to mixing in the catalyst if ambient temperatures drop below 40 degrees Farenheit. b. Flash Point: Both resin and catalyst shall have a minimum flash point of 100 degrees Farenheit. c. Shelf Life: Unmixed resin and catalyst shall have a minimum of 1 year shelf life at 70 degrees Farenheit. d. Pot Life and Cure Time: After mixing, the resin-catalyst blend shall be pourable for a minimum of eight minutes at 60 degrees Farenheit and shall hard cure in 15 minutes. Heating of the resin in the socket to a maximum temperature of 250 degrees Farenheit is permissible to obtain a full cure. 2. Properties of Cured Resin a. Socket Performance: Resin shall exhibit sufficient bonding to solvent washed wire in typical wire rope end fittings to develop The nominal strength of all types and grades of rope. No slippage of wire is permissible when testing resin-filled rope socket assemblies in tension. After testing, however, some "seating" of the resin cone may be apparent and is acceptable. Resin adhesion to wires shall be capable of withstanding tensile shock loading. b. Compressive Strength: The minimum allowable compressive strength for fully cured resin is 12,000 psi. c. Shrinkage: Maximum allowable shrinkage is 2%. To control shrinkage, an inert filler may be used in the resin provided that viscosity requirements as specified above (A.1) for the liquid resin are met. d. Hardness: The desired hardness of the result is in the range of Barcol 40 - 55. 3. Resin Socketing Compositions Manufacturer's directions should be followed in handling, mixing and pouring the resin composition. 4. Performance of Cured-Resin Sockets Poured-resin sockets may be moved after the resin has hardened. Following the ambient- or elevated- temperature cure, recommended by the manufacturer, resin sockets should develop the nominal strength of the rope, and have the capability of withstanding shock loading to a degree sufficient to break the rope, without cracking or breakage. Manufacturers of resin socketing material shall be required to test these criteria before resin materials will be approved for rope socketing use. Caution: This discussion is a generalized description of but one of many commercially available Thermoset resins suitable for wire rope socketing. Characteristics of these products do vary significantly and each must be handled differently. Thus, specific information concerning a resin must be obtained from each manufacturer before setting up a specific resin socketing procedure.

III Attachment Of Wire Rope Claps To Wire Rope A. Wire Rope Clips Wire rope clips are widely used for making end terminations. Clips are available in two basic designs; the U-bolt and the fist grip (Figure M2-3).

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Figure M2-3. Crosby Wire Rope Clips

Figure M2-3A. Correct Method to Attach Clips to Wire Rope

The correct way to attach U-bolts is shown at the top; the "U" section is in contact with the rope's dead end and is clear of the thimble.

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Figure M2-3B. Incorrect Methods to Attach Clips to Wire Rope

The efficiency of both types is the same. When using U-bolt clips, extreme care must be exercised to make certain that they are attached correctly, i.e., the U-bolt must be applied so that The "U" section is in contact with tile dead end of the rope (Figure M2-4). Figure M2-4 Tangents of Fleet Angles

Also, tightening and retightening the nuts must be accomplished as required.

B. How to Apply Clips Recommended method of applying U-bolt clips to get maximum holding power of the clip:

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Table M2-4A Attachment of Crosby G450 U-Bolt Clips

1. Turn back the specified amount of rope from the thimble. Apply the first clip one base width from the dead end of the wire rope (U-bolt over the dead end -- the live end rests in the clip saddle). Tighten nuts evenly to the recommended torque. 2. Apply the next clip as near the loop as possible. Turn on nuts firm but do not tighten. 3. Space additional clips if required equally between the first two. Turn on nuts -- take up rope slack -- tighten all nuts evenly on all clips to recommended to torque. 4. NOTE Apply the initial load and retighten nuts to the recommended torque. Rope will stretch and be reduced in diameter when loads are applied. Inspect periodically and retighten to the recommended torque. A termination made in accordance with the above instructions, and using the number of clips shown has about an 80% efficiency rating. This rating is based upon the nominal strength of wire rope. If a pulley is used in place of a thimble for turning back the rope, then add one additional clip. The number of clips shown is based upon using right regular lay, or right lang lay wire rope, 6 x 19 class or 6 x 36 class, fiber core or IWRC, IPS or EIP. If Seale construction or similar large outer wire type construction in the 6 x 19 class is to be used for sizes 1 inch and larger, then add one additional clip. The number of clips shown also applies to right regular lay wire rope, 8 x 19 class, fiber core, IPS, sizes 1-1/2 inch and smaller; and right regular lay wire rope, 18 x 7 class, fiber core, IPS or EIP, sizes 1-3/4 inch and smaller. For other classes of wire rope not in this list, it may be necessary to add additional clips to the number shown. If a greater number of clips are used than shown in the table, then the amount of rope turnback should be increased proportionately. This is based on the use of clips on new rope.

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IMPORTANT: Failure to make a termination in accordance with these instructions, or failure to periodically check and retighten all nuts to the recommended torque, will cause a reduction in this efficiency rating.

C. Fist Grip Clips Recommended Method of Applying Fist Grip Clips: Table M2-4B Attachment of Crosby G429 Fist Grip Clips

1. Turn back the specified amount of rope from the thimble. Apply the first clip one base width from the dead end of the wire rope. Tighten nuts evenly to recommended torque. 2. Apply the next clip as near the loop as possible. Turn on nuts firmly but do not tighten. 3. Space additional clips if required equally between the first two. Turn on nuts -- take up the rope slack -- then tighten all nuts evenly on all clips to the recommended torque. 4. NOTE! Apply the initial load and retighten the nuts to the recommended torque. Rope will stretch and be reduced in diameter when loads are applied. Inspect periodically and retighten to recommended torque. 5. Use of a half Hitch: Do not use a half hitch, either with or without clips, as it malforms and weakens wire rope. A termination made in accordance with the above instructions, and using the number of clips shown has an approximate 80% efficiency rating. This rating is based upon the catalog breaking strength of wire rope. If a pulley is used in place of a thimble for turning back the rope, add one additional clip. The number of clips shown is based upon using right regular or lang lay wire rope, 6 x 19 class of 6 x 37 class, fiber core or IWRC, IPS or EIPS. If Seale construction or similar large outer wire type construction in the 6 x 19 class is to be used for sizes 1 inch and larger, add one additional clip. The number of clips shown also applies to right regular lay wire rope, 8 x 19 class, fiber core, IPS or EIPS, sizes 11/2 inch and smaller. For other classes of wire rope not mentioned above, it may be necessary to add additional clips to the number shown. If a greater number of clips are used than shown in the table, the amount of rope turnback should be increased proportionately. THIS IS BASED ON THE USE OF FIST GRIP CLIPS INSTALLED ON NEW WIRE ROPE.

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IMPORTANT: Failure to make a termination in accordance with aforementioned instructions, or failure to periodically check and retighten to the recommended torque, will cause a reduction in efficiency rating.

IV. Casing-line And Drilling Line Reeving Practice A. Methods of Reeving Ordinarily, the only two variables in reeving systems, illustrated below, are the number of sheaves in the crown, and the number of sheaves in the traveling blocks; or the number required for handling the load, and the location of the deadline anchor. Figure M2-4 illustrates, in a simplified form, the generally accepted methods of reeving, or stringing up an inline crown and traveling blocks, along with the location of the drawworks drum, monkey board, drill pipe fingers, and deadline anchor in relation to the various sides of the derrick. Reeving diagram for 12-line stringup with 7-sheave crown block and 6-sheave travelling block, left hand reeving. See arrangement 1 in Table M2-5. Table M2-5 gives the various possible arrangements of reeving patterns for 12-10-8 and 6 line string-ups using 7sheave crown blocks with 6 sheave traveling blocks and 6-sheave crown blocks with 5-sheave traveling blocks.

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Table M2-5. Possible Reeving Pattern Arrangements

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The most used practice is to use left-hand reeving and locate the deadline anchor to the left of the derrick vee. In selecting the best of the various possible methods for reeving casing or drilling lines, the following basic factors should be considered. 1. Minimum fleet angle from the drawworks drum to the first sheave of the crown bloc, and from the crown block sheaves to the traveling block sheaves. 2. Proper balancing of crown and traveling blocks. 3. Convenience in changing from smaller to larger number of lines, or from larger to smaller number of lines. 4. Locating of deadline on monkey board side for convenience and safety of derrickman. 5. Location of deadline anchor, and its influence upon the maximum rated static hook load of derrick. Figure M2-4 Reeving Diagram For 12-Line String-Up With 7-Sheave Crown Block And 6-Sheave Traveling Block; Left Hand Reeving.

B. Function of Reeving System 1. General: A hoisting system is a way of listing heavy loads with lighter lead line pulling loads. As with a simple pulley system, the line strung through the blocks allows you a mechanical lifting advantage. This mechanical advantage is equal to the number of lines strung between the crown and the traveling block, taking into consideration accumulated friction. Thus for a 6-line system, without friction you could lift a weight by pulling with a force of only 1/6 of the weight. With an 8-line system, the pull will be only 1/8 of the weight; with 10 lines, 1/10, and so forth. The reason for this mechanical advantage is that the lines emerging from the traveling block divide the load equally among themselves by pulling down on the line as it leaves the traveling block. This is the load divided by the number of lines strung. 2. Work Encountered in Reeving System:

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By utilizing mechanical advantage of the pulley, you are not decreasing the work done. Work done is the load multiplied by the distance moved. When the load is hoisted, each of the lines shortens by the distance of the hoist. However, the last line or fast line, coming onto the drum, must take up all the extra line. This is, of course, the distance the load moves times the number of lines strung. Inasmuch as the load on this line is the weight lit~ed divided by the number of lines, then the work done by the hoist is the same as the work required to raise the load. 3. Line Speed: Since the movement of the drilling line, being wound or unwound on the drum is greater than the movement of the traveling block, the speed with which it moves is also greater. Thus if the traveling block is being lowered at the rate of 10 ft per second, or 10 fps, in a 6-line system, the line is paying off the drum at 60 fps or 3600 fpm. The maximum recommended speed for movement of wire ropes through the sheaves is 4000 fpm. If the block of an 8line system were moving at 10 fps, the line speed would exceed the recommended rate. 4. Determining Maximum Pull: The fast line during hoisting has a load greater than the total weight being lifted divided by the number of parts of line. The load is increased by the friction of the sheave bearings and the bending of the line around the sheaves. Starting at the deadline sheave, each successive line has, during hoisting, an extra load on it caused by the "sum" of the frictional loads from all previous rotating sheaves. Since the fast line experiences the accumulation of frictional forces from all rotating sheaves, its load is the greatest and it should be used when calculating design factors. The fast line load can be calculated by the following formula: L = W x Ks x (K-1)/(Kn -1) Where: L = fast line load, lbs. W = total weight lifted, lbs. K = friction coefficient Roller bearing Sheaves = 1.04 n = number of parts of line *s = number of rotating sheaves *NOTE: Deadline crown sheave does not rotate during hoisting so, for most rotary rigs, s = n. EXAMPLE: 500,000 lb load; 10 = line string up w/ 1-1/2" EIPS; Drilling line friction coefficient = 1.04 What is the lead line load and design factor? A. n = 10; s = 10; w = 500,000; K = 1.04 L = 500,000 x (1.0410) x (1.04 - 1)/{(1.04)10 - 1) = 500,000 x (1.48024) (0.04)/(1.8024 - 1) = 500,000 x 0.123 = 61,500 lbs. B. Nominal Strength of 1-1/2" EIPS = 114 Tons = 228,000 lbs. Design Factor = 228,000/61,500 = 3.7 WARNING: This ignores acceleration forces and shock loadings. These forces can greatly increase the load on the rope and lead to permanent deformation and increased rate of deterioration. 5. Fast Line Loads & Design Factors:

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Fast line loads and design factors for various hook loads with 6, 8, 10, and 12 parts of line are shown in Table M26. Table M2-6 Fast Line Load and Design Factors for Various Hook Loads with 6, 8, 10 and 12 Parts of Line (AIl Calculations Based Upon New 6X19 IWRC Wire Rope). Table based on the Extra Improved Plow and Improved Plow with independent wire rope cores.

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Table M2-6. Fast Line Load Design Factors

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M3. Factors Affecting Service Life Of Wire Rope Following are some of the factors that have a direct effect upon rotary drilling line service. Although they are elemental, they are critical. 1. Mast or Derrick Height The mast or derrick height will vary from approximately 65' to 185' or more. Governs the total amount of rotary line in the stringup, and determines whether "doubles," "triples" or "quadruples" of drill pipe will be handled during trips. 2. Crown Blocks Sheaves Sheave diameters should be large enough to minimize the bending fatigue which occurs on a rotary line. Worn grooves will not properly support the rotary line and worn bearings set up undue wear on both the sheaves and the line. 3. Traveling Block Sheaves The same conditions concerning the sheaves apply here as with the Crown Block. In addition, the traveling block must be of sufficient weight to give tight spooling on the drum as the block assembly is being raised or lowered, when going into and coming out of the hole. 4. Draw Works Drum The diameter and length of drum is important. A drum of small diameter and length requires more drum wraps to raise the blocks. This leads to more layers of rope on the drum, and therefore, more "cross-over" wear points. A grooved drum increases wire line service by supporting the rotary line and giving a tighter wrap. The condition of the drum clutch and brake greatly affects line life. If these are not properly adjusted, the resulting jerking and shock loads must be borne by the rotary line. 5. Type of String-Up - 6, 8, 10 or 12 Lines The type of String-Up will govern the load each part of line must carry, determines the total line in the String-Up, and also determines the length of time wear points must remain in the system. 6. Dead Line Anchor or Clamp The size, type and condition of the anchor has a direct effect on the rotary line. If it is too small, or otherwise distorts the line, it may form a "dog-leg" in the line which will set up a stress point. This stress point will result in undue wear and early fatigue, necessitating a long cut to remove it from the system. 7. Wire Line Stabilizer and Turn-Back Rollers The Wire Line Stabilizer and Turn-Back Rollers help extend the life of the wire line. The wire line stabilizer relieves vibration or "whip" on the "fast" line. The turn-back rollers help relieve shock at the "cross-over" points on the drum and prevent line piling up at the drum flanges. Weight box type stabilizers are considered far superior as far as drum spooling is concerned. Deadline stabilizers reduce vibration in the deadline adjacent to the deadline anchor and deadline sheave. 8. Experience of Crew The Experience of Crew will affect the wire line life in the manner in which they handle the rotary line. For example, how do they unspool the reel, how do they reeve the string-up, what steps are taken to keep the line out of mud and dirt, what method is used to spool new line on the drum, and how does the driller start and stop the drum when making a "round trip." NOTE: 6 inches of slack line jerked out on the load, will double the load on the line.

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9. Depth of Well The Depth of Well will govern the total weight of drill pipe and drill collars, the number of connections required, the number of bits required, and also the number of round trips needed. 10. Drilling Conditions Certain types of earth strata cause bit "chatter" or vibration which is passed through the drill pipe and traveling blocks to the rotary line. The intermittent shock loads must be absorbed by the drilling line, and are a source of undue wear, particularly at the dead line sheave. Also, certain strata cause crooked hole drilling, which results in considerable excess strain on the drilling line when coming out of the hole during a round trip. 11. Size of Drill Pipe Determines the total load when figuring the ton mile service per round trip, and in making connections. 12. Size and Number of Drill Collars The size and number of Drill Collars is one of the variable factors in determining the total excess weight when figuring ton-mile service per round trip. 13. Drill Stem Tests Drill Stem Tests mean extra round trips over and above those necessary to change bits. 14. Coring Coring also means extra round trips and more line wear. 15. Stuck Pipe Jarring and manipulation to unstick drill pipe causes extreme strain and wear on rotary line. No ton-mile method of service wear can determine the damage here! Careful visual inspection should be used, and damaged line removed from the system regardless of the length of cut required. 16. "Twist Offs" and "Fishing" Jobs "Twist Offs" and "Fishing" Jobs often mean several extra round trips to completely remove the "fish" or obstruction before normal drilling can be resumed. 17. Setting Casing While the length and size of casing will vary, but it still means additional trips, connections, and line wear. 18. Fleet Angle The Fleet Angle is taken into consideration with the proper wire line stabilizer can be the basis for solving many of the reasons for poor spooling on a rig. Therefore, the proper fleet angle should be of paramount importance when determining the excess laps. When we take these elemental factors into consideration it is then apparent why we must "tailor" a rotary line service program to each individual rig. Refer to Figure M2-1, and Figure M2-2.

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M4. Ton Mile Calculations A. Introduction In the early 1940's a drilling contractor would have purchased only enough rotary drilling line to string up his reeving system. Depending upon the height of his derrick and the number of parts of line to be used, lengths would vary from 650 to 1,750 feet. In working the line, heavy wear would occur in a few localized sections: where the rope makes contact with the traveling block sheaves, and where the rope makes contact with the crown block sheaves when the slips are pulled going in or coming out of the hole, and on the drum where each wrap of rope crosses over the rope on the layer below. Broken wires at these points of critical wear would result in the retirement of the entire string up, even though the remainder of the rope was in good condition. Today, purchasing longer lengths of drilling line, and periodically slipping new rope into the system while cutting off old line at the drum end, shifts the rope through these critical wear areas and distributes the wear more uniformly along the length of the rope. See Figure M4-1. Figure M4-1 Wire Line Wear Points

If too much wire rope is cut off too frequently, there will be an obvious waste of usable drilling line, which will result in higher than necessary rig operating costs. However, if the rope is moved through the reeving system too slowly, sooner or later some section of the drilling line will become worn and damaged to such an extent that there will be a danger of failure, injury to personnel, damage to equipment and expensive downtime. At the very least, it will be necessary to make a "long cut" to eliminate some broken wires. For these reasons, it is important that the drilling line be cut off at the proper rate. The purpose of this Simplified Cut-Off Practice is to give the drilling contractor a method for keeping track of the amount of work done by the drilling line, and a systematic procedure for making cuts of the appropriate length at the appropriate time. The objective is to obtain maximum rope service without jeopardizing the safety of the rig operation. In conjunction with the record keeping required for the cut-off procedure, daily visual inspection of the drilling line should be made for broken wires and any other rope damage. It must be remembered that in all cases, visual inspection of the wire rope by the drilling contractor must take precedence over any predetermined calculations.

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The only complicated part of a cut-off procedure is the determination of how much work has been done by the wire rope. Methods such as counting the number of wells drilled or keeping track of days between cuts are not accurate because the loads change with depth and with different drilling conditions. The various operations performed (drilling, coring, fishing, setting casing, etc.) subject the rope to different amounts of wear. For an accurate record of the amount of work done by a drilling line, it is necessary to calculate the weight being Lifted and the distance it is raised and lowered. In engineering terms, work is measured in foot-pounds. On a drilling rig the loads and distances are so great that we use "ton-miles." One ton-mile equals 10,560,000 footpounds, and is equivalent to lifting 2,000 pounds a distance of 5,280 feet. To simplify the calculation of ton-miles, a Ton-Mile Indicator has been developed. The following pages provide examples of how this Indicator is used to determine the number of ton-miles of work done by the drilling line for various operations on the rig. Please refer to Table M4-1 and Table M4-2 as you go through the examples.

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Table M4-1 E Indicator - Drill Collar Weight Factor

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Table M4-2 Wire Rope Indicator - Ton-Mile per Round Trip - 4-1/2" 16.6 ppf in mud

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These tables are taken from the Ton-Mile Indicator developed by Union Wire Rope. Indicators are available for any type or size of drill pipe in both mud and air drilling. Contact a Union Wire Rope representative for the Indicator(s) you require.

B. Examples Of Ton-mile Calculations 1) Example No. 1: Round Trip Ton-Miles a) Situation: At a depth of 11,000 feet, a round trip is made to change the bit. Drill Pipe = 4-1/2", 16.6 ppf Drill Collars = ten, 7-1/4", 119.2 ppf Traveling block assembly weight (hook, elevators, traveling block) = 27,000 lbs Drilling Fluid = mud

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b) Solution: 1. Determine Weight Factor Due to Collars: On Table M4-1, locate proper drill collar number and read weight factor due to collars in appropriate column. Weight factor due to collars = 13,000 lbs 2. Determine Total Weight Factor: Add together Weight Factor due to Collars and weight of Traveling Block assembly. Traveling Block. Assembly Weight = 27,000 lbs + Weight Factor due to Collars = 13,000 lbs Total Weight Factor = 40,000 lbs 3. Determine Ton-Miles Per Round Trip: On Table M4-2, locate depth and read round trip ton-miles in appropriate column. Round Trip = 337 Ton-Miles * Note: For laying down drill pipe at the end of well, figure one-half of round trip ton-miles for drill string in question.

2) Example No. 2: Drilling Ton-Miles a) Situation: Drilling continues from a depth of 11,000 feet to a depth of 12,000 feet. Drill Pipe = 4-1/2", 16.6 ppf Drill Collars = ten, 7-1/4", 119.2 ppf Traveling block assembly weight = 27,000 lbs Drilling fluid = mud b) Solution: Ton-Miles for drilling from one depth to another equals 3 times the difference in round trip ton-miles for the two depths. Total Weight Factor: 1. Determine Ton-Miles for a Round Trip Where Drilling Stopped: Locate depth of 12,000'; Read under the 40,000 lb column that Ton-Miles = 384 T-M 2. Determine Ton-Miles for a Round Trip Where Drilling Started: Locate depth of 11,000'; Read under 40,000 lb column that Ton-Miles = 337 T-M 3. Calculate the Difference in Round Trip Ton-Miles: 384 - 337 = 47 T-M 4. Calculate Drilling Ton-Miles: Drilling ton-miles = difference in round trip ton-miles times 3 = 47 x 3 = 141 T-M Ton-Miles for Drilling from 11,000' to 12,000' = 141 T-M.

3) Example No. 3: Ton-Miles for Setting Casing a) Situation: Setting 10-3/4", 40.5 ppf casing from surface to 3,600 feet. Traveling Block Assembly Weight = 20,000 lbs

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b) Solution: The ton-miles of work done in setting casing would be one-half the ton-miles done in making a round trip: if the weight of the casing were the same as the weight of the drill pipe. 1. Determine the ratio of casing weight to drill pipe weight: (40.5 ppf)/(16.6 ppf) = 2.44 2. Determine ton-miles for making a round trip with pipe: Locate depth of 3,600 feet Read under 20,000 lb column. No drill collars are used, therefore, the Total Weight Factor is equal to the traveling block assembly weight only. 3. Determine ton-miles for making a round trip with casing: Multiply by the weight ratio: 2.44 x 46 = 122 T-M Round trip for casing = 112 T-M ton-miles 4. Determine ton-miles for setting casing: Divide by 2, since the casing is only set down and not pulled out. (112/2) = 56 T-M Ton-miles; To set the casing = 56 T-M.

4) Example No. 4: Ton-Miles for a Short Trip a) Situation: Having drilled to 13,000 feet, a short trip is made back to 9,000 feet to condition the hole. Drill Pipe = 4-1/2", 16.6 ppf Drill Collars = Twenty, 7-3/4", 138 ppf Traveling Block Assembly Weight = 20,000 lbs Drilling Fluid = Mud b) Solution: The ton-miles of work done in making a short trip equals round trip ton-miles at the deeper depth minus the round trip ton-miles at the shallower depth. 1. Determine ton-miles for a round trip at 13,000 feet: Locate depth of 13,000 feet On Table M4-2Read under 50,000# column Round trip ton-miles at 9,000 feet = 284 T-M 2. Determine ton-miles for a round trip at 9,000 feet: On Table M4-2 Locate depth of 9,000 feet, Read under 50,000 lb column. Round trip ton-miles at 9,000 feet = 483 T-M 3. Determine ton-miles for the short trip: From 483 T-M Subtract 284 T-M = 199 T-M So, Ton-miles for the short trip = 199 T-M

5) Example No. 5: Ton-miles for round trip of mixed drill string a) Situation: Having drilled to 13,000 feet with a drill string (5" to 9000 ft, 4-1/2" 16.6 ppf below, and 15 jts 7-1/4" DCs @ 138 ppf), a round trip is made:

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Drilling Fluid = Mud;

Traveling Block Assembly Weight = 27,000 lbs

b) Solution: 1. Weight Factor due to collars = 23,000 lbs 2. Total Weight Factor = 23,000 + 27,000 = 50,000 lbs 3. Ton-miles for round trips: 4-1/2" @ 13,000' = 483 T-M 5"

@ 9,000' = 303 T-M add: = 786 T-M 4-1/2" @ 9,000' = - 284 T-M subtract: = 502 T-M

Ton-miles for a round trip with the mixed drill string = 502 T-M.

6) Example No. 6: Ton-Miles for Round Trip with Heavy Wall Drill Pipe a) Situation: Having drilled to 12,000 feet with the drill string (4-1/2" from surface, then below with 30 jts 4-1/2" 42 ppf HWDP, then 20 jts 7-1/4" ppf DCs @ 138 ppf), a round trip is made: Drilling Fluid = Mud;

Traveling Block Assembly Weight = 30,000 lbs

b) Solution: Instead of trying to calculate the heavy-weight pipe as in a mixed drill string, treat it as additional drill collars. Use the drill collar window on the back of the Union Ton-Mile Indicator which is closest to the heavy-weight pipe weight, or do the calculations by hand. 1. Determine weight factor due to collars: On Table M4-1, locate proper drill collar number and read weight due to collars under appropriate column. Weight factor due to DCs = 30,700 lbs 2. Determine weight factor due to heavy wall drill pipe: Figure the heavy-weight drill pipe as if they were drill collars. On Table M4-1 locate the proper heavy-weight pipe number and read the weight due to heavy-weight pipe from the window with the closest drill collar weight is 46.7 ppf). An accurate value for Weight Factor due to heavy-weight pipe can also be figured longhand as follows (more accurate): Excess weight per foot = 42.0 - 16.6 = 25.4 Total excess weight = 25.4 x 900' = 22,860 lbs Buoyed excess weight = 22,860 x 0.85 = 19,431 lbs 1/2 Buoyed excess weight = 19,431/2 = 9,716 lbs So, the weight factor due to the heavy-weight drill pipe = 9,716 lbs 3. Determine total weight factor: Traveling block assembly weight = 30,000 lbs Weight factor due to collars

= 30,700 lbs

International Association of Drilling Contractors

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IADC Drilling Manual - Eleventh Edition

Weight factor due to the HWDP = 9,716 lbs Total weight factor

= 70,416 lbs

4. Determine ton-miles per round trip: Locate depth of 12,000' Read under 70,000 lb window Round trip ton-miles = 520 T-M

C. Ton-miles Per Foot Cut The purpose of calculating the amount of work done by the drilling line is to give an accurate method for determining when and how much drilling line to slip through and cut off. The objective of spreading the rope wear along the length of the line can be accomplished best by cutting lengths proportional to the ton-miles of work accumulated. All that is necessary is to maintain a consistent number of ton-miles per foot of rope cut. For a given rope size, any particular rig can get only so many ton-miles of service. The key to a successful cut-off procedure is to spread these ton-miles uniformly by using the optimum ton-mile per foot cut goal. A rig which has been able to get about 66,000 T-M out of a 1-3/8" x 5,000' drilling line, may have a string-up of 1,700' for ten parts. The remaining 3,300' available to be cut off should be cut at a rate of one foot for every 20.0 ton-miles. (66,000 TM )/( 3,300 ft) = 20.0 T-M/ft) The ton-mile goal would be 20.0. The ton-mile goal for any rig with good past performance records can be calculated in the same manner. If the rig is new, or if the records are unavailable, a ton-mile goal can be selected from Table M4-3. Table M4-3. T-M Goal Where Records Are Not Available

Note: Only the drilling line size and the drum diameter are needed to determine a ton-mile goal. These are the most important factors that influence ton-mile service on a drilling rig.

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Chapter M: Wire Rope

D. Ton Mile Calculations - Drilling Ton Miles for Top Drive (Drilling with Stands) Ton mile calculations for other operations tend to be unaffected by the addition of the top drive, with the exception of the additional traveling equipment weight. Definition of Terms: WDS = Buoyant weight of drill string (drill pipe and BHA) M

= Weight of traveling equipment

LS

=

Length of a stand

Drilling Operation Cycle: 1) Drill down length of stand (LS) 2) Raise stand and ream back down full length 3) Set slips and break out at pipe handler 4) Raise traveling equipment; pick up next stand and make up 5)Pick up off slips and begin again Ton Miles Generated Per Cycle Segment: 1) ((WDS + M) x LS)/(2000 x 5280) 2) (2 x (WDS + M) x LS)/(2000 x 5280) 3) N/A 4) (M x LS)/(2000 x 5280) 5) N/A If one combines steps 1 through 5, the following applies: Ton Miles Per Stand Drilled = (LS x (3 WDS + 4 M)/(2000 x 5280)

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IADC Drilling Manual - Eleventh Edition

M5. Cut-off Program A. Cut-Off Program Assuming that 1-3/8" drilling line is used on a NATIONAL 130 (30" drum) rig with no past performance records, Table M4-3 gives a suggested ton-mile goal of 19.0. Table M5-1 is the Union Wire Rope Cut-Off Program for a 19.0 ton-mile goal. Click Here for Table M5-1 Union Wire Rope Cut-Off Program For 1-3/8" Rotary Drilling Line (Example Only) Other programs are available for the specific goal required for your rig. Tables on M5: Union Wire Rope Cut-Off Program For 1" thru 1-1/2" Rotary Drilling Lines Note: the program is summarized by the statement: Length to Cut = T-M Since Last Cut % 19.0 So long as the maximum ton-mile accumulation shown on the program is not exceeded, a cut may be made whenever it is convenient. It is only necessary to total the ton-miles accumulated since the last cut and divide by 19.0 to determine what length to cut. This way the ton-miles per foot cut will always be exactly 19.0, and the wear on the drilling line will be uniformly spread along its length. For convenience, the calculations have been made for a number of ton-mile accumulations, and are presented in tabular form on the program. B. Suggestions for Cut-Off Practice Whatever program is used, it should be followed throughout the life of one entire drilling line. If no long cuts are required, and it is believed that more service can be obtained from a line, the goal can be raised one ton-mile per foot cut. This procedure should be followed until the optimum goal is found. Avoid accumulating more ton-miles between cuts than the maximum shown on the program for your rig even on the first cut of a new line. It is best not to run up to the maximum permitted ton-miles each time between making a cut, as some problem on your rig could prevent a cut being made at the proper time and lead to a ton-mile overrun. A better approach is to bounce around on your program, cutting with a new ton-mile accumulation sometimes and alternating with a medium or higher ton-mile accumulations. This practice does not waste wire rope because you are always cutting off lengths in proportion to the work accumulated. Accurate measurement of the length to cut is very important. A steel tape should be used when making this measurement. When stringing back from 12 to 10 lines, or from 10 to 8 lines, make a cut of the appropriate length based upon the ton-mile accumulation at that time. This procedure will shift the critical wear points on the rope following heavy operations such as setting casing. Keep your wire rope history Sheets current, accurate and complete. Calculate ton-miles for drilling after each round trip. Failure to record drilling ton-miles is probably the most common mistake made in cut-off practice. The best cut-off program is the one with the most consistent ton-mile per foot cut values. By staying as close as possible to the ton-mile goal you will avoid long cuts and maintain the safest, and most economical use of your rotary drilling line. Daily visual inspection of the drilling line should be made for broken wires and any other rope damage.

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Note: in all cases, visual inspection of the wire rope by the drilling contractor must take preference over any predetermined calculations.

C. Union Wire Rope Cut-Off Program For Rotary Drilling Line Tables on M5: Union Wire Rope Cut-Off Program For 1" thru 1-1/2" Rotary Drilling Lines

Cut-Off Program For 1" Rotary Drilling Line Cut-Off Program For 1" Rotary Drilling Line; Goal of 6.0 T-M/Ft Cut Table - M5-p2a Wire Rope Cut-off Program, 1" Rotary Drill Line, Goal: 6.0 T-M/ft cut

1. Do not accumulate more than 800 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 800 ton-miles have been accumulated, a cut may be made at anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 6.0). 3. This program is based upon a goal of 6.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

International Association of Drilling Contractors

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IADC Drilling Manual - Eleventh Edition

Cut-Off Program For 1" Rotary Drilling Line; Goal of 7.0 T-M/Ft Cut Table - M5-p2b Wire Rope Cut-off Program, 1" Rotary Drill Line, Goal: 7.0 T-M/ft cut

1. Do not accumulate more than 1000 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 1000 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 7.0). 3. This program is based upon a goal of 7.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

M-52

International Association of Drilling Contractors

Chapter M: Wire Rope

Cut-Off Program For 1" Rotary Drilling Line; Goal of 8.0 T-M/Ft Cut Table - M5-p3a Wire Rope Cut-off Program, 1" Rotary Drill Line, Goal: 8.0 T-M/ft cut

1. Do not accumulate more than 1100 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 1100 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 8.0). 3. This program is based upon a goal of 8.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

International Association of Drilling Contractors

M-53

IADC Drilling Manual - Eleventh Edition

Cut-Off Program For 1" Rotary Drilling Line; Goal of 9.0 T-M/Ft Cut Table - M5-p3b Wire Rope Cut-off Program, 1" Rotary Drill Line, Goal: 9.0 T-M/ft cut

1. Do not accumulate more than 1200 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 1200 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 9.0). 3. This program is based upon a goal of 9.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

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International Association of Drilling Contractors

Chapter M: Wire Rope

Cut-Off Program For 1-1/8" Rotary Drilling Line Cut-Off Program For 1-1/8" Rotary Drilling Line; Goal of 9.0 T-M/Ft Cut Table - M5-p4a Wire Rope Cut-off Program, 1-1/8" Rotary Drill Line, Goal: 9.0 T-M/ft cut

1. Do not accumulate more than 1300 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 1300 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 9.0). 3. This program is based upon a goal of 9.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

International Association of Drilling Contractors

M-55

IADC Drilling Manual - Eleventh Edition

Cut-Off Program For 1-1/8" Rotary Drilling Line; Goal of 10.0 T-M/Ft Cut Table - M5-p4b Wire Rope Cut-off Program, 1-1/8" Rotary Drill Line, Goal: 10.0 T-M/ft cut

1. Do not accumulate more than 1400 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 1400 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 10.0). 3. This program is based upon a goal of 10.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

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International Association of Drilling Contractors

Chapter M: Wire Rope

Cut-Off Program For 1-1/8" Rotary Drilling Line; Goal of 11.0 T-M/Ft Cut Table - M5-p5a Wire Rope Cut-off Program, 1-1/8" Rotary Drill Line, Goal: 11.0 T-M/ft cut

1. Do not accumulate more than 1600 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 1600 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 11.0). 3. This program is based upon a goal of 11.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

International Association of Drilling Contractors

M-57

IADC Drilling Manual - Eleventh Edition

Cut-Off Program For 1-1/8" Rotary Drilling Line; Goal of 12.0 T-M/Ft Cut Table - M5-p5b Wire Rope Cut-off Program, 1-1/8" Rotary Drill Line, Goal: 12.0 T-M/ft cut

1. Do not accumulate more than 1650 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 1650 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 12.0). 3. This program is based upon a goal of 12.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

M-58

International Association of Drilling Contractors

Chapter M: Wire Rope

Cut-Off Program For 1-1/8" Rotary Drilling Line; Goal of 13.0 T-M/Ft Cut Table - M5-p6a Wire Rope Cut-off Program, 1-1/8" Rotary Drill Line, Goal: 13.0 T-M/ft cut

1. Do not accumulate more than 1750 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 1750 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 13.0). 3. This program is based upon a goal of 13.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

International Association of Drilling Contractors

M-59

IADC Drilling Manual - Eleventh Edition

Cut-Off Program For 1-1/4" Rotary Drilling Line Cut-Off Program For 1-1/4" Rotary Drilling Line; Goal of 12.0 T-M/Ft Cut Table - M5-p6b Wire Rope Cut-off Program, 1-1/4" Rotary Drill Line, Goal: 12.0 T-M/ft cut

1. Do not accumulate more than 1800 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 1800 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 12.0). 3. This program is based upon a goal of 12.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

M-60

International Association of Drilling Contractors

Chapter M: Wire Rope

Cut-Off Program For 1-1/4" Rotary Drilling Line; Goal of 13.0 T-M/Ft Cut Table - M5-p7a Wire Rope Cut-off Program, 1-1/4" Rotary Drill Line, Goal: 13.0 T-M/ft cut

1. Do not accumulate more than 1900 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 1900 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 13.0). 3. This program is based upon a goal of 13.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

International Association of Drilling Contractors

M-61

IADC Drilling Manual - Eleventh Edition

Cut-Off Program For 1-1/4" Rotary Drilling Line; Goal of 14.0 T-M/Ft Cut Table - M5-p7b Wire Rope Cut-off Program, 1-1/4" Rotary Drill Line, Goal: 14.0 T-M/ft cut

1. Do not accumulate more than 2000 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 2000 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 14.0). 3. This program is based upon a goal of 14.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

M-62

International Association of Drilling Contractors

Chapter M: Wire Rope

Cut-Off Program For 1-1/4" Rotary Drilling Line; Goal of 15.0 T-M/Ft Cut Table - M5-p8a Wire Rope Cut-off Program, 1-1/4" Rotary Drill Line, Goal: 15.0 T-M/ft cut

1. Do not accumulate more than 2100 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 2100 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 15.0). 3. This program is based upon a goal of 15.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

International Association of Drilling Contractors

M-63

IADC Drilling Manual - Eleventh Edition

Cut-Off Program For 1-1/4" Rotary Drilling Line; Goal of 16.0 T-M/Ft Cut Table - M5-p8b Wire Rope Cut-off Program, 1-1/4" Rotary Drill Line, Goal: 16.0 T-M/ft cut

1. Do not accumulate more than 2200 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 2200 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 16.0). 3. This program is based upon a goal of 16.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

M-64

International Association of Drilling Contractors

Chapter M: Wire Rope

Cut-Off Program For 1-1/4" Rotary Drilling Line; Goal of 17.0 T-M/Ft Cut Table - M5-p9a Wire Rope Cut-off Program, 1-1/4" Rotary Drill Line, Goal: 17.0 T-M/ft cut

1. Do not accumulate more than 2300 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 2300 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 17.0). 3. This program is based upon a goal of 17.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

International Association of Drilling Contractors

M-65

IADC Drilling Manual - Eleventh Edition

Cut-Off Program For 1-1/4" Rotary Drilling Line; Goal of 18.0 T-M/Ft Cut Table - M5-p9b Wire Rope Cut-off Program, 1-1/4" Rotary Drill Line, Goal: 18.0 T-M/ft cut

1. Do not accumulate more than 2300 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 2300 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 18.0). 3. This program is based upon a goal of 18.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

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International Association of Drilling Contractors

Chapter M: Wire Rope

Cut-Off Program For 1-3/8" Rotary Drilling Line Cut-Off Program For 1-3/8" Rotary Drilling Line; Goal of 17.0 T-M/Ft Cut Table - M5-p10a Wire Rope Cut-off Program, 1-3/8" Rotary Drill Line, Goal: 17.0 T-M/ft cut

1. Do not accumulate more than 2400 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 2400 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 17.0). 3. This program is based upon a goal of 17.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

International Association of Drilling Contractors

M-67

IADC Drilling Manual - Eleventh Edition

Cut-Off Program For 1-3/8" Rotary Drilling Line; Goal of 18.0 T-M/Ft Cut Table - M5-p10b Wire Rope Cut-off Program, 1-3/8" Rotary Drill Line, Goal: 18.0 T-M/ft cut

1. Do not accumulate more than 2600 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 2600 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 18.0). 3. This program is based upon a goal of 18.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

M-68

International Association of Drilling Contractors

Chapter M: Wire Rope

Cut-Off Program For 1-3/8" Rotary Drilling Line; Goal of 19.0 T-M/Ft Cut Table - M5-p11a Wire Rope Cut-off Program, 1-3/8" Rotary Drill Line, Goal: 19.0 T-M/ft cut

1. Do not accumulate more than 2700 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 2700 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 19.0). 3. This program is based upon a goal of 19.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

International Association of Drilling Contractors

M-69

IADC Drilling Manual - Eleventh Edition

Cut-Off Program For 1-3/8" Rotary Drilling Line; Goal of 20.0 T-M/Ft Cut Table - M5-p11b Wire Rope Cut-off Program, 1-3/8" Rotary Drill Line, Goal: 20.0 T-M/ft cut

1. Do not accumulate more than 2800 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 2800 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 20.0). 3. This program is based upon a goal of 20.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

M-70

International Association of Drilling Contractors

Chapter M: Wire Rope

Cut-Off Program For 1-3/8" Rotary Drilling Line; Goal of 21.0 T-M/Ft Cut Table - M5-p12a Wire Rope Cut-off Program, 1-3/8" Rotary Drill Line, Goal: 21.0 T-M/ft cut

1. Do not accumulate more than 2900 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 2900 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 21.0). 3. This program is based upon a goal of 21.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

International Association of Drilling Contractors

M-71

IADC Drilling Manual - Eleventh Edition

Cut-Off Program For 1-3/8" Rotary Drilling Line; Goal of 22.0 T-M/Ft Cut Table - M5-p12b Wire Rope Cut-off Program, 1-3/8" Rotary Drill Line, Goal: 22.0 T-M/ft cut

1. Do not accumulate more than 3200 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 3200 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 22.0). 3. This program is based upon a goal of 22.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

M-72

International Association of Drilling Contractors

Chapter M: Wire Rope

Cut-Off Program For 1-3/8" Rotary Drilling Line; Goal of 23.0 T-M/Ft Cut Table - M5-p13a Wire Rope Cut-off Program, 1-3/8" Rotary Drill Line, Goal: 23.0 T-M/ft cut

1. Do not accumulate more than 3200 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 3200 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 23.0). 3. This program is based upon a goal of 23.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

International Association of Drilling Contractors

M-73

IADC Drilling Manual - Eleventh Edition

Cut-Off Program For 1-3/8" Rotary Drilling Line; Goal of 24.0 T-M/Ft Cut Table - M5-p13b Wire Rope Cut-off Program, 1-3/8" Rotary Drill Line, Goal: 24.0 T-M/ft cut

1. Do not accumulate more than 3200 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 3200 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 24.0). 3. This program is based upon a goal of 24.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

M-74

International Association of Drilling Contractors

Chapter M: Wire Rope

Cut-Off Program For 1-1/2" Rotary Drilling Line Cut-Off Program For 1-1/2" Rotary Drilling Line; Goal of 23.0 T-M/Ft Cut Table - M5-p14a Wire Rope Cut-off Program, 1-1/2" Rotary Drill Line, Goal: 23.0 T-M/ft cut

1. Do not accumulate more than 3400 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 3400 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 23.0). 3. This program is based upon a goal of 23.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

International Association of Drilling Contractors

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Cut-Off Program For 1-1/2" Rotary Drilling Line; Goal of 24.0 T-M/Ft Cut Table - M5-p14b Wire Rope Cut-off Program, 1-1/2" Rotary Drill Line, Goal: 24.0 T-M/ft cut

1. Do not accumulate more than 3600 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 3600 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 24.0). 3. This program is based upon a goal of 24.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

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Cut-Off Program For 1-1/2" Rotary Drilling Line; Goal of 25.0 T-M/Ft Cut Table - M5-p15a Wire Rope Cut-off Program, 1-1/2" Rotary Drill Line, Goal: 25.0 T-M/ft cut

1. Do not accumulate more than 3700 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 3700 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 25.0). 3. This program is based upon a goal of 25.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

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Cut-Off Program For 1-1/2" Rotary Drilling Line; Goal of 26.0 T-M/Ft Cut Table - M5-p15b Wire Rope Cut-off Program, 1-1/2" Rotary Drill Line, Goal: 26.0 T-M/ft cut

1. Do not accumulate more than 3800 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 3800 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 26.0). 3. This program is based upon a goal of 26.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

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Cut-Off Program For 1-1/2" Rotary Drilling Line; Goal of 27.0 T-M/Ft Cut Table - M5-p16a Wire Rope Cut-off Program, 1-1/2" Rotary Drill Line, Goal: 27.0 T-M/ft cut

1. Do not accumulate more than 3900 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 3900 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 27.0). 3. This program is based upon a goal of 27.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

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Cut-Off Program For 1-1/2" Rotary Drilling Line; Goal of 28.0 T-M/Ft Cut Table - M5-p16b Wire Rope Cut-off Program, 1-1/2" Rotary Drill Line, Goal: 28.0 T-M/ft cut

1. Do not accumulate more than 4000 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 4000 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 28.0). 3. This program is based upon a goal of 28.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

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Cut-Off Program For 1-5/8" Rotary Drilling Line Cut-Off Program For 1-5/8" Rotary Drilling Line; Goal of 28.0 T-M/Ft Cut Table - M5-p17a Wire Rope Cut-off Program, 1-5/8" Rotary Drill Line, Goal: 28.0 T-M/ft cut

1. Do not accumulate more than 4000 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 4000 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 28.0). 3. This program is based upon a goal of 28.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

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Cut-Off Program For 1-3/4" Rotary Drilling Line Cut-Off Program For 1-3/4" Rotary Drilling Line; Goal of 31.0 T-M/Ft Cut Table - M5-p17b Wire Rope Cut-off Program, 1-3/4" Rotary Drill Line, Goal: 31.0 T-M/ft cut

1. Do not accumulate more than 4000 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 4000 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 31.0). 3. This program is based upon a goal of 31.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

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Cut-Off Program For 1-3/4" Rotary Drilling Line; Goal of 32.0 T-M/Ft Cut Table - M5-p18 Wire Rope Cut-off Program, 1-3/4" Rotary Drill Line, Goal: 32.0 T-M/ft cut

1. Do not accumulate more than 4000 ton-miles between cuts, even on the first cut of a new line. 2. So long as less than 4000 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your "ton-miles per foot cut" is constant (length to cut = T-M since last cut % 32.0). 3. This program is based upon a goal of 32.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

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M-6 Drum And Reel Capacity A. Design Factor Design factor is defined as the ratio of nominal wire rope breaking strength to the wire rope tension. The maximum rope tension occurs in the fast line or "lead line" because of friction losses due to rope stiffness and bearing inefficiencies throughout the system. Consequently, the lead line tension is greater than the weight of the load divided by the number of parts of line. To calculate design factor it is necessary to compute the Load line tension using the following equations and table of lead line constants. Design Factor = (Nominal Rope Strength)/(Lead Line Tension) Lead line Tension = Weight of Load X Constant See Table M6-1 for a summary of Lead Line Constants. Table M6-1. Lead Line Constants

See Table M6-2. for Nominal Rope Strength 6 x 19, Bright (Uncoated), Independent Wire Rope Core.

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Table M6-2. Nom. Rope Strength 6 x 19, Bright, IWRC

Example If the weight indicator reads 304,000 lbs with 10 parts of 1-3/8" improved plow drilling line, the design factor may be calculated as follows: Lead Line Tension = Weight of Load x Constant Lead Line Tension = 304,000 lbs x 0.1224 = 37,210 lbs Design Factor

= (Nominal Rope Strength)/(Lead Line Tension)

Design Factor

= (167,000 lbs)/(37,210 lbs) = 4.5

For convenience, the design factors have been calculated for various sizes and grades of drilling line as shown in the following Table M6-3.

Tables on M6: Union Wire Rope Design Factors For 1" thru 2" Rotary Drilling Lines A similar table is available for your specific requirements.

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Figure M6-2 Example 8/10 Part String-Up

Let: A = Depth of rope space on drum, inches B = Width between drum flanges, inches D = Diameter of drum barrel, inches H = Diameter of drum flanges, inches K = Factor from table below for size of line selected Y = Depth not filled on drum or reel, inches ( Case 2 only) API Recommended Practice 9B and most wire rope manufacturers suggest a minimum design factor of 3.0 for drilling and tripping. If heavier loads are used so that the design factor drops below 3.0, the ton-mile service falls off sharply. Below a design factor of about 2.0, wire rope is permanently and irreversibly damaged. Consequently, 3.0 would seem to be a realistic minimum for safe operation, giving some margin for stuck pipe and similar emergencies. Rigs running with loads so light that their design factor is above 7.0 for extended periods of time will not be able to get expected ton-mile service. Laboratory tests and actual field experience confirm that with light loads, the tonmiles add up so slowly that the wire rope will wear out in fatigue due to the higher number of bending cycles required to accumulate each ton-mile. These high design factors are especially common on workover rigs. When this is the case, it is a good idea to make cuts more frequently than normal, perhaps every few round trips. Another problem is that a high design factor means that too many parts of line are strung. An excessive number of parts of string-up puts extra rope on the drum where crossover and wear take their toll on the life of the rope. The excessive length in the string-up takes more cuts to work through the reeving system, and consequently any section of rope is in the system longer than necessary before it is finally cut off. An example of using the fewest possible parts of string-up while still maintaining a safe rig operation and reasonable design factors is illustrated.

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Example: 1-3/8" EIP Rotary Line Constant Weight: TBA Wt. (40,000 lbs)

+ Drill Collar Excess Wt. (30 @ 138 lbs/ft = 92,871 lbs)

Total: 132,871 lbs (Total) Maximum Indicated Load (Design Factor = 3.0): Constant Weight (132,871 lbs) Drill Pipe Weight (4-1/2"DP of 16.6 lbs/ft = 296,310 lbs) Maximum Indicated Load (Design Factor = 3.0) Constant Weight (132,871 lbs ) Drill Pipe Weight (4-1/2" DP of 16.6 lbs/ft = 388,025 lbs)

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Figure M6-1 10 Part Stringup

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Table M6-3 Union Wire Rope Design Factors for 1-3/8" IPR Drilling Line (Example Only)

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A 12-part string-up would be required for setting casing having a total buoyed weight of more than 480,000 lbs.

B. Design Factor Charts Design factor Tables M6-4 through M6-21 for 1" to 2" Union Wire Rope, "Improved Plow Rotary Line", IPRL, and "Extra Improved Plow Rotary Line", EIPRL.

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Tables on M6: Union Wire Rope Design Factors For 1" thru 2" Rotary Drilling Lines

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M-7 Wire Rope - Ton Mile Calculations - Special Applications Table M7-1 TON-MILES FOR JARRING DOWN (BUMPER JARS)

*Example Number 1: If approximately 25 pulls are made on 12,000' of clear 5" (19.5 ppf) pipe, the ton-miles accumulated are: 0.505 x 25 = 13 ton-miles. Example Number 2: If approximately 100 pulls are made on 20,000' of clear 4-1/2" (16.6 ppf) pipe, the ton-miles accumulated are: 1.59 x 100 = 159 ton-miles.

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Table M7-2 TON-MILES FOR JARRING UP (OIL JARS)

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Table M7-3 TON-MILES FOR WORKING CASING

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Table M7-4 TON-MILES FOR PULLING ON STUCK PIPE

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M-8 Appendix - Ton Mile Formulas Introduction The ton mile tables in this manual are designated to include the most common operating situations, however, they are not exhaustive. Variations in pipe weight (drill pipe, tubing, etc.), excess weight, and fluid weight (mud, gas, air, foam, etc.) make an exhaustive set of ton mile tables impractical for this manual. Where the ton mile tables can not be used the following ton mile formula (from which the tables are derived) may be applied.

1. Round-Trip Operations: Most of the work done by a drilling line is that performed in making round trips (or half-trips) involving running the string of drill pipe into the hole and pulling the string out of the hole. The amount of work performed per round trip can be determined by use of the following formula: TR = {D (Ls + D)Wm + 4D(M + 1/2C)}/10,560,000

Equ. (4.1)

Where: TR = ton-miles (weight in tons times distance moved in miles) D = depth of hole, ft Ls = length of drill-pipe stand, ft N = number of stands of drill-pipe Wm = effective weight per foot of drill-pipe, lbs from Figure M8-1 M = total weight of traveling block-elevator assembly, lb. C = effective weight of drill-collar assembly from Figure M8-2 minus the effective weight of the same length of drill-pipe, lbs, from

2. Drilling Operations: The ton-miles of work performed in drilling operations is expressed in terms of work performed in making round trips, since there is a direct relationship as illustrated in the following cycle of drilling operation. 1. Drill ahead length of the kelly. 2. Pull up length of the kelly. 3. Ream ahead length of the kelly. 4. Pull up length of the kelly to add single or double. 5. Put kelly in rat hole. 6. Pick up single or double. 7. Lower drill stem in hole. 8. Pick up kelly. Analysis of the cycle of operations shows that for any one hole, * operations 1 and 2 is equal to one round trip; * operations 3 and 4 is equal to another round trip; * operation 7 is equal to one-half a round trip;

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* operations 5, 6, and 8, in this case, equals another one-half round trip. The work of drilling this hole equals three round trips to bottom, expressed as: Td = 3 (T2-T1)

Equ. (4.2)

Where: Td = ton-miles drilling T1 = ton-miles for one round trip at depth D1 (depth where drilling started after going in hole, ft) T2 = ton-miles for one round trip at depth D2 (depth where drilling stopped before coming out of hole, ft.) If operations 3 and 4 are omitted, then formula 4.2 becomes: Td = 2 (T2 - T1)

3. Coring Operations: The ton-miles of work performed in coring operations, as for drilling operations, is expressed in terms of work performed in making round trips, since there is a direct relationship that is illustrated in the following cycle of coring operations. 1. Core ahead length of core barrel. 2. Pull up length of kelly. 3. Put kelly in rat hole. 4. Pick up single. 5. Lower drill stem in hole. 6. Pick up kelly. Analysis of this operational cycle shows that for any one hole: * operations 1 and 2 is equal to one round trip; * operation 5 is equal to one-half a round trip, and * operations 3, 4, and 6, in this case, equals another one-half round trip. The work of drilling this hole is equivalent to two round trips to bottom, expressed as: Tc = 2 (T4 - T3) ..... (4.3) Where: Tc = ton-miles coring T3 = ton-miles for one round trip at depth D3 (depth where coring started after going in hole, ft.) T4 = ton-miles for one round trip at depth D4 (depth where coring stopped before coming out of hole, ft.) NOTE: Extended coring operations are not generally done.

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4. Setting Casing Operations: The calculation of the ton-miles for the operation of setting casing should be determined as in Par. 1, as for drill pipe, but with the effective weight of the casing being used, and with the result being multiplied by one-half, since setting casing is a one-way (1/2 round-trip) operation. Determine Ton-miles for setting casing from: Ts = {D (Lcs + D) x Wcm + 4 D (M + 1/2C)}/21,120,000

Equ.(4.4)

But as excess weight for drill collars need not be considered, this simplifies to: Ts = {D (Lcs + D) x Wcm + 4 D}/21,120,000

Equ.(4.4a)

Where: Ts

= ton-miles setting casing

Lcs = length of joint of casing, ft. Wcm = effective weight per foot of casing, lbs. This may be estimated from data given in Table M4-1 for drill pipe, or calculated as follows: Wca = Wca (1 - 0.015B) Where: Wca = weight per foot of casing in air, lb. B

= weight of drilling fluid, lb/gal, from Table M4-1 or Table M4-2

5. Short Trip Operations: The ton-miles of work performed in short trip operations, as for drilling and coring operations, is also expressed in terms of round trips. Analysis shows that the ton-miles of work done in making a short trip is equal to the difference in round trip ton-miles for the two depths in question. This can be expressed as follows: Tst = Ts - Td

(Equ 4.5)

Where: Tst = ton-miles for short trip Ts = ton-miles for one round trip at depth Ds (shallower depth) Td = ton-miles for one round trip at depth Dd (deeper depth)

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Table M8-1 Drill Collar Weights Pounds Per Foot

Table M8-2 Travelling Block Weights

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Chapter N Lubrication

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Table of Contents - Chapter N Lubrication N1. Lubrication ........................................................................................................................................ N-4 I. Conditions ....................................................................................................................................... N-4 IIA. Glossary ...................................................................................................................................... N-4 IIB: Definitions -- General ................................................................................................................... N-5 IIC. Definitions -- Lubricant Additives ................................................................................................. N-7 N2. Types Of Lubrication ......................................................................................................................... N-9 I. Engine Crankcase Oil ...................................................................................................................... N-9 C. Government and Industry Specifications ....................................................................................... N-10 II. Industrial Gear Oils ...................................................................................................................... N-11 III. Hydraulic Oils ............................................................................................................................. N-12 IV. Grease ........................................................................................................................................ N-13 V. Tool Joint Lubricants .................................................................................................................... N-14 VI. Rust Preventives ......................................................................................................................... N-14 N3. Lubrication Practices ....................................................................................................................... N-15 I. Introduction ................................................................................................................................... N-15 II. General Hints On Lubrication ....................................................................................................... N-15 III. Cooling System ........................................................................................................................... N-15 IV. Record Keeping .......................................................................................................................... N-16 V. Storage And Handling Of Lubricants ............................................................................................. N-18 N4. Cold Weather Conditions ................................................................................................................. N-19 1. Introduction .................................................................................................................................. N-19 II. Rig Enclosures ............................................................................................................................. N-19 III. Engines And Power Plants .......................................................................................................... N-19 IV. Chain Drives, Compounds, Gear Reducers, Slush Pumps & Rotary Tables ................................... N-20 V. Grease Applications ..................................................................................................................... N-21 VI. Thread Lubricants ....................................................................................................................... N-22 VII. Blow-out Preventers .................................................................................................................. N-22 VIII. Machinery Storage ................................................................................................................... N-22 IX. Lubricant Storage ....................................................................................................................... N-22 X. Summary ..................................................................................................................................... N-23 XI. Fuel ............................................................................................................................................ N-23

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CHAPTER N Lubrication The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study. This chapter was updated under the direction of Mr. Chuck Rayburn of Grasso Oil Services.

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N1. Lubrication I. Conditions A. General The three basic conditions of lubrication should be understood by anyone having the operation of machinery under his supervision. These conditions are: full film lubrication, boundary lubrication, and extreme pressure (E.P.) lubrication. The first two of these conditions are always encountered in the moving parts of any machine and often the third. 1. Full Film Lubrication Full Film Lubrication exists where the friction surfaces are completely separated by a film of oil. In the case of the bearing, the area must be adequate for the load. Also, the shaft or other moving part must be at or above a certain critical speed for the lubricant being used. The oil, which adheres to both the shaft and its bearing, is drawn between them in the form of a wedge which completely supports the load. Oil can be too thin to fully support the load and resist being squeezed out. In this respect, the small clearance in bearings is very important in preventing the oil film from being squeezed out. The closer the clearance and the higher the speed, the more the load that can be carried on a full film of a particular oil. 2. Boundary Lubrication Boundary Lubrication is a form of effective lubrication in the absence of a full fluid film. It is effected by additives that provide a greater film strength than that of the base oil alone. 3. Extreme Pressure (EP) Conditions Extreme Pressure (EP) Conditions exist where surface loads are too great for base oil films to prevent metal to metal contact and afford adequate protection against friction through oiliness properties. In oil field work, two types of extreme pressure are encountered. a. One is in the pins and boxes of tool joints and drill collars as well as pipe threads where motion is slow during setting up and none exists thereafter, but where the final pressures are enormously high. b. The other is on gears, especially of the "Hypoid" type, where very high pressures on very small surface areas are combined with high rubbing speeds. Special additives prevent high friction, wear, or scoring under these conditions; they are mandatory for Hypoid gears.

B. Purpose A lubricant for any given type of bearing must perform four primary jobs: The reduction of friction and wear, the carrying away of heat, the cleaning of contact surfaces between moving parts, and the sealing out of dirt and water.

IIA. Glossary A. Introduction Nearly everyone associated with machinery is a user of petroleum products; namely, fuels and lubricants. Yet, to a large degree, many users are still not familiar with standard terms and definitions applied to petroleum products. The purpose of this section is to define the commonly used terms associated with petroleum products, and to give the user a workable degree of familiarity with these terms in a layman's language. Only in this way can the user make knowledgeable choices of the correct type of products to protect his equipment.

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IIB: Definitions -- General ADDITIVE -- A chemical added in small quantities to a petroleum product to enhance particular properties. The various additives used in lubricant formulation are defined in N1-IIC. Definitions -- Lubricant Additives AGMA -- American Gear Manufacturers Association. One of their activities is to establish and promote standards of gear lubricants on an industry-wide basis. API -- American Petroleum Institute. A society to further the interests and standards of the petroleum industry. Some of the API projects have been the crankcase oil service classifications, and drilling industry thread compounds. ASTM -- American Society of Testing Materials. An organization devoted to "the promotion of knowledge of the materials of engineering, and the standardization of specifications and methods of testing." Many of the current petroleum products tests are in accordance with ASTM test standards. ANTI-SEIZE COMPOUND -- A grease-like material containing powdered metals or metallic oxides, frequently applied to threaded joints to facilitate separation and to prevent seizure. ASH CONTENT- In lubricating oils, generally referred to as "sulphated ash." Represents the non-combustible residue, usually due to the presence of metallic additives. The choice of engine crankcase oils in some cases is dependent on the sulphated ash content of the oil. AUTOMATIC TRANSMISSION FLUID -- Fluid suitable for automatic transmissions of passenger cars and light trucks. May also be used in some torque converters. Usually about SAE 10W/20 viscosity with a low pour point. BACTERICIDE -- An additive material used to inhibit bacterial growth. Most commonly used in cutting fluids and in thread compounds. CHANNEL -- To form a groove in grease or heavy oil too viscous to flow under existing conditions. The temperature at which this occurs is called the channel point, and is an indication of the low temperature operating limits. COMPOUNDED OIL -- Special blend of petroleum oil with small amounts of fatty or synthetic fatty oils. This imparts a strong attraction for metal surfaces and increases lubricity and load carrying ability. Commonly used in worn gears and gear cases subject to heavy moisture. DEMULSIBILITY -- The separation of an oil/water emulsion. Lubricants with good demulsibility qualities will rapidly separate from water when the mixture is at rest. DIESTERS -- A group of chemical fluids commonly referred to as synthetic lubricants. Chosen for specific enhanced properties exceeding conventional petroleum base oils. DROPPING POINT -- Lowest temperature at which a grease becomes sufficiently fluid to drip under a particular ASTM test. Has only limited significance to service performance. GEAR OIL (AUTOMOTIVE) -- Relatively high viscosity oils for the lubrication of transmissions and drive axles. EP type gear oils may be used in transmissions and are mandatory for hypoid drives. Typical EP gear oil quality level is MIL-L-2105D. Available in various SAE Gear Oil viscosities. GEAR OIL (INDUSTRIAL) -- High quality oil for gear cases. Performance levels typically specified by AGMA lubricants numbers. Where EP properties are not required, turbine oils with rust and oxidation inhibitors are generally recommended. For worm gears and heavily loaded gear cases, and EP type gear oil, different from automotive gear oils are used. Industrial EP Gear oils should not be used in automotive service.

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GREASE -- Is an oil lubricant in combination with some thickening agent to produce a plastic-like material and is used where fluid oil lubrication is mechanically unsuitable. Common thickening agents are various metallic soaps, silica gel, silicones and clay. The major constituent is the lubricating oil and the properties of the oil used govern the temperature range and the capabilities of the grease. HYPOID GEARS -- Special bevel gear arrangement where the two gear-shaft axles do not intersect. Widely used in automotive differentials. Has high unit loading and requires EP gear oils. ISO -- International Standards Organization. An organization established to combine lubricant specifications into a single order. Under this system ISO grades would be established and reference to AST, ASE, ASA, etc., would be discontinued. ISO/ASTM INDUSTRIAL LUBRICANT VISCOSITY -- A system of viscosity grading adopted by the International Organization for Standardization (ISO), and mandated for international trades as of 1/1/78. See N1-P2 ISO/ ASTM Industrial Lubricants Viscosity Grades. NOTE: Each grade 50% more viscous than previous grade range +/- 10%. NLGI (NATIONAL LUBRICATING GREASE INSTITUTE) -- Responsible for developing a system of consistency grades for grease, based upon rates of penetration. OXIDATION -- A form of chemical deterioration of petroleum products when subjected to heat and oxygen. Above 200°F the rate of oxidation doubles for every 18°F rise in temperature. OXIDATION STABILITY -- The resistance of a petroleum product to oxidation. Used as an indication of the service life and storage life of lubricants. pH -- A measure of acidity or alkalinity. Used to evaluate the condition of used oils. POUR POINT -- The lowest temperature at which an oil will start to flow. Of limited use in determining cold weather capabilities of an oil, but often used as an indicator. R&O -- Rust and oxidation inhibited. Term applied to machine, circulating, hydraulic and compressor oils for long service. The highest quality R&O oils are often referred to as "Turbine Oils." RING OILER -- A device for lubricating a bearing by means of a loose ring riding on a shaft, with the lower part of the ring dripping in an oil reservoir. Large electric motors and generators frequently use this system. RUST PREVENTIVES (Petroleum Base) -- Compounds that give non-permanent protection to metal surfaces against the effects of moisture. Often used on machinery for long storage and seasonal lay-up. These are not to be confused with rust inhibitors used in lubricating oils. SAE (SOCIETY OF AUTOMOTIVE ENGINEERS) -- Organization responsible for the establishment of many U.S. automotive and aviation standards, such as crankcase oil and gear-oil viscosities. SAE GRADES -- These are viscosity grades of both crankcase oils based on Kinematic viscosity measurements. SAYBOLT UNIVERSAL SECONDS (SUS or SSU) -- Is the reported viscosity of a given oil at a given temperature as determined in a Saybolt viscosimeter. This method of determination has been largely superseded by Kinematic systems where the unit is the stoke or centistoke. STRAIGHT MINERAL OIL -- A petroleum oil containing no additives, in some instances, rust and oxidation inhibitors may be present, but no detergents or EP agents. SYNTHETIC HYDROCARBONS -- A group of specialized olefin base chemicals often used in selected lubricant applications. TIMKEN OK LOAD -- Is a measure of the EP properties of a lubricant. Minimum values are often specified for gear oils and greases.

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TURBINE OIL -- Top quality rust and oxidation inhibited oil used for long-service, exacting applications. VISCOSITY -- Measure of a fluid's resistance to flow. It is usually expressed in terms of the time required for a standard quantity of fluid at a specified temperature to flow through a standard orifice. The higher the value, the more viscous the liquid. Viscosities of petroleum oils are commonly reported in Saybolt Universal Seconds (SUS or SSU). Kinematic viscosities are reported in centistokes (Cs). European systems include Redwood and Engler, all of which can be related to Saybolt Universal Seconds. SAE, ASTM and AGMA have established viscosity grades that have been recognized throughout the industry. VISCOSITY INDEX (V.I) -- The measure of the rate of change of viscosity within a given temperature range.

IIC. Definitions -- Lubricant Additives The performance of lubricants in various applications has been enhanced by the contribution of chemical additives. Additive technology is very complex and exacting and the indiscriminate use of additives in the field should be discouraged. Descriptions of some additives used in lubricant formulations follows: ANTI-OXIDANT -- Minimizes the formation of resins, varnish, acids, sludge and polymers. ANTISEPTIC -- Prevents bacterial growth. Used in cuttings oils, soluble oils, and in thread lubricants. ANTI-WEAR -- Additive reacts with the metal to form a lower melting point alloy to create fluid film lubrication and to allow a new distribution of load. ZDDP, zinc dialkyl dithiophosphate, and Tricresyl Phosphates commonly used. Chief use is in hydraulic oils and crankcase oils. CORROSION INHIBITOR -- Protects bearing and other metal surfaces from corrosion. Often are organic zinc, sulphur and phosphorous compounds. DETERGENT -- Most commonly used in engine crankcase oils. Controls build-up of varnish and sludge by reacting with oxidation products to form oil soluble material which remains suspended in the oil. Normal or basic Calcium and Barium Sulphonates are widely used. DISPERSANTS -- Have a strong affinity for solids such as dirt particles. The particles are surrounded by oil soluble molecules which prevent agglomeration and deposits with the system. Most commonly used in crankcase oils. EMULSIFIER -- Allows mineral oil to be mixable with water. Frequently used in metal cutting oils and in some lubricants for wet applications. EXTREME PRESSURE -- Prevents seizure and welding between metal surfaces under local conditions of extreme pressure and temperature. Sulphurized fats and chlorinated hydrocarbons are frequently used. Main use is in gear oils. FOAM SUPPRESSANTS -- Silicone polymers which do not prevent the formation of foam, but reduce the interracial tension of the bubble film to enable the bubbles to rupture readily. OILINESS -- Fatty materials which increase oil film strength to prevent oil film rupture. Highly attracted to metal surfaces to cushion and keep the metal surfaces apart. POUR DEPRESSANT -- Lowers the pour point of the oil by preventing the agglomeration of wax crystals. Used frequently in low temperature oils, and to a lesser degree in some fuels. RUST INHIBITOR -- Protects ferrous metal surfaces against rust, by polar attraction to metal surfaces. Serves as a barrier to water. TACKINESS -- Tacky, stringy materials to provide greater cohesion to the oil. Used in greases and no-drip oils, such as chain oils.

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VISCOSITY INDEX IMPROVER -- Reduces the rate of change of viscosity with change in temperature. These are usually some form of polymer subject to mechanical shear. Frequently use

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N2. Types Of Lubrication I. Engine Crankcase Oil A. SAE Viscosity Classification Viscosity is perhaps the single most important property in choosing a lubricant for a particular application. For many years, the SAE system classified crankcase oils on the basis of SSU viscosities (Seconds, Saybolt Universal). A recent revision of the system replaced the SSU viscosities with kinematic viscosity measurements, while keeping the seven SAE grade numbers, as shown in Table N2-1. Table N2-1 SAE Auto Crankcase Oil Viscosity Grade Classification

Minimum viscosity for any crankcase oil in the new SAE classification is 3.8 cS (38 SSU) at 100°C. The system is based solely on viscosity; other factors of oil quality or performance are not considered.

B. Engine Service Classification The American Petroleum Institute (API), American Society for Testing Materials (ASTM), and Society of Automotive Engineers (SAE), together with the auto and engine builders established the ENGINE SERVICE CLASSIFICATION which was adopted in 1970. This system is based on engine tests, both for gasoline and diesel engines which more precisely defines the performance of each class of service. The ENGINE SERVICE CLASSIFICATION system established nine grades of service. The earlier ones, while obsolete, serve to show how the current classifications have evolved. It is by these designations that the engine builder indicates oil quality requirements. Table: Engine Service Classification System

Service Oils SA* -- for utility gasoline and diesel engine service

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SB* -- for minimum duty gasoline engine service. Above categories are for very moderate engine use and may be considered obsolete, to the point where few, if any, engine builders recommend this quality. SC -- for gasoline engines operating under conditions meeting the builders warranties for the years 1964 through to 1967. SD -- for gasoline engines in 1968 to 1970 passenger cars and some trucks operating under engine manufacturers' recommendations in effect for those model years. SE -- for 1972 through 1980 gasoline engine warranty maintenance service, in passenger ears and some trucks. SF -- for 1981 through 1988 gasoline engine warranty maintenance service, in passenger cars and some trucks. SG -- Meets warranty requirements for 1989 and newer model vehicles. Improves sludge control. Commercial Oils CA -- for light duty Diesel engine service CB -- for moderate duty Diesel engine service. Oils of these two categories were widely used in the late 1940's and 1950's. They have been superseded by the two following designations which encompass more severe engine operating conditions. CC -- moderate Duty Diesel and gasoline engine service. Used in moderate supercharged diesel engines and heavy duty gasoline engines. CD -- Severe Duty Diesel Engine Service. Designed for service in supercharged high-speed, high output Diesel engines, where control of engine wear and deposit is critical. CD II -- Severe duty 2-cycle diesel engines: Meets CD plus Detroit Diesel 6V-53T engine test requirements. CE -- Severe duty turbocharged 4-cycle diesel engines: highest protection against high- and low-temperature deposits, wear and corrosion. CF -- Severe duty turbocharged 4-cycle diesel engines: highest protection against high and low temperature deposits, wear, and corrosion, especially including late model (since 1988) lower emission engines. Crankcase oils can meet more than one classification requirement and are usually so designated. The official viscosity values are based on 100oC viscosities in centistokes (ASTM D445) and 0°F viscosities in centipoises (ASTM D2602 cold cranking simulator). Approximate values in SUS are given for information only.

C. Government and Industry Specifications In addition to the API Engine Service Classifications, both Federal Government and Engine Builders have established oil performance specifications which are in many ways related. Table N2-2 indicates the equivalent specifications.

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Table N2-2 Equivalent Classifications and Specifications

II. Industrial Gear Oils Industrial gear oils may be divided into three distinct types:

A. Straight Mineral Gear Oils Petroleum-base oils that do not have extreme pressure additives or compounding to improve load carrying ability. They may contain rust and oxidation inhibitors and in some cases, foam suppressors. These oils will satisfy most requirements for spur, helical and spiral bevel gear units as well as for some high-speed roller chain drives. They must not be used with hypoid or worm gear sets.

B. Extreme Pressure Gear Oils Petroleum-base lubricants containing special chemical additives to increase the load carrying ability of the oil under local conditions of high temperature and pressure. As a rule, these EP additives are not particularly thermally stable. They should not be used where oil temperatures continually exceed 200°F. EP Gear Lubricants should be used only when specified by the gear drive manufacturer. They are generally used in heavily loaded gear sets, in hypoid and worm gear drives.

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C. Compound Gear Oils A blend of petroleum-base lubricant with 3 to 10 percent fatty or synthetic fatty oils. They are generally recommended for worm gear drives. As indicated earlier, viscosity is still the most important consideration in choosing the correct gear lubricant. Table N2-3 defines the various viscosity grades in accordance with AGMA standards for enclosed gear drives. Table N2-3 Viscosity Ranges for AGMA Gear Drive Lubricants

NOTE on table N2-3: Oils marked comp. are compounded with 3% to 10% fatty or synthetic fatty oils.

III. Hydraulic Oils A. General Hydraulic oils perform the dual function of lubrication and the transmission of power. To perform these functions, hydraulic oils must have the following essential qualities: * correct viscosity * high oxidation resistance * high viscosity index * water separating ability * adequate film strength * rust resistance * anti-wear properties * resistance to foaming

B. Pump Oils Hydraulic pump manufacturers determine the most suitable viscosity for their equipment. General recommendations follow (see Table T2-P4 below):

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Table T2-P4 Hydraulic Pump Lubricants

Note: Oil viscosity should not be less than about 70 SUS at operating temperature. An important oil quality is its ability to minimize wear under the thin film or boundary lubrication condition that exists between closely fitted parts, particularly in the pump assembly. The film strength of the base oil can be improved by the use of anti-wear additives, similar to those used in current automotive crankcase oils. The "new generation" hydraulic oils, or oils carrying the description "AW" refers to oils with added anti-wear properties.

C. Blow-Out Preventers BOP systems, while a form of hydraulics, differ from conventional hydraulic systems in that they are under pressure from some form of gaseous accumulator, and are infrequently operated, in comparison to a constantly running mechanical system. The oil used has been generally a low viscosity oil (60 SUS @ 100°F.) to ensure an adequate low temperature performance, and fortified with rust and oxidation inhibitors. In some areas, the use of water/soluble oil emulsions have been used successfully and there is some interest in water/glycol solutions as well, particularly from an ecological requirement. This bears more investigation.

IV. Grease A lubricating grease is a fluid oil lubricant in combination with some form of thickening agent which produces a plastic-like material and is used in areas where fluid oil lubrication is mechanically unsuitable. The major constituent of grease is the lubricating oil. The properties of this oil are a major factor in determining the usable temperature range and other lubricating properties of the grease. The consistency (hardness) of a grease is graded by the penetration of a weighted cone into the surface of the grease. The NLGI has established a set of standards based upon penetration limits to indicate the various consistency grades, see Table N2-4.

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Table N2-4 NLGI Grease Grades

Grease application is dependent upon both the oil viscosity, and the thickener used. Oils of almost any viscosity, from as low as 60 SUS @ 100°F to as high as 160 SUS @ 210°F are in use. The thickener is usually some type of metallic soap, of which calcium lime, sodium and lithium are the most common. Mixed soap bases of calciumsodium and calcium-lithium are also used. In addition to these, barium and aluminum soaps are also used to a more limited degree. Other thickeners such as Bentonite, (clay base), which is not a metallic soap, are the basis for "no melt" types of greases. Finely divided, non-abrasive filler materials such as carbon black, asbestos, tale, mica, zinc oxide, graphite and molybdenum disulphide are used to enhance properties such as water "wash-off' resistance, acid resistance, heat resistance, anti-galling protection and load carrying ability under sparse lubrication conditions. Conventional extreme pressure additives common to automotive and industrial gear oils are also used to improve the load carrying ability of grease.

V. Tool Joint Lubricants Tool joint lubricants consist of a conventional grease base, using calcium, calcium-lithium or lithium soaps to provide water resistance, and an oil of about 500 SSU at 100°F. To this is added up to 60% metallic filler to provide the necessary thread protection under high torque, high pressure conditions. Powdered zinc, from 40% to 60% by weight in the grease is recommended by IADC and API. Thread compounds made according to API 5A2 bulletin contain various metallic fillers such as powdered zinc, copper dust and graphite, in a petroleum or silicone grease base. They are recommended specifically for easing and tubing connections in high pressure well service. The low coefficient of friction of these products decreases the torsional yield strength of tool-joint connections to such a degree this can be extremely hazardous when used on rotary shouldered connections. They are not recommended for tool joints.

VI. Rust Preventives Many drilling rigs are subject to seasonal lay-up. While most of the lubricants used on a drilling rig, such as crankcase oils, gear oils, and hydraulic oils contain rust inhibitors, experience has shown the use of special preservative compounds to be extremely beneficial. Most petroleum marketers will have rust inhibited preservative oils available, as well as protective concentrates that can be added to existing oils in use. This area of equipment protection during off-season shut-down can be costly if not carded out, and certainly merits attention.

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N3. Lubrication Practices I. Introduction The lubricating engineers employed by both the manufacturers of drilling equipment, refining companies and others cooperate in preparing specifications and schedules for lubrication of your equipment. These specifications and schedules are designed to give the user the optimum operating life of your equipment. In all cases, the weight and grade of the lubricant recommended by the manufacturers should be used. Also, the proposed schedule of applying lubricants and changing oil should be followed. Lacking such information, this section will give you reasonable hints which may be followed.

II. General Hints On Lubrication A. Greases Where greases are used, either by gun or cup application to a smooth journal or labrynth bearing, a sufficient amount should be applied so that a small amount is forced out the bearing. This removes any dirt or abrasive particles and, being on the outside, acts as a seal to prevent dirt from entering the bearing. If the bearing has seals, care should be taken to add just enough lubricant to replace that which has been used. Too much may rupture the seals. With packed bearings the bearing should be removed and cleaned thoroughly before repacking. Care should be used when changing from one base thickened grease to another. Be sure that all of the old grease is removed or purged from the bearing. Otherwise the two bases may react to reduce consistency and allow grease to run out of the bearing.

B. Lubricating Oils The additives in one oil (possible different refineries) may not blend with those of another. This may form corrosive and/or abrasive materials or may result in less effective lubrication. It would be a safe practice to flush and clean out the entire lubrication system when changing from one brand or one with different additives to another.

C. Engine Conditions Worn liners and rings allow blow-by which contaminates the crankcase oil with unburned fuel and combustion products. If the rings and liners are worn, the oil cannot effectively seal against the high pressures developed after ignition starts. Combustion products are water and carbon dioxide, which if allowed to accumulate in the crankcase, will cause severe corrosion of the bearings and possible lacquering. The combustion products may be removed by adequate crankcase ventilation at operating temperatures.

III. Cooling System The cooling system of any internal combustion engine plays an important part in the effectiveness of the lubrication system. If the heat is not removed from the cylinder liner fast enough, the inside of the liner becomes hot enough to carbonize the lubricating oil. As the oil is destroyed by heat, it loses it's lubricating quality. Also, it deposits carbon on the inside of the liner causing excessive wear, and if the deposits become thick enough, freezing of the pistons. In hard water areas, good cooling water may be obtained by using one of the commercial tank or filter type softeners.

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IV. Record Keeping A. Logs Accurate records, or logs, should be kept with respect to engine performance, oil and fuel consumption. Most engine manufacturers have available engine log forms which are in considerable detail for their engines. If these are not handy, the Drilling Technology Committee of the IADC has prepared an engine log form of a general type that is applicable to all makes and types of engines. This form is available from the Houston office of IADC.

B. Check List A check list, or lubricants survey, indicating all points of lubrication on the rig should be prepared. This list should include all points of lubrication on the power equipment, as well as the hoisting equipment and mud conditioning equipment. A sample check or lubrication list is shown in Table N3-1.

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Table N3-1 Lubrication Check List

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Notes on Table N3-1 The chart may be expanded to show two additional columns: "When," when lubrication should be done, and "Who" indicating who should be responsible. Example: Item

Method Lubricant When

Crown Block Gun

#2 EP

Who

Every trip, or 24 hrs. Daylight Derrickman

V. Storage And Handling Of Lubricants The importance of keeping equipment and lubricating systems clean cannot be overemphasized. The presence of foreign materials in new equipment and contamination from poor housekeeping of lubricants contribute to the decline in performance and the shortened life of all equipment. Care should be taken when receiving all bulk and packaged lubricants to avoid exposure to ventilation, rough handling, dents, and contamination by transfer hoses and pumps. Storage of lubricants should be under cover with all bungs and openings tightly closed when not in use. Drums and kegs, when exposed to outside storage, should be stored on their side or covered to avoid water collecting on the top. Bulk tanks and drums should be clearly labeled with correct products in storage. Personnel should be instructed in the correct application and handling of lubricants. Use of lubricants survey and properly labeled machinery can prevent misapplication of lubricants. All personnel should be made aware of environmental data sheets, material safety data sheets, and proper safety procedures for exposures to lubricants.

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N4. Cold Weather Conditions 1. Introduction This summary of recommended lubricants and field operating methods and procedures was obtained from contacts with personnel of a number of major drilling contractors who have been operating in the Canadian Arctic and High Arctic Islands for a number of years. It is based upon the field experiences of drilling superintendents, tool pushers and rig mechanics, in a very hostile environment. Over the years they have evolved methods and systems to enable their equipment to operate efficiently, providing the right selection of lubricants is made available.

II. Rig Enclosures A. General In order to even survive under extremely cold conditions, with high prevailing winds, some form of shelter and heat is, without question, the first priority. Rigs have been so designed that all surface and sub-structure components will be sheltered in some fashion, either by heavy flame resistant canvas, or by plywood and polyethylene sheets. the engine area, mud pumps, tanks and sub-structure will be fully enclosed and sheltered from any winds. The drilling floor and mast will be similarly enclosed to heights of 22 to 26 feet, with a canvas curtain across the "V-door". Top of the enclosure around the mast is frequently angled for the last two or three feet to act as a wind deflector to prevent a chimney effect on the drilling floor area. The monkey board on the mast is also enclosed to some degree and provided with electric radiant heaters for some degree of comfort to the derrick man.

B. Effect of Enclosures With the type of enclosures used, exposure to prevailing wind is reduced to a minimum. Temperatures in the engine area and in the mud system area during sustained drilling are well above freezing. In some cases, they have been reported to be above +50°F. Temperatures at the draw-works and on the working floor are somewhat lower, but nowhere near ambient, and generally quite tolerable. To supplement this, wide usc is made of steam generators and Portable, electrically-driven, high capacity fan-operated fuel oil heaters to direct heat wherever needed. Only critically exposed areas are the crown pulley, travelling block, and to some degree, the racking platform. The substructure and control stacks are well enclosed with the hydraulic lines electrically traced or steam heated. While it may seem strange, the actual drilling operation, once the fig is set up and enclosed, is no more uncomfortable or intolerable than normal winter operations in Western Canada, Northern United States or the Intermountain Areas, other than the effect of continuous darkness.

III. Engines And Power Plants A. Power Plants The Power Plant on site is usually the first piece of equipment activated after a move, and provides the necessary energy for steam generators, heaters and lights. Normally, the same crankcase oil is used as that in the rig power units, which is usually SAE 30 grade. Some operators will change out to SAE 10W grade on shut-down, in order to facilitate an easier start after a move, or on the next cold start. Once the rig has been assembled, SAE 30 grade is put back in for continued service.

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B. Main Rig Power Units Most operators contacted advise that SAE 30 grade crankcase oil is used year round. Some follow the practice of changing out to SAE 10W grade just prior to shutdown and for early run-in, once the move and reassembly has been completed. However, for continuous drilling, only SAE 30 grade is used. Those engines are often equipped with external propanefired cooling system heaters, and immersion-type oil pan heaters for cold starts. Adequate time must be allowed to thoroughly warm the engine before an attempt is made to start. Immersion-type oil pan heaters are used to a lesser degree because of the danger of oil degradation due to excessive localized heater element temperatures. In using oil pan heaters, the heating element capacity should be no more than 8 watts' per square inch of heating element area to reduce the danger of oil cooking on the element. It has been found that portable forced-air fuel oil heaters are more popular to warm engines because of their mobility.

C. Hydraulic Couplings and Torque Converters These units normally require a light-bodied oil such as SAE 10W or 5W/20. These oils will function satisfactorily down to -35°F cold. However, under the enclosed conditions and working area temperatures, there have been no particular problems associated with these units and one can normally expect very little trouble with lubrication.

D. Hydraulic Controls Most mechanically driven hydraulic systems can operate satisfactorily on SAE 20 crankcase oil. Special low temperature hydraulic oils with working ranges of -60°F to + 110°F (bulk oil temperature) have been developed and are used on a year-round basis by a number of operators. The use of low temperature, aviation-type hydraulic oils such as Mil-L-5606 has been replaced by these new Arctic hydraulic oils to some degree and they have given good performance.

IV. Chain Drives, Compounds, Gear Reducers, Slush Pumps & Rotary Tables There is some considerable variance on the choice of lubricants for these different components amongst the different operators contacted.

A. Chain Cases and Compounds Usually oils of SAE 10W or 20W straight mineral engine oils or AGMA No. 1 or No. 2 grades (non-EP) are used. Since these units are subject to continuous service at relatively high speeds, only oils containing rust and oxidation inhibitors should be used. The use of cheap "black oils" or oils referred to as "once through" oils should not be considered in any enclosed chain case. Mild extreme pressure industrial gear oils make excellent chain oils for high speed roller chain. Therefore, it is suggested the same gear oil be used in the chain cases and compounds as is used in other gear reducers, such as the rotary and the draw-works. This can be SAE 90 gear oil or AGMA 4 EP or 5 EP. One of the practices used has been to dilute the chain case with 10% to 20% diesel fuel just prior to prolong shutdown. Once the rig move has been completed and the unit re-assembled, the system is operated slowly for a time with no load. Then the oil/diesel fuel mixture is drained out and the chain cases refilled with the oil normally used. Before starting, in any event, portable forced-air fuel oil heaters are used to warm the chain case and oil sump. This may take several hours, and is always done where undiluted oil is left in the oil reservoir during shutdowns or moves.

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B. Rotary The rotary consists of a pinion-crown gear assembly, either bevel spur gear or spiral bevel design. Mild extreme pressure gear oils, AGMA No. 5 EP viscosity are used on a year-round basis. Because of the loading on the gears, this viscosity is necessary for sustained drilling. After shut-down and moves, external heating must be applied to the gear cases in order to bring the oil temperature up to at least +50°F before operating under load.

C. Slush Pumps Crankcase and gear cases usually require AGMA No. 5 EP to carry the required loads for continuous operation. Again, any form of external heat must be used to bring the oil temperature up to at least +50°F if the units are not drained when drilling operations are shut down for any length of time. SAE 140 grades of AGMA No. 7 EP are considered too heavy for cold weather operations.

D. Swivels The swivel is perhaps the most exposed rotating unit and is idle during trips and other operations. It is impossible to enclose or heat in any substantial way, although the continuous circulation of the mud through the unit does help since the mud has to be above freezing. The points to be lubricated are fairly heavy roller or tapered roller bearings and these can work satisfactorily with a relatively light viscosity oil. An SAE 90 gear oil or AGMA No. 5 EP is used extensively outside of the Arctic. AGMA No. 1 EP or Arctic grades should be used on a year around basis for northern work to provide the necessary fluidity down to about -50°F.

V. Grease Applications A. Crown Pulley and Travelling Blocks Like the swivel, these components are completely exposed to the elements and sit idle a great deal of the time. They must be called upon to work at full capacity almost at once after these idle periods and must not create a drag nor allow any slack in the wireline. For sustained cold weather service, the bearings should be cleaned and re-greased with some light Arctic type of grease; preferably Lithium base of NLGI No. I or No. 2 consistency. Greases that will dispense at -40°F and function in a bearing at -65°F are available and should be considered for year-round service in the Northern areas.

B. Electric Motors and Generators These bearings should be packed once per year and the manufacturer's recommended greasing frequency followed. Normally, with good seals, these bearings should not require any other greasing. With continuous operation and a relatively high temperature rise during running, light Arctic greases should not be used. Normally, a grease designed for long service life for anti-friction bearings of NLGI No. 2 consistency should be used. Lithium base or multi-purpose greases with dropping points of at least 300°F are used extensively. If service time is less than 80% or motor is out of use for some time, artificial heating device should be used to bring motor up to about 40°C before use.

C. Draw Works, Rotary, Shale Shaker and All Other Grease Fittings No special grease is needed here other than NLGI No. 2 multi-purpose type with good rust inhibitor. Grease guns can be kept warm for dispensing, and the units are warmed externally for the initial start-up or are kept warm through continuous operating.

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VI. Thread Lubricants A. Drill Collar Lubricants These are usually made up of 40-60% metallic zinc in. a relatively soft grease base. The pails can be kept warm in the doghouse until needed and have not presented any particular difficulty in brushing on at the prevailing working floor temperatures.

B. Tool Joint Compound Recommended tool joint compound is made up of 40% to 60% zinc dust in a medium grease base. Unless kept warm during the tripping-in operations, there can be difficulty in applying by the conventional bristle brush. Soft-low temperature compounds (Pipe Dopes) containing the same proportions of metallic zinc dust, but using a low temperature grease base are available and have been used successfully for several years. These can be readily brushed on the pin and box sections, unheated down to -40°F.

VII. Blow-out Preventers Blow-out preventer oil (BOP Fluid) is usually a low viscosity oil, such as 60 SUS at 100°F, fortified with rust and oxidation inhibitors. Typical pour points are below -50°F, to ensure good mobility at low temperatures. With the stack area enclosed, and either electrical or steam tracing on the hydraulic lines, virtually no problems due to oil viscosity have been reported.

VIII. Machinery Storage The Arctic areas are subject to almost constant winds of relatively high velocity. This causes severe drifting of very fine snow particles. It is not unusual to see vehicle cabs, with doors and windows tightly closed, to be filled to steering wheel level with packed snow. Engine compartments, radiator shutters and radiators are similarly totally filled with snow. During the periods where rigs are undergoing moves or are racked in storage, operators use large plastic sheets strapped around units to cover engines, draw-works, pumps and other compact components to avoid this type of snow being driven in. For seasonal lay-ups, engine crankcase, chain drive units, gear cases and hydraulic systems are filled with oil and extra rust inhibitors. Some form of rust inhibitor concentrate is readily available and is added directly to the various systems just prior to shut-down. For outside iron, particularly that stored near salt water, various types of rust preventative products such as plastic, asphaltic or thin film types are available and are extensively used.

IX. Lubricant Storage The remoteness of the Arctic and Arctic Islands means that all supplies must be brought in by water transportation during a very short summer shipping season. Air lift on an emergency basis is very costly. As a result, lubricating oils, mostly in 45-gallon (55 U.S. Gallons) drums are stockpiled at various staging areas, and on drilling sites for several months at a time. Normal precautions to exclude water getting into sealed drums must be taken. At the individual drilling sites, oil drums are usually piled outside and are subject to the prevailing temperature. There is usually room for a few drums in the engine area, and drums are brought in to handle the daily consumption requirements. A drum of oil brought in from the outside to the engine area will take up to 48 hours to warm up enough to be able to be poured. Oils such as SAE 90 gear oils for AGMA No.5 grades may take even longer. Adequate lead time must be provided for daily make-up requirements. Greases are usually handled in 35-pound pails and with a relatively small daily requirement, they present no storage or warming problems.

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Ethylene glycol anti-freeze must be treated in much the same fashion as oil. Pure anti-freeze, undiluted in the container, has a freeze point of about +8°F. A drum exposed to -30°F or lower for several days would require up to 24 hours in warm storage to be useable. A common practice is to remove part of the anti-freeze from a drum and fill with water for outside storage. A mix of 60% antifreeze / 40% water will give a maximum freeze point of approximately -60°F.

X. Summary In all of the discussions with drilling rig operators who have had extensive Arctic experience, there appears to be very little difference in the methods used in the Arctic from those used on the Canadian Prairies, Northern United States or Intermountain Areas during the winter drilling activities. For the most part, the same grade of lubricants are used on a year-round basis in the Arctic. The most important aspects to consider, on an individual rig, are to enclose the rig as completely as is conveniently possible, and have substantial supplies of auxiliary heat. This can be in the form of steam boilers, portable electrically driven or engine driven forced-air fuel oil heaters, electric immersion heaters, electric radiants, electrical heating tapes, and others. The object of all this is to modify the environment within the working area, by whatever reasonable means possible, to create more favorable operating and working conditions. These steps are necessary in order that the correct grades of lubricants can be used to handle the component loads encountered in continuous drilling operations. The problem of logistics, transportation, storage and freight costs to these remote locations is a major one. The recommendations made here may not necessarily be in agreement with the equipment builder, nor with other drilling contractors operating under similar conditions. We recognize the difficulties under which the men and equipment must work and, therefore, have tried to select products with the widest possible applications. This will be noted in that only two Industrial Gear Oils are used in areas such as swivels, chain cases, rotaries, compounds and any gear reducers. The type of products shown here, together with practices followed by experienced crews have, up to this time, proven satisfactory for many thousands of feet of hard drilling under most difficult conditions.

XI. Fuel A. Introduction Fuel for diesel engines in cold weather operations and for remote, more moderate climates, needs mention. The lubrication aspect will be discussed in portions of this subsection. Oil exploration and related activity in the arctic areas create many logistics and supply problems. Not the least of these is the selection, availability and storage of power fuels. Main fuel requirements are for the diesel engines and camp uses and for these there is no great problem in selecting proper grades of fuel. However, remote sites both in the Arctic and in more moderate climates are sometimes served by turbine powered aircraft. This brings up the question as to whether turbo fuels can be used in diesel engines when the latter runs short. This section discusses such suitability.

B. Specifications for Diesel Fuel The ASTM 10D standards specify the volatile fuel oils from Kerosene to intermediate distillates. Fuels of this classification are for use in high speed engines with service involving frequent and wide variations in loads and speed. Also, they are for use where abnormally low fuel temperatures may be a problem. ASTM 2-D refers to heavier summer grades of diesel fuel, not marketed in Arctic areas and specifications of which are not discussed here. More important points of the ASTM 1-D standards are:

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Cetane Number

40

Flash Point

100 or legal

Viscosity

1.4 to 2.5

Pour Point

*

* For cold weather operation, pour point should be 10°F below the ambient temperature except where fuel oil heating facilities are provided.

C. Engine Manufacturers Requirements The fuel requirements of three manufacturers of diesel engines follow: 1. Caterpillar -- Fuels with a minimum viscosity of 1.0 Cs at 100°F have given satisfactory performance with no injection pump or injector wear. 2. Cummins -- Recommended fuel oil viscosity is 1.4 Cs at 100°F minimum. Fuels that meet ASTM 1-D (or 2-D) are satisfactory. Some jet or turbine engine fuels have lower viscosity, but may be used if the viscosity is above 1.0 Cs at 100°F. Fuels lighter than 1.0 Cs should not be used without adding lubricating oil to the fuel to provide necessary lubrication. 3. Detroit Diesel -- Diesel fuels conforming to ASTM D975 for grades 1-D and 2-D only are considered satisfactory for Detroit Diesel engines. The unit injector system used in these engines is not considered sensitive to fuel oil viscosity. Fuels with viscosity as low as 1.0 Cs at 100°F have proven satisfactory.

D. Use of Jet Fuel 1. General In comparing the above discussions of ASTM and manufacturers specifications, it is noted that certain jet fuels can be used in diesel engines with some qualifications. These qualifications primarily concern the viscosity but also the hazard of using certain jet fuels for anything other than aircraft due to the blended volatile components. 2. Jet fuels Available for Diesels An example of jet fuel usable in diesel engines is Esso Turbo Fuel A-1. This fuel meets the requirements of ASTM fuel grade 1-D in all respects except viscosity. It has a viscosity of 1.3 Cs compared with 1-D specifications of 1.4 to 2.5 Cs at 100°F. Where diesel engines are considered critical or sensitive to low viscosity, following should be done: a. Add 1% SAE 10W crankcase oil to the fuel, or b. Add Esso Fuel Oil Conditioner at rate of one quart to 200 gallons of fuel. In contrast, Esso Turbo Fuel B should not be used for any other use than jet engine fuel. It is a blend of gasoline and kerosene fractions and is not suitable for diesel fuel or in heating systems. A Chevron Research Bulletin titled "Winterize and Keep Rolling" is a further reference. It states: When it is necessary to operate marginally winterized equipment at sustained subzero temperatures (-40°F and below), Chevron Pearl Kerosene or Chevron Jet Fuel A-50 can be used in all diesel engines without difficulty. These products can also be blended with Chevron Diesel fuels to lower the pour point if the situation demands it.

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3. Other Qualifications The Chevron bulletin mentioned above gives other qualifications in the use of diesel or jet fuel. When the temperature of the fuel is below the pour point one or all of the following may occur: a. Fuel solidifies and cannot be jumped to the engine. b. Wax crystals may form and plug filters, fittings and line. c. Lower boiling point lowers heating value by maximum of 5%. d. Reduced cloud and pour point reduces cetane number, making starting somewhat more difficult unless there are starting aids.

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Chapter O: Drilling Fluids

Chapter O Drilling Fluids

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Table of Contents - Chapter O Drilling Fluids 1. Drilling Fluids: Functions And Tests ....................................................................................................... O-4 I. General ........................................................................................................................................... O-4 II. Functions ....................................................................................................................................... O-4 III. Test and Mud Properties ............................................................................................................... O-4 IV. Factors Affecting Mud Performance and Cost .............................................................................. O-6 2. Types Of Drilling Fluids ......................................................................................................................... O-7 I. Water Based Drilling Fluids .............................................................................................................. O-7 II. Oil Muds ..................................................................................................................................... O-13 3. Trouble Shooting ................................................................................................................................ O-14 I. Problems ....................................................................................................................................... O-14 II. Specific Problems ........................................................................................................................ O-16 4. Calculations ........................................................................................................................................ O-23 I. Calculations ................................................................................................................................... O-23 II. Additional Aids ............................................................................................................................ O-24 5. Additives For Drilling Fluids ................................................................................................................ O-33 I. Definitions for Drilling Fluid Classification ....................................................................................... O-33 II. Drilling Fluid Systems ................................................................................................................... O-33 III. Fluid Additive Functions .............................................................................................................. O-34

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Chapter O Drilling Fluids The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study. This chapter was updated under the direction of Mr. Bill Halliday of Milpark Drilling Fluids.

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1. Drilling Fluids: Functions And Tests I. General The drilling fluid is a major factor in success of the drilling program, and as such, deserves careful study. Discussion in this Manual, however, is limited to general features. A detailed treatment from the standpoint of field application is provided in the book: "Principles of Drilling Mud Control," published by the University of Texas in cooperation with the IADC. The suppliers of mud materials offer a wide range of publications. Numerous articles on drilling fluids are to be found in the technical literature of the oil industry.

II. Functions The principal functions of the drilling fluid are: * To remove the cuttings from the bottom of the hole and carry them to the surface. * To transmit hydraulic horsepower to the drill bit. * To cool and lubricate the drill string and bit. * To exert sufficient hydrostatic pressure to control fluids encountered in formations penetrated. * To minimize settling of cuttings and weight material in suspension when circulation is temporarily stopped. The mud, however, should have properties which allow the cuttings to settle in the surface system. * To support and protect the walls of the hole. * To reduce to a minimum any harm to the formations penetrated. * To insure maximum information about the formations penetrated. The performance of these functions depends upon various properties of the mud and some compromises are often necessary. Mud performance is affected by the drilling equipment in use. The properties of the mud should be adjusted to the hydraulics available for the drilling problem to be solved. Rate of penetration is affected by the density of the mud and nature of the suspended solids. Regular and complete tests are essential to the control of mud properties. The interpretation of the results of these tests in terms of performance in the hole is vital to the success of the drilling program.

III. Test and Mud Properties Various properties of the mud are measured as an indication of the performance of the mud in the hole. Methods for measurement of these properties are stated in API RP 13B "Recommended Practice on Standard Procedure for Testing Drilling Fluids." These procedures are revised and extended periodically as new tests gain acceptance. Tests commonly made are:

Density Or Mud Weight Density Or Mud Weight affords a measure of the hydrostatic pressure of the mud column. When mud weight is reported as pounds per square inch per thousand feet, the pressure at any depth is easily calculated. Density is reported also in pounds per gallon, specific gravity, and pounds per cubic foot. Sec Table 04-1 for the relation between these units.

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Viscosity Viscosity is a measure of the internal resistance of a drilling fluid. This internal resistance, or inertia, is a result of the attractions of molecules in a liquid, and is a measure of the combined effects of these attractions and the natural cohesion of suspended particles. The greater the internal resistance, the greater the viscosity. a. The Marsh Funnel The Marsh Funnel is an instrument used to measure what is commonly called "Funnel Viscosity." The Marsh Funnel viscosity is reported as the number of seconds required for a given fluid to flow 1 quart of fluid through the calibrated orifice at the end of the funnel. b. Direct-Indication Viscometer Direct-indication viscometer is used to measure more significant rheological properties of a drilling mud. Measurements are normally made at shear rates of 600 and 300 RPMs.

Plastic Viscosity Plastic Viscosity is defined as the 600 RPM shear stress reading minus the 300 RPM shear stress reading. The Plastic Viscosity depends mainly on the friction between solids and the liquid. Plastic Viscosity is also somewhat representative of high shear rate viscosities encountered at the drill bit.

Yield Point Yield Point is defined as the 300 RPM shear stress reading minus the Plastic Viscosity. Yield Point is a measure of the attractive forces between active clay particles in the mud under flowing conditions. It is also a measure of the hole cleaning capabilities of a mud.

Gel Strength Gel Strength is a measure of the attractive forces of suspended particles in a liquid when that liquid is in a static state. Gel strength is reported in lb/100 sq ft. The gel strength influences the surge and swabbing effects of the drilling fluids when trapping the drill string, the pressure required to break circulation, ease of release of gas, and setting of suspended particles in the pits. Relative measures of gel strength properties are made on a direct indicating viscometer and are commonly reported as 10 sees and 10 min. gels.

Filtration Filtration test is a relative measure of liquid filtered into a permeable formation and of the cake left on the formation. The condition of the mud and type of solids in the mud influence filtration. There are two standard filtration test. One is at ambient temperature and 100 psi and the other at 300°F and 500 psi. The high temperature - high pressure test should preferably be run under actual bottom hole temperatures and differential pressures existing in the well bore.

Sand Content Sand Content is measured because sand is abrasive to the equipment that comes in contact with the mud and sand may cause trouble by setting in the hole or by increasing the mud weight.

Solids, Oil, And Water Content Solids, Oil, And Water Content are measured not only as a basis for the control of the oil content of emulsion muds, but also as an aid in the control of the performance of the mud. Solids content affects drilling rate and flow properties of the mud. Optimum solids control is essential for overall superior mud performance.

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Chemical Tests Chemical Tests are made on the mud and filtrate as an aid in the identification of contaminants and in control of mud properties. These tests include: pH, alkalinity, lime content, chloride (or salt), calcium (or hardness), sulfate carbonate, sulfide starch preservative, chromate, MBT, H2S, resistivity and others.

IV. Factors Affecting Mud Performance and Cost A few basic items greatly influence the performance of the drilling fluid and ultimate cost of the drilling operations.

Pit Facilities Pit Facilities should provide the necessary surface volume and should be arranged so the movement and conditioning of mud can be effectively accomplished.

Mixing Facilities Mixing Facilities should be capable of providing good mixing of mud additives. Adequate pumps, hoppers, and mud guns and mixers should be available.

Mechanical Mud Conditioning Mechanical Mud Conditioning devices, such as fine screen shakers, degassers, desanders, desilters, mud cleaners and centrifuges are effective in reducing mud costs.

Materials Storage Materials Storage under suitable cover eliminates spoilage or breakage caused by exposure to weather.

Mixing Water Mixing Water greatly affects mud cost. The best available water should be chosen for the particular mud to be used. For fresh water muds, soft water having a low concentration of dissolved salts is desirable. Water to replace that lost by surface evaporation and down-hole filtration should be added continuously while circulating. Add water below the shale shaker to avoid washing drill cuttings through the screen.

Hydraulics Hydraulics should be designed in such a way that available horsepower and pump facilities are effectively utilized.

Rig Personnel Rig Personnel should be capable of carrying out mud treatment and should be vigilant to note any change in surface volume or properties of the mud.

Mud Type Mud Type for best results will vary in different areas because of subsurface formations, availability of water or special requirements. The type of drilling fluid chosen should be based on efficiency and cost for the particular area.

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2. Types Of Drilling Fluids I. Water Based Drilling Fluids A. Little or No Chemical Treatment Spud Mud Composition Prepared with available water and the appropriate concentration of bentonite and/or premium clays. Maintenance Generally untreated chemically; however, lime, cement, or caustic soda is added occasionally to increase viscosity and give the mud a fluff to seal possible lost return zones in unconsolidated surface formations and to clean hole of cuttings. Applications and Limits Used for drilling surface hole. Tolerance for drilled solids and contaminants very limited. Natural Mud Composition Utilizes native drilled solids incorporated into mud for viscosity, weight and water loss control. Maintenance Often supplemented with bentonite for additional stability and water loss control. Surfactants can be used to aid in controlling weight and solids build-up. Applications and Limits Generally utilized in top-hole drilling to mud-up or conversion depth. Limited tolerance for solids and contamination.

B. Chemically Treated (No Calcium Compounds) Phosphate Composition Generally a natural mud which has been conditioned with bentonite and treated with phosphates (SAPP or sodium tetraphosphate). Maintenance Treated with phosphate as the primary thinning agent. Small amounts caustic soda-quebracho and/or lignite used for pH control (8.5 to 9.5). Occasionally CMC used for water loss control. Applications and Limits Limited tolerance for contaminants such as salt, cement, or anhydrite. Usually limited to moderately deep drilling and mud weights below 12.0 lb/gal. Treatment with phosphates will cause excessive viscosity if bottom hole temperature exceeds 150°F.

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C. Organically Treated for Deflocculation Quebracho and other Tannins Composition Generally a natural mud which has been conditioned with bentonite, caustic soda and a tannin (quebracho). Maintenance Maintained at Ph 9.0 to 11.0 using caustic soda and quebracho. CMC occasionally used for water loss control. Applications and Limits Tolerance for contamination about the same as phosphate muds but are more temperature stable. Used for moderately deep drilling at low mud weights. Lignite Composition A natural mud conditioned with bentonite, caustic soda and lignite. Maintenance pH maintained at 8.5 to 9.5 with caustic and lignite. CMC may bc used for water loss control. Applications and Limits Tolerance for contamination about the same as phosphate muds but are more temperature stable. Used for moderately deep drilling at low mud weights. Lignosulfonates Composition A low pH fresh or sea water natural mud conditioned with bentonite, caustic soda, lignosulfonate and/or lignite. Maintenance Viscosity and water loss controlled with bentonite, lignosulfonate and/or lignite. Applications and Limits Applicable at all mud weights. Provides a low pH inhibited system. Temperature stable at high temperatures (350°F or above) with good resistance to contaminants.

D. Calcium Treated Lime Mud Composition These muds are prepared from any low or high pH mud by the addition of appropriate amounts of caustic soda, dispersant (quebracho, lignite or lignosulfonate) and lime.

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Maintenance Caustic and dispersant are used to maintain the filtrate alkalinity (Pi) and lime to control the mud alkalinity (Pm) and excess lime. Starch or CMC is added as needed for fluid loss control. Applications and Limits These muds offer resistance to contamination from salt, cement and anhydrite, even at high mud weights. Temperature stable to 250°F if excessive dry solids contamination is avoided. High lime concentration gives good results in drilling gumbo shales. Gyp Muds Composition Gyp muds are prepared from available muds by addition of gypsum, caustic soda and a lignosulfonate. CMC or lignosulfonate are used for filtration control. Maintenance Regular treatment of caustic soda and lignosulfonates are used to control flow properties. Gypsum is added to provide sufficient excess gypsum. Applications and Limits Gyp muds are used for shale drilling, or where gypsum or anhydrite must be drilled. They resist contamination from cement or salt. They are limited by the temperature stability of the CMC to 250°F- 275°F maximum bottom hole temperature.

E. Non Dispersed (Low Solids) Muds Bentonite Extenders/Selective Flocculants Composition Generally fresh water with little or no drill solids and 10-14 lb/bbl bentonite along with a dual action polymer for extending the bentonite and flocculating drilled solids. Sodium polyacrylates are used for filtration and rheological control. Selective flocculants used for flowline flocculation and in place of dual action polymers when drilling formations with high MBT. Maintenance Good solids control is necessary for optimum performance. Viscosity controlled by additions of extending-type polymer and bentonite. Fluid loss and rheology controlled with sodium polyacrylate. Soda ash to maintain calcium concentration below 100 ppm. No thinners used for rheological control. System commonly runs with Yield Point higher than Plastic Viscosity in the very low weight range.

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Selective flocculants used to control drilled solids content. Applications and Limits Used where high cuttings carrying capacity is needed. Good penetration rates due to high shear thinning characteristics. Other benefits are reducing possibility of lost circulation, improved hydraulics and less wear on bits and pumping equipment. Can be weighted with barite but requires additional polymer to coat barite. Excellent thermal stability (400oF)

F. Inhibiting Salt Polymer Systems Composition Inhibiting salts such as KCl, NaCl, or Diammonium phosphate along with complex, high molecular weight polymers. Prehydrated bentonite, a polyanionic cellulose, CMC and XC Polymer for fluid loss and rheological control. Maintenance Viscosity and gel strength controlled with prehydrated bentonite and polymer (including XC Polymer). Bentonite concentrations in the system usually 6-10 #/bbl. Fluid loss control with polyanionic cellulose or CMC. Yield Point commonly runs higher than Plastic Viscosity. Good corrosion control practices are recommended. Use oxygen scavengers and inhibitors to protect tubular goods. Applications and Limits Drilling and protecting water sensitive formations. Good for minimizing formation damage due to filtrate invasion where formation contains hydratable clay solids. Good hole cleaning and shear thinning fluids. Do not tolerate high solids concentrations. Good solids control is necessary. Temperature limitations 200-250°F. Generally limited to mud weights below 15 lb/gal.

G. Salt Water Muds Sea-Water or Brackish Water Muds Composition Prepared with available make-up water, both formation and commercial clay solids, caustic soda, and lignite or a chrome lignosulfonate.

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CMC is usually used for water loss control; however, high concentrations of lignosulfonates can be successfully used for water loss control. Maintenance Viscosity and gel strength are controlled with caustic soda, chrome lignosulfonate and/or lignites. Soda ash frequently used to lower calcium concentration. CMC or lignosulfonates for water loss control. pH controlled between 8.5 to 11.0. Applications and Limits Used primarily because of convenience of make-up water. Degree of inhibitive properties varies with salt and hardness concentrations. Saturated Salt Water Fluids Composition Saturated salt water used as make-up water. Salt water clays (attapulgite, sepiolite) or prehydrated bentonite used to provide viscosity. Starch, CMC and prehydrated bentonite used to control fluid loss. The chloride range for salt muds is from 10,000 ppm to 192,000 ppm (saturated). Maintenance Salt water clays or prehydrated bentonite to increase viscosity. Starch, CMC and prehydrated bentonite to control fluid loss. Occasionally soda ash is used to lower filtrate calcium and adjust pH. Caustic also used for pH control. Solids content should be maintained as low as possible (1-5 % maximum in unweighted systems). Applications and Limits Used primarily to prevent excessive hole enlargement when drilling salt stringers or massive salt beds. Normally used below weights of 14 lb/gal. Potassium Chloride Fluids Composition Potassium chloride (to 36.5% by wt.) added to make-up water. Prehydrated bentonite and/or XC Polymer is used for viscosity and fluid loss control. CMC and other polymers used for additional fluid loss reductions. Maintenance Potassium chloride added as needed to maintain desired concentration.

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Pre-hydrated bentonite used for viscosity and fluid loss control with supplemental additives of CMC or other polymers used for further fluid loss reductions. Density controlled with barite. Applications and Limits Used for drilling shale sections that are fresh water sensitive. Important to keep solids as low as possible. Usually used below weights of 14 lb/gal.

H. Special Modifications and/or XC Polymer Other water base muds are being used, but those discussed are most frequently used. Low solids muds, employing one of a variety of polymers and bentonite, have been successful in many areas. Drilling and surfactants are being applied to stabilize many muds. Low solids and low solids fluids require quality drilled solids removal practices. PHDA Systems Composition High molecular weight polyacrylamilide systems have gained in popularity in recent years for their shale encapsulating and lubricity properties. They can be utilized in fresh water, seawater, and other inhibiting salts. Twenty percent sodium chloride PHPA systems are used frequently in deep water applications for their gas hydrate inhibiting characteristics. Maintenance Viscosity and gel strength controlled with prehydrated bentonite and/or XC Polymers. PHPA is depleted from these systems on drilled cuttings and the borehole. Therefore, maintaining 0.5-1.5 ppb polymer in the active system is necessary.. Fluid loss control with PAC, CMC, lignite, as other polymeric type additives. Due to the high molecular weight additives, these systems tend to run with higher yield points and gel strengths than a typical lignosulfonate fluid. Deflocculation can be obtained by using lignite, lignosulfonates, as low molecular weight synthetic polymers. Applications and Limits Drilling troublesome shales that can cause bit balling, excessive washout or tight hole situations. Drilling in deep water (> 500 ft water depth) and in conjunction with high salt concentrations to prevent gas hydrates formation. MBT values are normally kept lower than 20 lb/bbs bentonite equivalent. Efficient solids control greatly enhances the maintenance of this mud system.

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II. Oil Muds Invert Oil Mud Composition A specially formulated mud having oil as the external phase. Internal phase is normally CaCl2 or NaCl water in order to balance the activity of the mud with the formations drilled. Maintenance Viscosity decreased with oil and increased with water. Oil loss controlled with emulsifiers, stabilizing agents and special formulated compounds usually the o/w ranges between 75/25 and 95/5. Applications and Limits Filtration control can be relaxed to improve penetration rate.

Relaxed Invert Oil Mud Composition A specially formulated mud having oil as the external phase. Internal phase is normally CaCl2 or NaCl water in order to balance the activity of the mud with the formations drilled. Differs from invert oil muds by generally having higher HTHP fluid-loss values and higher oil/water ratios. Formulated by oil, water, emulsifying agents and stability agents. Maintenance Viscosity decreased with oil and increased with water. Oil loss controlled with emulsifiers, stabilizing agents and special formulated compounds. Applications and Limits Used as a drilling fluid where a penetration rate equal to or exceeding a water-based mud is desired. Not effected by contaminants. Stable at high temperature.

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3. Trouble Shooting I. Problems There are four mechanical or physical properties to control in the treatment of drilling mud: 1) density, 2) viscosity, 3) gel strength, 4) filtration.

A. Density (or Weight) The density or weight of a drilling mud is easily controlled by additions of barite to increase weight, or by water or oil to decrease weight. See Table 04-3 and Table 04-4 to determine weight reduction by oil or water.

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Table O4-3 Effect of Oil on Mud Weight

Table O4-4 Oil Dilution of Mud Weight

Use Equation 4-I-E to determine the barite required to raise the density from one mud weight to another and the resulting volume increase.

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Figure O4-1 Solids vs. Mud Weights

B. Viscosity and Gel Strength The control of viscosity and gel strength depends on the solids and the chemical environment. The primary concern is the amount and typo of low-gravity solids contained in the mud. A centrifuge can also be utilized to lower the low gravity solids content of a drilling mud. Water can be expected to decrease the plastic viscosity. The addition of a suitable chemical will decrease the yield point. When solids are in the correct range, most viscosity and gel strength problems can be corrected by proper chemical treatment.

C. Filtration An API filtration test is a relative measure of performance. It does not necessarily follow that down-hole filtration is the same. Only high-pressure, high-temperature tests can give an indication of down-hole filtration. The condition of the mud, and particularly the type of solids present in the mud, greatly influence filtration.

II. Specific Problems A. Contamination Problem - High Drilled Solids Symptoms

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High viscosity and gel strength. Slow drilling rate reduces temperature stability. Mud does not respond to chemical treatment. Solution Reduce drilled solids by water dilution, use of selective flocculants and mechanical separation. Problem - Abrasion Symptoms Premature bit failure and excessive wear of swabs, liners, and valve seats. Solution Use a desander to hold sand content to a minimum. Normally <2% by volume is ideal. Problem - Cement Symptoms High viscosity, high gel strengths, and increase Ph, water loss and filtrate calcium. Solution Pretreat if possible, or for low concentration remove chemically with sodium bicarbonate, add lignosulfonate and/or lignite to reduce viscosity gel strengths. Problem - Gypsum or Anhydrite Symptoms High viscosity, high flat gel strengths, and increase water loss, filtrate calcium and sulfate. Solution Pretreat for small quantities or remove chemically with soda ash. For drilling massive anhydrite change to mud which will tolerate anhydrite. Problem - Salt Rock Symptoms High viscosity and high gel strengths; increase in water loss and salt content. Grainy appearance to mud. Solution Adjust mud properties with organic thinners and water loss control agents, or convert to saturated salt system. Problem - Salt Water Symptoms Same as salt rock except increase in pit volume and a reduction in mud weight. Solution Raise weight to overcome salt water flow. Adjust mud properties with chemicals and water loss control agents. If only stringers are encountered dilute with water.

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B1. Abnormal Low Pressure Problem - Lost Circulation Symptoms Partial to complete loss of returns. Complete losses may best be remedied by the use of soft plugs such as diesel oil-bentonite squeezes, or diesel oil-bentonite-cement squeezes. Solution Pull up in casing and wait for fracture to close. Adjust flow properties to afford minimum flow resistance and equivalent circulating density. Reduce mud weight, if possible. For low weight muds add flake or fibrous materials to avoid increasing mud weight from material additions. In high weight muds, add fine flake or granular lost circulation material for partial loss of returns.

B2. Abnormal High Pressure Problem - Formation Gas or Water Influx Symptoms Increased pit volume possibly preceded or accompanied by gas or salt water cut mud. Mud continues to flow when pumps are shut off. Solution Shut in well. Record drill pipe and casing pressure. Circulate out gas or water influx and separate at surface. Using data obtained calculate necessary mud weight, mix mud and circulate to kill well. Problem - Gas Cutting. Usually from gas bearing shale and or other high pressure, low volume formation. Symptoms Normally shows up as gas-cut mud after trips but dissipates rapidly. If encountered while drilling, gas cutting or kicking will occur in heads. Possible change in chloride content. Solution Raise weight only as necessary. Keep gel strengths as low as possible. Continue to circulate and avoid use of blowout preventers if possible. Use degasser as necessary to clear gas from mud. Problem - Differential Sticking of Drill Pipe. Symptoms Normally occurs when drill pipe is not in motion. Cause in excessive pressure differential between well bore and porous formation. Full or partial circulation while stuck. Probably high fluid loss and high solids content mud. Solution If possible, reduce mud weight. Spot diesel or crude oil treated with surfactants. A non-oil spotting fluid may be preferred in the Gulf of Mexico, due to environmental constraints on oil spots. For prevention, measure fluid loss at static bottom hole temperature and 500 psi differential pressure and use minimum safe mud weight.

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C. Corrosion Problem - General, salt muds. etc. Symptoms Internal and external pitting, more pronounced internally in uncoated pipe. Solution Add corrosion inhibitors. Use oxygen scavengers. Problem - Aerated Mud Symptoms Severe pitting of drill pipe more pronounced internally. Solution Extremely difficult to control. Use corrosion inhibitors and oxygen scavengers. Problem - Sulfide Stress Corrosion Symptoms Severe brittle, flat fractures of susceptible materials, either tool joints and/or pipe. Solution Maintain sufficient weight to avoid influx of formation fluids. Add sulfide scavengers.

D. Formation Problem - Bit Balling Symptoms Little or no progress in footage. Balled up bit and drill string. Swabbing on trips and connections. Bits generally come out in good condition, showing little wear, but heavily packed with cuttings. Solution Use inhibitive mud systems containing lubricants, surfactants, etc. or oil slowly at suction. Utilize available horsepower efficient hydraulics. for results, do not emulsify. Control drill to avoid packing fraction of drilling fluid. Problem - Bentonitic Swelling Symptoms Increase in viscosity, gel strength and solids content. Tight places in hole slow drilling. Mud difficult to control. Solution Keep viscosity and gel strength low to prevent swabbing. Use an emulsion mud to keep bit and drill string clean. Use an inhibitive mud. Raise mud weight to hold bore hole open. Problem - Running, Sloughing, Caving Shales Symptoms

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Hole fill-up after trip. Excessive cuttings over shaker. Tight connections. Solution Raise weight, increase viscosity, decrease fluid loss, maintain mud in laminar flow. Use asphalt or gilsonite products to seal micro fractures. Problem - Plastic Salt Symptoms Tight connections. Even with saturated or oil based mud pipe may become stuck. Solution Increase mud weight. Ream through tight spots. If stuck, spot fresh water, then increase mud weight.

E. Mud Characteristics Problem - Foam at Surface Symptoms Foam on Surface of Mud Pits (not while Converting Mud). Solution Not serious unless mud weight reduced by internal foam. Keep guns submerged. Use a fine spray of water or oil to break foam. Use defoamer if foam persists. In salt or low solids mud, Bentonite will be helpful. Problem - Foam, Internal Symptoms Reduction in mud weight, increased viscosity, fluffy appearance. Pumps run rough or hammer and pump pressure falls off. Solution Eliminate all mechanical causes of foam. Maintain low viscosity and gel strength. Use defoamers if necessary. Problem - High Fluid loss (1) Symptoms Normal viscosity but high fluid loss test. Solution Add fluid loss agent through hopper. Problem - High Fluid Loss (2) Symptoms Filter cake spongy, soft and too thick. There is sufficient fluid loss agent in system. Solution Stabilize system with deflocculant addition.

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Problem - High Viscosity (1) Symptoms High funnel viscosity, plastic viscosity, yield point, gels and solids. Sometimes normal gel and/or solids. Solution Run mechanical solids removal equipment to discard drill solids and fine barite particles. Water dilution also required. Thinner may be used later. Problem - High Viscosity (2) Symptoms High funnel viscosity, yield point and gels and normal plastic viscosity and solids. Solution Add deflocculant. Run mechanical solids removal equipment. Check mud for contaminants. Problem - Increase Of Surface Mud Weight Symptoms High viscosity. Solution Run mechanical solids removal equipment and add water. Problem - Unstable Mud Symptoms Barite settles out. Solution Add viscosifier to increase viscosity.

F. Slow Drilling Rate Problem - Bit Balling Symptoms Little or no progress in footage. Balled up bit and drill string. Swabbing on trips and connections. Bits generally come out in good condition, showing little wear, but heavily packed with cuttings. Solution Use inhibitive mud systems containing lubricants, surfactants, etc. or oil slowly at suction. Utilize available horsepower efficient hydraulics. for results, do not emulsify. Control drill to avoid packing fraction of drilling fluid. Problem - High Drilled Solids Symptoms High viscosity and gel strength. Slow drilling rate reduces temperature stability. Mud does not respond to chemical treatment.

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Solution Reduce drilled solids by water dilution, use of selective flocculants and mechanical separation.

G. High Temperature Problem - High Temperature Gelation. Symptoms Difficult to break circulation. Inability to run tools to bottom. High viscosity and gel strengths of mud off bottom. Decrease in alkalinity, increased water loss and increase in soluble calcium. Solution Reduce solids concentration by water dilution. Increase thinner concentration. Spot high temperature treated mud on bottom. H. Bearing Failure Problem - Locked Cones Symptoms Cones locked or bearings loose with teeth structure still on cones. Solution Reduce drilled solids by water dilution, mechanical separation and use selective flocculants. Use sealed bearing bits.

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4. Calculations I. Calculations A. Volume of Mud in System. One of the first concerns of the driller is the volume of mud in the system. This includes the mud in the pit and the mud in the hole. It is also useful to know how much reserve mud is available in storage tanks or pits. Bbl. of mud in system = bbl. of mud in pit + bbl. of mud in hole Volume of mud in pit, bbls = {length(ft) x width(ft) x depth (ft)}/(5.6 cu ft/bbl)

B. Capacity of Hole. The most frequently used formula for estimating the volume of mud in the hole is: Volume in bbls per 1,000 ft of hole = (diameter in inches)2

C. Time for One Complete Circulation - Mud Cycling Time. In mud conditioning, it is frequently important to know the time required for the mud to make a cycle from the pump suction to the bottom of the hole and back to the pump suction. When adding weight material or chemicals it is almost always desirable to add these materials at such rate that the mud will make at least one complete cycle during the treatment: 1) the volume of mud in the hole and active surface volume, and 2) the output rate of the slush pump. C1. Cycle Time: Pump output, bbl/min = 0.024 x Pump output, gal/min Pump output, bbl/min = bbl/stroke x strokes/min Time of complete circulation = (bbls mud in hole + active surface volume) / (bbl/min pump output)

D. Hydrostatic Pressure Equivalents. Hydrostatic pressure, psi = 0.052 x mud weight, lb/gal x depth, ft Hydrostatic pressure, psi = 0.00695 x mud weight, lb/cu ft x depth, ft Average formation fluid pressure, psi = 0.433 x depth, ft

(0.433 = gradient of fresh water, psi/ft)

Average formation fluid pressure, psi = 0.465 x depth, ft

(0.465 = gradient of saltwater)

Mud weight, lb/cu ft = 7.4805 x Mud weight, lb/gal Mud weight, lb/gal = 0.2337 x Mud weight, lb/cu ft SG of Mud = (Mud weight, lb/gal)/8.33

(fresh water = SG of 1.00 at 4°C)

E. Quantities of Mud Materials. 1. Increase in Weight. Barite: SG = 4.25 or 35.5 lb/gal or 1,490 lb/bbl

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Approximate in the weight range 9.0-12.0 lb/gal 60 sacks barite increases weight of 100 bbl mud by 1 lb per gal. For weights above 12.0 lb/gal, divide the desired or final weight by 0.2 to find number of sacks barite to raise weight of 100 bbl of mud by 1 lb/gal. Sacks barite needed to increase weight of 100 bbl mud: X = 1,490 (W2 - W1)/(35.5 - W2) W1 = present mud weight, lb/gal W2 = desired mud weight, lb/gal 2. Increase in Volume from Addition of Weight Material. Approximate: 15 sacks barite equals 1 bbl. of volume; 100 sacks barite equals 6.64 bbl of volume. Barrels increase in volume in weighing up 100 bbl. of mud: V = 100 (W2 - W1)/(35.5 - W2) Where V = increase in volume, bbl. W1 = initial mud weight, lb/gal W2 = final mud weight, lb/gal 3. To Determine Quantity of Water Necessary to Obtain a Given Weight Reduction (neglecting settling effect). X = (W1 - W2) x V1/ (W2 - 8.33) Where X = bbls of water to be added W1 = original mud weight, lb/gal W2 = desired mud weight, lb/gal V1 = original mud volume, bbls

F. Annular or Rising Velocity of Mud. It will be recalled that the upward velocity of the mud in the annulus between the drill pipe and wall of the hole is an important consideration with that function of drilling fluid of removing cuttings. The usual expression of this velocity is in feet per minute. Annular Volume, bbl/ft = capacity open hole, bbl/ft minus (capacity of drill pipe and displacement of drill pipe, bbl/ ft) Annular Velocity, ft/min = (pump output, bbl/min) / (Annular Volume, bbl/ft) Annular Velocity, ft/min = 0.024 x gal/min / (Annular Volume, bbl/ft)

II. Additional Aids Additional aids for calculating various factors in mud work are:

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Table O4-1

Gravity, Weight, Pressure Relationships

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Table O4-2

Table O4-3

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Densities of Salt Brines

Effect of Oil on Mud Weight

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Table - O4-5 - Air/Gas Volumes for Drilling

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Figure O4-1 :Solids versus Mud Weight

Figure O4-2 Nomogram for Estimating Equivalent Circulating Density, ECD

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Figure O4-2

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EXAMPLE Given: Hole size = 9-1/2 inches Drill Pipe Size = 4-1.2 inches Mud Weight, MW = 13 ppg Yield Point, YP = 14 lb/100 sq ft Solution: Hydraulic Diameter, HD = 9-1/2 - 4-1/2 = 5 inches Enter YP at (A) Enter HD at (B) Connect (A) and (B) Read DMW at (C) = 0.24 ECD = MW + DMW = 13.0 + 0.24 = 13.24 ppg Compliments of IMCO FIGURE 04-3. Chart to Determine Bottom-Hole Pressure Due To the Height and Density of the Mud Column

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Figure O4-3: BHP Chart from TVD & Mud Weight

Dotted line on chart follows the example of the use of this chart as given below. EXAMPLE To determine the fluid pressure at the bottom of a well 4,000 (or 400) feet deep which is filled with a mud weighing 15 pounds per gallon, use a straightedge to connect 4,000 (Depth of Hole in Feet) on the left-hand column with 15 (Density of Mud Pounds per Gallon) on the right-hand column. The line so formed will intersect the center axis at about 3,150, indicating that the pressure at the bottom of the well is 3,150 (or 315) pounds per square inch. Copyright 1954 by Baroid Division, National Lead Company, Houston, Texas

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5. Additives For Drilling Fluids I. Definitions for Drilling Fluid Classification The importance of terminology properly defining a drilling fluid is becoming of greater significance. This includes the drilling contractor, the operator, the mud service engineer, and even the well completion service specialists who must work with the well after the hole is down. As the number of products added to a given drilling fluid formulation increases, so does the importance of proper mud classification, proper metering and measurement of fluids and special additives.

II. Drilling Fluid Systems Fresh Water, Low pH Fresh Water, Low pH - Systems with a liquid phase of water containing only small concentrations of salt, and with a pH ranging from 7.0 to 9.5. This would include spud muds, bentonite treated muds, phosphate muds, and polymer nondispersed muds.

Brackish Water, Low Ph Brackish Water, Low Ph - Includes 7.0 to 9.5 Ph sea and brackish, or hard water muds. Source water here may be from open sea or bays (5000 - 15,000 mg/l chlorides). Saturated Salt Water, Low Ph Saturated Salt Water, Low Ph - Liquid phase of these muds is saturated with sodium chloride, although other salts may be present. These may be prepared from fresh water of brine water (192,000 mg/l chlorides).

Gyp Treated, Low Ph Gyp Treated, Low Ph - These gypsum-treated or gyp-base muds are formulated by conditioning the mud with plaster (commercial calcium sulfate), lignosulfonates, and CMC's.

Lime Treated, High Ph Gyp Treated, Low Ph - Consist of adding caustic soda, lime, and clay, and an organic thinner. These normally have a Ph greater than 11.0 and contain an excess of lime equal to or greater than Pf.

Fresh Water High Ph Fresh Water High Ph - Muds having a liquid phase of fresh water but with which have been treated with products which bring the Ph level above 9.0. These would include most alkaline tannate treated muds.

Low Solids Low Solids - A drilling fluid where solids content is less than 5 percent by volume or a weight less than 9.0 per gal. may have either oil or water base.

Emulsions Emulsions - Are formed by the physical mixture of two immiscible liquids such as oil and water. One liquid is broken up into droplets in the other liquid by mechanical action. The droplets are so small that they are not able to separate from the suspending liquid even though there might be a great difference in the specific gravity of one with respect to the other. The suspending liquid is called the continuous phase and the droplets are called the dispersed phase. Emulsions are often used in the liquid phase of drilling muds. Most common are:

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Oil-In-Water. Oil-In-Water. Droplets of oil are dispersed in water in these emulsions. Water is a continuous phase and is often the only liquid recovered in a falter loss test.

Water-In-Oil Water-In-Oil (invert emulsions). The oil is the continuous phase having droplets of water as the dispersed phase. These emulsions contain up to 50% of the total volume as water in the dispersed phase.

Oil Muds Oil Muds - Are not emulsions at the start of their use in drilling. They are usually a mixture of diesel fuel and asphalt. Viscosity is controlled by the additions of diesel fuel to thin and asphalt compounds or organo clays to thicken. Weight is increased by the addition of barites. As a rule, oil muds will form water-in-oil emulsions with formation water or from other sources of water contamination.

Air, Gas, Mist Air, Gas, Mist - These include aerated and gaseated mud systems in this classification.

Foam Foam - Mixture of air, water and detergent foaming agent.

III. Fluid Additive Functions Alkalinity, pH Control Additives Alkalinity, pH Control Additives - Products designed to control the degree of acidity or alkalinity of a drilling fluid. These include lime, caustic soda, bicarbonate of soda or soda ash. Bactericides Bactericides - Function to control bacterium count. Para-formaldehyde, caustic soda, lime, and starch preservatives are commonly used preservatives. Defoamers Defoamers - Products designed to control foaming action, particularly that occurring in a brackish water and saturated salt water muds. Emulsifiers Emulsifiers - For the purpose of creating a heterogeneous mixture of two liquids. These include modified lignosulfonates, certain surface active agents, anionic and nonionic (negatively charged and non-charge) products. Lubricants Lubricants are designed to reduce torque to increase horsepower at the bit by reducing the coefficient of friction. Certain oils, graphite powder, glycols and soaps are used for this purpose. Flocculants Flocculants - These are used to reduce the solids content of drilling fluids by coagulating the drilled solids and making them easier to remove. With proper use clear water can be obtained. Filtrate Reducers

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Filtrate Reducers - Filtrate, or fluid loss reducers, such as bentonite clays, CMC (sodium carboxymethyl cellulose), sodium polyacrylated, and pregelatinized starch serve to cut filter loss, a measure of a drilling fluid's liquid phase's tendency to pass into the formation. Foaming Agents Foaming Agents - These are most often chemicals which also act as surfactants (surface active agents) to foam in the presence of water. These foamers permit air or gas drilling through formation making water and formations with excessive lost circulations problems, or low pressure depleted zones. Lost Circulation Materials Lost Circulation Materials - Nearly every possible product has been used to stop or slow the loss of circulating fluids into the formation. This must be differentiated from normal loss of filtration liquid and the loss of drilling mud solids to the filter cake which is a continuous process in open hole. Shale Control Inhibitors Shale Control Inhibitors - Gypsum, potassium compounds, sodium silicate, chrome lignosulfontates, as well as lime and various salts are products used to control caving by preventing swelling and disintegration of shales. Also, high molecular polyacrylamides are used as shale encapsulators. Surface Active Agents Surface Active Agents - Surfactants, as they are called, reduce the interfacial tension between contracting surfaces (water/oil, water/silt, water/air, etc.). Also used are gilsonite and other asphaltic compounds. These may sometimes be emulsifiers, de-emulsifiers, flocculants, deflocculants, depending upon the surfaces involved. Thinners, Deflocculants Thinners, Deflocculants - These chemicals modify the relationships between the viscosity and percentage of solids in a drilling mud, and may further be used to vary the gel strength, increase a mud's "pumpability," etc., Lignosulfonates, Tannins (quebracho), various polyphosphates and lignitic materials are chosen as thinners or as dispersants, since most of these chemicals also remove (by precipitation or sequestering, and deflocculation reactions) solids. Principle purpose of a thinner is to function as a deflocculant to combat random association of clay particles. Viscosifiers Viscosifiers - Bentonite, Xantham Gum, CMC, attapulgite clays, and sub-bentonites, are employed as viscosity builders for drilling fluids to assure a high viscosity solids relationship. Calcium Removers Calcium Removers - Caustic soda, soda ash, bicarbonate of soda, and certain polyphosphates make up the majority of chemicals designed to prevent and overcome the contaminating effects of anhydrite and gypsum, both forms of calcium sulphates, which can destroy the effectiveness of nearly any chemically-treated mud not employing calcium removers with exception of modified lignosulfonate. Weighing Materials Weighing Materials - Barite, lead compounds, iron oxides and similar products possessing extraordinarily high specific gravity are used to control formation pressures, check caving, facilitate pulling dry drill pipe on round trips, and as an aid in combating some types of circulation loss. Corrosion Inhibitors

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Corrosion Inhibitors - Hydrated lime and amine salts are often added in mud and air/gas systems to check corrosion. A good mud, containing an adequate percentage of colloids, certain emulsion muds, and oil muds, exhibit in themselves excellent corrosion inhibiting properties. Oxygen Scavenger Oxygen Scavenger - Commonly a sodium sulfite, ammonium bisulfite, frequently catalyzed with heavy metal such as nickel or cobalt. Oxygen scavengers react with dissolved oxygen in the water phase and remove it through this process. Oxygen scavenger should be injected into the line just before the pump, not into the suction pit. Hydrogen Sulfide Scavenger Hydrogen Sulfide Scavenger - Usually a heavy metal (iron, zinc) chemical which, under proper conditions can chemically react with H2S or neutralized sulfide species. Mud should have Ph over 10 to protect steel components, then add the scavenger to react with and remove sulfide in an inert form. NOTE: The reader is referred to the June edition of World Oil Magazine for the WO Drilling Fluid Products Guide. This annual publication provides product name, description, systems recommendations and product function.

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Chapter P: Hole Deviation and Horizontal Drilling

Chapter P Hole Deviation and Horizontal Drilling

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Table of Contents - Chapter P Hole Deviation and Horizontal Drilling References ......................................................................................................................................... P-3 P-1 Straight Hole Drilling .......................................................................................................................... P-4 I. Introduction ..................................................................................................................................... P-4 II. Problems Associated With Dog-legs And Key Seats ..................................................................... P-10 III. Control Of Hole Angle? ............................................................................................................. P-13 IV. Factors To Consider When Designing Packed Hole Assembly ..................................................... P-34 V. Packed Hole Assemblies .............................................................................................................. P-35 VI. Stabilizing Tools .......................................................................................................................... P-38 VII. Conclusion ................................................................................................................................ P-51 P-2 Controlled Directional Drilling ........................................................................................................... P-52 I. Introduction ................................................................................................................................... P-52 II. Basic Deflection Patterns .............................................................................................................. P-54 III. Planning And Supervising The Directional Well ............................................................................ P-55 IV. Sub Surface Surveying ................................................................................................................ P-59 V. Deflection Tools ........................................................................................................................... P-66 VI. Orientation Of Deflection Tools ................................................................................................... P-73 VII. Principles Of Directional Drilling Stabilization .............................................................................. P-75 VIII. Dog-leg Severities .................................................................................................................... P-78 P-3 Horizontal Drilling ............................................................................................................................ P-84 A. Planning ....................................................................................................................................... P-84 B. Proper Drill Stem Design .............................................................................................................. P-92 C. Factors Determining Optimum Well Profiles .................................................................................. P-97 D. Four Factors That Affect Fatigue Damage .................................................................................. P-101 E. Directional Control In The Horizontal Section .............................................................................. P-105

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CHAPTER P Hole Deviation and Horizontal Drilling The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study.

References P-1 Straight Hole Drilling Information in this section is based on various API papers authored by H. M. Rollins and Arthur Lubinski. Also the tables included in this publication were prepared by H. M. Rollins with the assistance of Arthur Lubinski.

P-3 Horizontal Drilling Proper Drill Stem Design Dawson, R. and Paslay, P.R., "Drill Pipe Buckling in Inclined Holes", SPE 11167 presented at 1982 Fall Technical Conference and Exhibition, New Orleans, September 26-29. Four Factors Affect Fatigue Damage 1) "Recommended Practice for drill Stem Design and Operating Limits (RP7G)", American Petroleum Institute, April 1, 1989. 2) Arthur Lubinski, "Maximum Permissible Dog-Legs in Rotary Boreholes", Transactions of AIME, 222 (1961), 251-270. 3) H.M. Rollings, "Drill Pipe Fatigue Failure", Oil & Gas Journal, April 18, 1986.

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P-1 Straight Hole Drilling I. Introduction A better title would probably be "Controlled Deviation Drilling" because it has been learned through the years that a perfectly straight hole is virtually impossible to drill. No one knows the exact cause of holes going crooked but some logical theories have been presented. It has been confirmed that the drilling bit will try to climb uphill or updip in laminar formations with dips up to 40 degrees. See Figure P1-1. Figure P1-1 Effect of Formation Dip on Hole Deviation

Another factor to consider is the bending characteristics of the drill stem. With no weight on the bit, the only force acting on the bit is the result of the weight of the portion of the string between the bit and the tangency point. This force tends to bring the hole toward vertical. When weight is applied, there is another force on the bit which tends to direct the hole away from vertical. the resultant of these two forces may be in such a direction as to increase angle, to decrease angle, or to maintain constant angle. This was stated by Arthur Lubinski (Research Engineer for AMOCO) at the spring meeting of the Mid-Continent District, Division of Production, Tulsa, March 1953, and was based upon the assumption that the drill stem lies on the low side of an inclined hole. See Figure P1-2.

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Figure P1-2 Effect of Drill String Bending on Hole Deviation

In general, soft formations make the problem of drilling a straight or nearly vertical hole much easier than in the very hard formations. In particular the effect of the drill stem bending and the dips may be much less when drilling soft formations while the hard formations which are at high dip angles require high bit weights and all of these factors work against drilling a straight or vertical hole. In a straight hole drilling contract many of the possible troubles can be prevented by obtaining satisfactory contract terms on deviation and dog-legs. It is extremely important that when negotiating the contract itself that the operator be aware of the advantages in giving the broadest possible limits for deviation. By relaxing deviation clauses to reasonable limits, it is possible to drill a so-called straight hole at high rates of penetration and avoid the costly operations of plugging back and straightening the hole. In addition to the operator's deviation limits, it may be possible to work with him to select a location so that the well may be allowed to drift into the target area. In other words, it is desired to reach a certain point on the structure and it is known that the well will drift in a certain direction up-structure; is it desirable then to move the location downdip so that when drilling normally the bottom of the well From the contractor's standpoint, some very valuable time can be spent in planning the drill stem and the bit program along with the hydraulics. Drift planning will include obtaining the largest drill collars that may be safety run in a given hole size and to plan for optimum bit weights to get the best rate of penetration. If it is anticipated that there will be a problem maintaining the deviation with the contract limits, there are somewhat more extreme methods possible which will assure a more nearly vertical hole and still allow relatively high rates of penetration.

A. Minimum Effective Hole Calculations Arthur Lubinski was one of the first to apply mathematics to drilling. He stated in the early 1950's that the size of the bottom drill collars would be the limiting factor for lateral movement of the bit and the minimum effective hole diameter (MEHD) could be calculated by the following equation:

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MEHD = (Bit Size + Drill Collar OD)/2 Robert S. Hock (an engineer with Phillips Petroleum Company) theorized that, while drilling with an unstabilized bit, an abrupt change can occur if hard ledges are encountered. See Figure P1-3. Figure P1-3 Abrupt Dogleg/Undersized Hole from Hard Ledge

He pointed out that a dog-leg of this nature would cause an undersized hole, making it difficult or maybe impossible to run easing. Hock rewrote Lubinski's equation to solve for the minimum permissible bottom hole drill collar outside diameter (MPBHDCOD) as follows: MPBHDCOD = 2(Casing Coupling OD) - bit OD For Example: Data:12-1/4" bit; 9-5/8" casing (coupling OD = 10.625) Minimum Drill Collar Size = 2(10.625) - 12.25 Minimum Drill Collar Size = 9" OD (See Table P1-3 for additional calculations)

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Table P1-3 Min. DC while Drilling Slick or Pendulum for Hole/Csg Sizes

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Note: See other tables pertaining to drill collar sizes and rig equipment required to handle drill collars.

B. Why Restrict Total Hole Angle? Total hole angle should be restricted: 1) in order to stay on a particular lease and not drift over into adjacent property, 2) to insure drilling into a specific pay zone like a stratigraphic trap, a lensing sand, a fault block, etc., or 3) to drill a near-vertical hole to meet legal requirements from regulatory agencies, field rules, etc. The restriction of total hole angle may solve some problems but it is not a cure-all. 4) Hole can be effectively "lost" by holes drilled off vertical. See Table P1-1

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Table P1-1 Drift And Loss Of Depth In Crooked Holes Or Holes Drilled Off The Vertical

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As can also be seen in Figure P1-4, the typical 5-degree limit does not assure a well bore free of troublesome doglegs. Figure P1-4 Six Degree Dog-leg

C. Why Restrict Rate of Hole Angle Change? Lubinski pointed out in his work (in the early 1960's), that the rate of hole angle change should be the main concern, not necessarily the maximum hole angle; and he expressed this rate of hole angle change in degrees per 100 feet. In 1961 an API study group published a tabular method of determining maximum permissible dog-legs that would be acceptable in rotary drilling and completions. Therefore, the main objective is to drill a "useful" hole with a full-gauge, smooth bore, free from dog-legs, key seats, offsets, spirals, and ledges. A key seat is formed after part of the drill pipe string has passed through the dog-leg. Since the drill pipe is in tension, it is trying to straighten itself while going around the dog-leg. This creates a lateral force that causes the drill pipe to cut into the center of the bow as it is rotated. See Figure P1-5. This force is proportional to the amount of weight hanging below the dog-leg. A key seat will be formed only if the formation is soft enough and the lateral force great enough to allow penetration of the drill pipe. When severe dog-legs and key seats are formed many problems can develop.

II. Problems Associated With Dog-legs And Key Seats A. Drill Pipe Fatigue Lubinski presented guidelines (1961) for the rate of change of hole angles. He said that if a program is designed in such a way that drill pipe damage is avoided while drilling the hole, then the hole will be acceptable for conventional designs for casing, tubing, and sucker rod strings as far as dog-leg severity is concerned. A classical example of the severe dog-leg condition which produces fatigue failures in drill pipe can be seen in Figure P1-5.

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Figure P1-5 Problems from Hole Deviation

The stress at point B is greater than the stress at Point A; but as the pipe is rotated, point A moves from the inside of the bend to the outside and back to the inside again so that every fiber on the pipe goes from minimum tension to maximum tension and back to minimum tension again. Cyclic stress reversals of this nature cause fatigue failures in drill pipe, usually within the first two feet of the body adjacent to the tool joint because of the abrupt change of tension. Lubinski suggested that to avoid rapid fatigue failure of pipe, the rate of change of the hole angle must be controlled. Suggested limits can be seen in Figure P1-6. Figure P1-6 Fatigue Curve Maximum Safe Dog-Leg Limits - Grade E Drill Pipe

This graph is a plot of the tension in the pipe versus change in hole angle in degrees per 100 feet. This curve is designed for 4-1/2'' 16.60 lb/ft Grade "E" drill pipe, and represents stress endurance limits of the drill pipe under various tensile loads and in various rates of change in hole angle. If conditions fall to the left of this curve, fatigue damage to the drill pipe will be avoided, but to the right, fatigue damage will build up rapidly and failure of the pipe is likely. It can be seen from this plot that if a dog-leg is high in the hole with high tension in the pipe, only a small change in angle can be tolerated. Note: See Figure P1-6a for maximum safe dog-leg limits in Grade E drill pipe.

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Figure P1-6a Maximum Safe Dog-Leg Limits Grade E Drill Pipe

EXAMPLE - refer to Fig. P1-6a, above. (DOG-LEG AT 3000 ft) (A) Proposed Mud Weight At TD 12,000 Ft = 16.0 ppg (B) 4-1/2" 16.60 ppf Drill Pipe (17.8 ppf Actual Weight) DC Length: 1000 Ft; DC Weight: 60,000 Lbs In 16.0 Lb/Gal Mud (C) Drill Pipe Below Dog-Leg = (Proposed TD) - (Depth Of Dog-Leg) - (DC Length) = 12,000 ft - 3000 ft - 1000 ft = 8000 ft (D) Maximum Safe Dog-Leg Limit = 4.7° If the stress endurance limit of the drill pipe is exceeded, because of rotation through a dog-leg, an expensive fishing job or a junked hole could develop.

B. Stuck Pipe Sticking can occur by sloughing or heaving of the hole and by pulling the large OD drill collars into a key seat while pulling the drill stem out of the hole.

C. Logging Logging tools and wire lines can become stuck in key seats. The wall of the hole can also be damaged, causing hole problems.

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D. Running Casing Running casing through a dog-leg can be a very serious problem. If the casing becomes stuck in the dog-leg, it will not extend through the productive zone. This would make it necessary to drill out the shoe and set a smaller size casing through the productive interval. Even if running the casing to bottom through the dog-leg is successful, the casing could be severely damaged, thereby preventing the running of production equipment.

E. Cementing The dog-leg will force the casing over tightly against the wall of the hole, preventing a good cement bond because no cement can circulate between the wall of the hole and the easing at this point.

F. Casing Wear While Drilling The lateral force of the drill pipe rotating against the casing in the dog-leg or dragging through it while tripping, can cause a hole to wear through the easing. This could cause drilling problems and/or possible serious blowout.

G. Production Problems It is better to have a smooth string of casing to produce through. Rod wear and tubing leaks associated with doglegs can cause expensive repair jobs. It may be difficult to run packers and tools in and out of the well without getting stuck because of distorted or collapsed casing.

III. Control Of Hole Angle? Now that we have some ideas as to the possible causes of bit deviation and the problems associated with crooked holes, look at two possible solutions using the pendulum and the packed hole concepts.

A. Pendulum Theory In the early 1950's, Woods and Lubinski collaborated in mathematical examination of the forces on a rock bit when drilling in an inclined hole. In order to make their calculations, they made three basic assumptions: 1. The bit is like a ball-and-socket joint, free to turn but laterally restrained. 2. The drill collars lie on the low side of the hole and will remain stable on the low side of the hole. 3. The bit will drill in the direction in which it is pushed, not necessarily in the direction in which it is aimed. Consequently, the forces which act upon the bit can be resolved into: 1. The axial load supplied by the weight of the drill collars. 2. the lateral force -- the weight of the drill collar between the bit and the first point of contact with the wall of the hole by the drill collar ("Pendulum Force"). "Pendulum Force" is the tendency of the unsupported length of drill collar to swing over against the low side of the hole because of gravity. It is the only force that tends to bring the hole back towards vertical. See Figure P1-7.

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Figure P1-7 Forces on Bit

3. the reaction of the formation to these loads, which may be resolved into two forces, one parallel to the axis of the hole and one perpendicular to the axis of the hole. This work made it possible to utilize gravity as a means of controlling change in hole angle. Special tables were prepared to show the necessary weight for the bit to maintain a certain hole angle. These tables also show the proper placement of a stabilizer to give the maximum pendulum force and the maximum weight for the bit. The effects of using larger drill collars can also be determined. Table P1-2 consists of several pages of the results of such calculations with instructions on how to use them.

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TABLE P1-2a -- 6-1/8" Hole Size -- 15 Degree Formation Dip Drill Collar Sizes

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TABLE P1-2a - Continued

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TABLE P1-2a - Continued

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TABLE P1-2b -- 6-3/4'' Hole size -- 15 Degree Formation Dip Drill Collar Sizes

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TABLE P1-2b - Continued

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TABLE P1-2c -- 7-7/8" Hole Size -- 15 Degree Formation Dip Drill Collar Sizes

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TABLE P1-2c - Continued

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TABLE P1-2d -- 8-3/4" Hole size -- 15 Degree Formation Dip Drill Collar Sizes

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TABLE P1-2d - Continued

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TABLE P1-2e -- 9-7/8" Hole Size -- 15 Degree Formation Dip Drill Collar Sizes

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TABLE P1-2f -- 10-5/8" Hole Size -- 15 Degree Formation Dip Drill Collar Sizes

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TABLE P1-2g -- 12-1/4'' Hole Size -- 15 Degree Formation Dip Drill Collar Sizes

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TABLE P1-2h -- 17-1/2'' Hole Size -- 15 Degree Formation Dip Drill Collar Sizes

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Note: this table is for 15 degree formation dips only. If other dips are encountered, appropriate tables or graphs are available from directional drilling service companies.

B. The Use of Hole Deviation - Weight Tables When it is planned to move a rig in on a location, the tool pusher and/or the drilling superintendent should check on the following: 1. Learn from the operating company the expected dip of formations to be drilled and possibility of faulted zones. 2. Obtain bit records of other wells drilled in the area and determine from them expected crooked hole zones. Using these charts and bit record information about drill collar assemblies and weights, classify the formations, Class "A" to Class "U". 3. Predict the probable weights you can carry through these zones with your drill collar assembly while maintaining an acceptable hole angle. 4. Compare and evaluate the probable weights you could use with larger collars or stabilizers or both. 5. In using these charts, the diameter of the bottom 60 feet or 90 feet of drill collars should be considered; smaller collars above these will not affect the use of this information. 6. CAUTION -- For predictions in which the hole angle is assumed to change, it is necessary that the formation dip be known, and the correct dip tables used. For predictions in which there is no change in the hole angle, any of the tables may be used; however, all values in one problem must be taken from the same set of tables -- all from the 15-degree dip tables or from the 30-degree dip tables.

C. The Use of Hole Inclination -- Weight Tables (For Selection of Drill Collar Size and for Placement of Stabilizers) With the development and acceptance of the "packed-hole" technique in controlling the rate of curvature while drilling; the "Stabilizer Pendulum" technique is not being used to the extent it was six or seven years ago. In the interest of space in the manual, it was decided that for the purpose of estimating hole inclination control with respect to drill collar size and weight on the bit, only the 15 degree dip tables would be published in this edition. A complete set of these tables are available from your drill collar supplier and tables have been prepared in detail which will permit one to predict the effect on hole inclination of changes in weight, drill collar size or the use of stabilizers. The complete tables contain data for formation dips of 4 degrees, 7 degrees, 10 degrees, 15 degrees, 20 degrees, 30 degrees and 45 degrees. At each dip condition, tables are included for hole inclinations of 2, 3, 4, and 6 degrees, and, where applicable for 10, 12, 15, 20, 25, 30 and 40 degrees. These values have been prepared for all practical drill collar sizes for the following hole sizes: 6-1/8, 6-3/4, 7-7/8, 8-3/4, 9, 9-7/8, 10-5/8, and 12-1/4 inches. Variations in bit weights are shown for very small values and increased to the maximum values which are foreseen to be used for several years. It must be made clear that the use of this information must be based on an equilibrium condition; that is, the hole angle must remain constant for an interval of 60 to 100 feet, with a constant weight on the bit. The use of a reamer or stabilizer at the bit makes the data outlined in the table invalid. EXAMPLE

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The following is an example illustrating the use of these tables: You are drilling an 8-3/4" hole with 6" drill collars in a formation known to have a dip angle of approximately 15 degrees. In order to MAINTAIN a hole angle of approximately 4 degrees, you have been drilling at 13,000 lbs on the bit in a uniform formation for about 100 feet. For this situation, you have found the EQUILIBRIUM CONDITION -- nothing has changed for the last 100 feet. From the tables, we can now predict how much weight could be run with other sizes of drill collars or with stabilizers. Find our present condition -- 8-3/4" hole size, 15 degree dip, 6" drill collars, 4 degree hole angle, 13,000 lbs on the bit -- in Table 2, Sec. P1. It is located on line 4 degrees, "0". Any other point on any line "0" in these 15 degree dip tables is comparable to our present condition. For example, on the same 8-3/4" chart -- using 7-1/2" drill collars, we learn that we could carry 22,630 lbs on the bit and still maintain 4 degrees; using 7-1/2". collars with a stabilizer at 66.73 ft above the bit, we could carry 29,100 lbs If we wished to reduce our hole angle to 3 degrees, using our 6 " collars, we must reduce our weight to 10,386 lbs with a stabilizer set at 59-66 feet above the bit. Direct comparisons can also be made with other hole sizes. Someone drilling through this section using a 6-3/4" hole size could expect to maintain 3 degrees with 5" collars at 12,159 lbs on the bit. You will note that in the first column of each table, the hole angle and the class is shown. The hole angle designates the degrees of deviation; the hole class indicates how severe the crooked hole condition is. A Class "A" condition is a very severe crooked hole condition and very light weights must be used to maintain a given hole angle; a Class "U" condition is a mild crooked hole condition and heavy weights may be carried. Using our original set of conditions -- 15-degree dip, 6" drill collars, 8-3/4" hole, 4 degrees: * a Class "A" formation would permit the use of only about 400 lbs on the bit * a Class "G" only 2,303 lbs; a Class "U" formation would permit the use of 39,421 lbs; * our Class "O" formation, moderately crooked, permits using 13,237 lbs. Information in this section is based on various API papers authored by H. M. Rollins and Arthur Lubinski. Also the tables included in this publication were prepared by H. M. Rollins with the assistance of Arthur Lubinski.

D. Packed Hole Theory Most people today use a packed hole assembly to overcome crooked hole problems and the pendulum is used only as a corrective measure to reduce angle when the maximum permissible deviation has been reached. The packed hole assembly is sometimes referred to as the "gun barrel" approach because a series of stabilizers is used in the hole already drilled to guide the bit straight ahead. The object should be to select a bottomhole assembly to be run above the bit with the necessary stiffness and wall contact tools to force the bit to drill in the general direction of the hole already drilled. If the proper selection of drill collars and bottomhole tools is made, only gradual changes in hole angle will develop. This should create a useful hole with a full-gauge, smooth bore free from dog-legs, key seats, offsets, spirals and ledges, thereby making it possible to complete and produce the well. See Figure P1-8.

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Figure P1-8 Gradual Increase in Deviation

IV. Factors To Consider When Designing Packed Hole Assembly A. Length of Tool Assembly It is important that wall contact assemblies provide sufficient length of contact to assure alignment with the hole already drilled. Experience confirms that a single stabilizer just above the bit generally acts as a fulcrum or pivot point. This will build angle because the lateral force of the unstabilized collars above will cause the bit to push to one side as weight is applied. Another stabilizing point, for example, at 30 feet above the bit will nullify stone of the fulcrum effect. With these two points, this assembly will stabilize the bit and remove some of the hole anglebuilding tendency, bit it would not be considered a good packed hole assembly. As shown in Figure P1-9, two points will contact and follow a curved line, but add one more point and there is no way you can get three points to contact and follow the curve. Therefore, three or more stabilizing points are needed to form a packed hole assembly. See Figure P1-9 Three or more Stabilizing Points for a Packed Hole Assembly

B. Stiffness Stiffness is probably the most misunderstood of all the points to be considered about drill collars. Few people realize the importance of diameter and that it is proportional to stiffness. If you double the diameter of a bar its stiffness is increased 16 times. EXAMPLE: If an 8 inch diameter bar is deflected 1 inch under a certain load, a 4 inch diameter bar will deflect 16 inches under the same load. Here are some numbers for moments of inertia (I), proportional to stiffness and they represent the stiffness of popular drill collars of various diameters.

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Table - P1-22 Moments Of Inertia (I)

OD 5" 6-1/4" 6-1/2 6-3/4" 7" 8" 9" 10" 11"

I.D. 2-1/4" 2-1/4" 2 -1/4" 2-1/4" 2-13/16" 2-13/16" 2-13/16" 3" 3"

M. of Inertia 29 74 86 100 115 198 318 486 713

Large diameter drill collars will help provide the ultimate in stiffness, so it is important to select the maximum diameter collars that can be safety run. Drill collars increase in stiffness by the fourth power of the diameter. For example, a 9-1/2" diameter drill collar is four times stiffer than a 7" diameter drill collar and is two times stiffer than an 8" diameter drill collar when all three sizes may be considered appropriate for drilling a 12-1/4". hole.

C. Clearance There needs to be a minimum clearance between the wall of the hole and the stabilizers. The closer the stabilizer is to the bit, the more exacting the clearance requirements are. If, for example, 1/16 " undergauge from hole diameter is satisfactory just above the bit, then 60 feet above the bit, 1/8" clearance can be a critical factor for packed hole assembly.

D. Wall Support and Length of Contact Tool Bottom assemblies must adequately contact the wall of the hole to stabilize the bit and centralize the drill collars. The length of contact needed between the tool and the wall of the hole will be determined by the formation. The surface area in contact must be sufficient to prevent the stabilizing tool from digging into the wall of the hole. If this should happen, stabilization would be lost and the hole would drift. If the formation is strong, hard and uniform, a short narrow contact surface is adequate and will insure proper stabilization. On the other hand, if the formation is soft and unconsolidated, a long blade stabilizer may be required. Hole enlargement in formations that erode quickly tends to reduce effective alignment of the bottom assembly. This problem can be reduced by controlling the annular velocity and mud properties.

V. Packed Hole Assemblies Proper design of a packed hole assembly requires a knowledge of crooked hole tendencies and degree of drillability of the formations to be drilled in each particular area. For basic design practices the following are considered pertinent parameters: Parameters Crooked Hole Drilling Tendencies: 1. Mild Crooked Hole Country 2. Medium Crooked Hole Country 3. Severe Crooked Hole Country Formation Firmness: 1. Hard to Medium Hard Formations:

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a) Abrasive b) Non-Abrasive 2. Medium Hard to Soft Formations

A. Mild Crooked Hole Country The packed hole assembly shown in Figure P1-10 for mild crooked hole country is considered the minimal assembly for straight hole drilling and bit stabilization. Figure P1-10 Mild Crooked Hole Country

Three points or zones of stabilization are provided by Zone 1 immediately above the bit, Zone 2 above the large diameter short drill collar and Zone 3 atop a regular length large diameter collar. A vibration dampener (when used) should be placed above Zone 2 for the best performance. !n Very Mild crooked hole country the vibration dampener may be run in place of the short drill collar between Zone I and Zone 2. When rough drilling conditions are encountered, a vibration dampener will increase penetration and add life to the drill bit. Wear and tear on the drilling rig and drill stem will also be reduced. NOTE: IN VERY MILD CROOKED HOLE COUNTRY THE VIBRATION DAMPENER MAY RE RUN IN PLACE OF THE SHORT DRILL COLLAR.

B. Medium Crooked Hole Country A packed hole assembly for medium crooked hole country is similar to that for mild crooked hole conditions but with the addition of a second stabilizing tool in Zone 1. The two tools run in tandem provide increased stabilization of the bit and add stiffness to limit angle changes caused by lateral forces. See Figure P1-11.

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Figure P1-11 Medium Crooked Hole Country

C. Severe Crooked Hole Country In severe crooked hole country three stabilization tools are run in tandem in Zone I to provide maximum stiffness and wall contact to aim and guide the bit. In 8-3/4" and smaller hole sizes it is also recommended that a large diameter short collar be used between Zone 2 and Zone 3. This will increase stiffness by reducing the deflection of the total assembly and allows the tools in Zone 1 and Zone 2 to perform their function without excessive wear due to lateral thrust or side-loading from excess deflection above. See Figure P1-12. Figure P1-12 Severe Crooked Hole Country

* N0TE: USE SHORT DRILL COLLAR IN 8-3/4" AND SMALLER HOLES.

D. Mild, Medium and Severe Crooked Hole Country Figure P1-13 shows all three basic assemblies required to provide the necessary stiffness and stabilization for a packed hole assembly.

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Figure P1-13 Three Basic Assemblies

* THE SHORT DRILL COLLAR LENGTH IS DETERMINED BY THE HOLE SIZE. HOLE SIZE (INCHES) = SHORT DRILL COLLAR (FEET) +/- 2 ft EXAMPLE: USE APPROX. AN 8 FT COLLAR IN AN 8" DIAMETER HOLE. A short drill collar is used between Zone 1 and Zone 2 to reduce the amount of deflection that would be caused by the drill collar weight. As a general rule of thumb the short drill collar length in feet is approximately equal to the hole size in inches, plus or minus two feet. For example: a short collar length of 6 to 10 feet would be satisfactory in an 8 inch bole.

VI. Stabilizing Tools There are three basic types of stabilizing tools: 1) Rotating Blade, 2) Non-Rotating Rubber Sleeve and 3) The Rolling Cutter Reamer. Some variations of these tools are as follows:

A. Rotating Blade A rotating blade stabilizer can be a straight blade or spiral blade configuration, and in both cases the blades can be short or long. See Figure P1-14.

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Figure P1-14 Rotating Blade Assemblies

Short Spiral Blade; Long Spiral Blade; Short Straight Blade; & Long Straight Blade The rotating blade stabilizers shown in Figure P1-14 are available in two types: 1) Shop Repairable and 2) Rig Repairable. 1. Shop Repairable: Refer to Figure P1-14 Rotating Blade Assemblies The shop repairable tools are either integral blade, welded blade or shrunk on sleeve construction. Welded blade stabilizers are popular in soft formations but are not recommended in bard formations because of rapid fatigue damage in the weld area. 2. Rig Repairable: Refer to Figure P1-14 Rotating Blade Assemblies Rig repairable stabilizers either have a replaceable metal sleeve or replaceable metal wear pads. These tools were originally developed for remote locations but have received widespread acceptance in the last few years. All rotating blade stabilizers have fairly good reaming ability and because of recent improvements in hard-facing, have very good wear life. Some of the hard-facing materials used today are: 1. Granular tungsten carbide 2. Crushed sintered tungsten carbide 3. Sintered tungsten carbide (inlaid) 4. Pressed in sintered tungsten carbide compacts

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B. Rig Replaceable Non-Rotating Sleeve Stabilizer The non-rotating rubber sleeve tool is a very popular stabilizer because it is the safest tool to run from the standpoint of sticking and washover. This type of stabilizer is most effective in areas of hard formations such as lime and dolomite. Since the sleeve is stationary, it acts like a drill bushing and therefore will not dig into and damage the wall of the hole. It does have some limitations. The sleeve is made of rubber and in temperature over 250 degrees Fahrenheit is not recommended. It has no reaming ability and sleeve life may be short in holes with rough walls. See Figure P1-15. Figure P1-15 Non-Rotating Rubber Sleeve Stabilizer

C. Rolling Cutter Reamer Rolling cutter reamers are used for reaming and added stabilization in hard formation. Wall contact area is very small, but it is the only tool that can ream hard rock effectively. Any time rock bit gage problems are encountered; the lowest contact tool should definitely be a rolling cutter reamer. See Figure P1-16.

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Figure P1-16 Rolling Cutter Reamer

D. Mild, Medium and Severe Crooked Hole Country in Hard to Medium-Hard Formations Figure P1-17 Mild, Medium and Severe CHC in Hard to Medium-Hard Formation

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In Zone 1-A (directly above the bit) a rolling cutter reamer should be used when bit gage is a problem in hard and abrasive formations. A six point tool would be required for extreme conditions. In non-abrasive formations, some type of rotating blade tool with hard-facing would be desirable. NOTE: USE REAMER IF BIT GAGE IS A PROBLEM. USE 6-PT. IN EXTREMELY HARD & ABRASIVE FORMATIONS

E. Medium and Severe Crooked Hole Country in Hard to Medium-Hard Formations In Figure P1-18 it is shown that some type of rotating blade stabilizer would be recommended in Zone 1-B with hard to medium hard formations and medium to severe crooked hole tendencies. Figure P1-18 Medium and Severe CHC in Hard to Medium-Hard Formations

NOTE: THE SAME TOOLS WOULD BE USED IN ZONE I C FOR SEVERE CROOKED HOLE COUNTRY For severe crooked hole drilling, one of the same types of tools could be used in Zone 1-C.

F. Mild, Medium and Severe Crooked Hole Country -- Hard to Medium-Hard Formations Rotating blade type tools would be good in Zone 2 for all three conditions of crooked hole tendencies. In very mild crooked hole country, a non-rotating sleeve type tool would suffice. See Figure P1-19.

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Figure P1-19 Mild, Medium and Severe CHC in Hard to Medium-Hard Formation

NOTE: IN VERY MILD CROOKED HOLE COUNTRY A N.R.S. STAB. MAY BE USED IN ZONE 2.

G. Mild, Medium and Severe Crooked Hole Country with Hard to Medium-Hard Formations With the slightest deviation from vertical, drill collars will lie on the low side of the hole because of their enormous weight. Therefore, the function of Zone 3 is to pull the collars away from the wall, thereby preventing any lateral force from being transmitted to the bit. Both the rotating blade and the non-rotating rubber sleeve stabilizers may be used for this job in hard to medium hard formations. See Figure P1-20.

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Figure P1-20 Mild, Medium and Severe CHC in Hard to Medium-Hard Formation

Any stabilizers run above Zone 3 would be used only to prevent the drill collars from buckling or becoming "wall stuck", and in most cases would have very little effect on directing the bit.

H. Mild, Medium and Severe Crooked Hole Country -- Medium-Hard to Soft Formations Tools for use in medium hard to soft formations, where bit gauge is no problem, must provide maximum length of wall contact to provide proper stabilization to the drill collars and bit. For all degrees of crooked hole tendencies, rotating blade stabilizers would be recommended. Figure P1-21 Mild, Medium and Severe CHC in Medium-Hard to Soft Formation

* Modern packed hole assemblies, when properly designed and used, will:

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* Reduce rate of hole angle change. A smooth walled hole with gradual angle change is more convenient to work through than one drilled at minimum hole angle with many ledges, offsets, and sharp angle changes. * Improve bit performance and life by forcing the bit to rotate on a true axis about its design center, thus loading all cones equally. * Improve hole conditions for drilling, logging, and running casing. Maximum size casing can be run to bottom. * Allow use of more drilling weight through formations which cause abnormal drill. * Maintain desired hole angle and course in directional drilling. In these controlled situations, high angles can be drilled with minimum danger of key seating or excessive pipe wear.

I. Packed Pendulum Because all packed hole assemblies will bend, however small the amount of deflection, a perfectly vertical hole is not possible. The rate of hole angle change will be kept to a minimum but occasionally conditions will arise where total hole deviation must be reduced. When this condition occurs the pendulum technique is employed. If it is anticipated that the packed hole assembly will be required after reduction of the hole angle, the packed pendulum technique is recommended. In the packed pendulum technique the pendulum length collars are swung below the regular packed hole assembly. When hole deviation has been dropped to an acceptable limit, the pendulum collars are removed and the packed hole assembly again is run above the bit. It is only necessary to ream the length of the pendulum collars prior to resuming normal drilling. If a vibration dampening device is used in the packed pendulum assembly, it should remain in its original pickup position during the pendulum operations. Figure P1-22 Packed Pendulum

J. Reduced Bit Weights By reducing the weight on the bit, the bending characteristics of the drill string are changed and the hole will tend to be straighter. One the oldest techniques for straightening the hole was to reduce the weight on the bit and speed up the rotary table. In recent years it has been found that this is not always the best procedure because reducing the bit weight sacrifices considerable penetration rate. Worse, it frequently brings about dog-legs as illustrated in

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Figure P1-23. Figure P1-23 Effect of Reduced Bit Weights on Deviation

As a point of caution then, the straightening of a hole by reducing bit weight should be done very gradually so that the hole will tend to return to vertical without sharp bends and will therefore be much safer for future drilling. A reduction of bit weight is usually required when changing from a packed hole assembly to a pendulum or packed pendulum drilling operation. 1. Calculating Drilling Weight How many drill collars are needed? To answer this question, size of collars, weight to be run on the bit, maximum mud weight, and whether the well is vertical or directional, must be known. If it is a directional hole, it is necessary to know the maximum anticipated inclination from the vertical. Drill collars are run to supply the necessary weight for the bit to make it drill, to prevent the drill pipe from being run in compression, and to add stiffness to the BHA for the prevention of dog-legs. When drill pipe is rotated in compression, cyclic stresses can cause accelerated fatigue failures in the pipe. For this reason, 10% to 25% excess drill collar weight normally is used to keep the drill pipe in tension at all times. 2. Mathematical Calculation The following equation is sometimes used to determine the necessary number of drill collars: Weight of D.C.'s in Air = (Bit Weight) x (Safety Factor) / (Mud Buoyancy Factor) Example: Requirements: Bit Weight Required

= 55,000 lbs

12 Lb/Gal Mud

= 0.82 Buoyancy Factor

15% Safety Factor

= 1.15

Vertical Hole

= 0° Inclination

From the Equation: Drill collar weight needed = 55,000 x (1.15 / 0.82) = 77,134 lb Nine 8 inch OD by 2-13/16 inch ID by 31 ft will be used. Example:

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How many 6-3/4 inch OD by 2-13/16 inch ID by 30 feet are needed? Total air weight = 77,134 lbs Nine 8 inch (150 lb/ft x 9 x 31 ft) = 41,850 lbs 6-3/4 inch DC weight requirement = (77134 - 41,850) = 35,284 lbs The 6-3/4 inch by 2-13/16 inch DCs = 100 lbs/ft 35,284 / 100 = 353 ft, and 353 ft / 30 ft = 11.77 Rounding upwardds, twelve 6-3/4 inch drill collars are needed.

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Figure P1-24 Drilling Weight Planner (0-35 Kips) *(15% Safety Factor Built In)

3. Nomograph Calculation (Figure P1-24 & Figure P1-25)

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This problem can be solved easily with the Drilling Weight Planner (Fig. Figure P1-25).

Figure P1-25 Drilling Weight Planner (0-70 Kips)*(15% Safety Factor Built In)

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Enter the nomograph at point A on the bottom left-hand side at 55,000 lbs weight on bit. Draw a vertical line up to the zero degree hole inclination line (vertical hole). Draw a horizontal line over to point C, 12 lb/gal drilling mud. Draw a perpendicular line through point C from the top of the page to the bottom. The weight of drill collars in air (77,134 lb) can be read at both the top and bottom at point D. The buoyed weight of all the collars can be read at point E (63,250 lbs). This would be the weight of the collars hanging in the elevators with the hole full of mud. Select the 8 inch drill collar line and scale off nine 8 inch drill collars between points 1 and 2. Draw a perpendicular line up to the 6-3/4 inch drill collar line and count the number of 6-3/4 inch drill collar line with the perpendicular line that goes through point C. This line goes from 13-1/2 to 25-1/2 for a total of twelve 6-3/4 inch drill collars. This is the same number calculated mathematically. By using this graph, any combination of drill collar sizes, and also Hevi-Wate drill pipe, can be solved graphically for both vertical and directional holes. 4. Directional Hole Calculation For directional holes, point B would not be 0 degrees but would be the degrees of inclination from vertical anticipated. A directionally drilled hole requires that a correction be made in total drill collar weight, because only a portion of the total weight will be available to the bit (Figure P1-26). Figure P1-26 Weight Available for Bit in Directional Holes

Using the equation in Figure P1-26 P = W x Co x 0 for a 45° hole; P = 0.7071 x W for a 60° hole; P = 0.5 x W for a 90° hole; P = 0 x W = 0 From the equation, in a 600 hole deviation, only half of the drill collar weight is available for the bit, so twice as many drill collars would be required over the number needed in a vertical hole, to load the bit with the same weight, without placing some of the drill pipe in compression. A safety factor of 15% is built into the nomograph, so no additional weight adjustment is necessary. The drilling weight planner shows the available weight for the bit, but should not be confused with the actual weight on the bit. Once the driller tags bottom, with the pump running, the amount of indicated weight slacked off is the actual drilling weight.

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When only a fixed number of drill collars are available, the nomograph can be worked backwards to determine the amount of drilling weight available for the bit. When drilling high angle holes it is possible to use less than the 15% safety factor on the chart, as the drill pipe will lie on the low side of the hole, and thus requires a greater compressive load to cause a helical buckle.

VII. Conclusion In summation, a well engineered bottom hole assembly with the proper selection of stabilizing tools in all three zones, should produce a useful hole with a full-gauge, smooth bore .free from dog-legs, key seats, offsets, spirals and ledges, thereby making it possible to complete and produce the well. Both the Drilling Contractor and Oil Company Operator should realize additional profits from a well planned drilling program. Careful planning will usually result in the best drill stem for a given job.

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P-2 Controlled Directional Drilling I. Introduction Controlled Directional Drilling can be defined as the technique of intentionally deviating a well bore so that the bottom hole location or any reasonable intermediate portion of the hole between the surface location and the total depth is positioned into a pre-determined target(s) area that is located at a given horizontal and vertical distance from the surface location of the well. Application Figure P2-1. outlines many of the applications of Controlled Directional Drilling. Figure P2-1a Controlled Directional Drilling Applications

Exploration From One Wellhead, Multiwells From Artificial Island, Shoreline And Fault Control

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Figure P2-1b More Controlled Directional Drilling Applications

Inaccessible Locations, Relief Well Control, Sidetracking & Straightening, Salt Dome Drilling The technical advances developed in recent years has made this unique method of drilling a valuable industry tool. Many priceless sources of energy could not have been economically developed without mastery of directional drilling techniques being accomplished at a reasonable cost.

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II. Basic Deflection Patterns Figure P2-2 Basic Deflection Patterns

Type I. This type of control pattern is used in most of today's directional drilling operations. the well to be deviated is drilled as straight as possible to the point where deflection is to begin (Kickoff point). Initial deflection is accomplished usually by employing either the jetting technique or a downhole motor (see deflection tools). After the drift angle and direction has been obtained in accordance with the pre-planned program, surface casing is set to protect and isolate the build-up section of the hole. Drilling is continued on as straight a path as possible to the desired bottom hole (target) of the well.

Type II. The upper portion of this type of pattern is like the Type I procedure. The well is drilled as straight as possible to the kickoff point, deflection and direction is obtained, and the build up section of the hole cased off with surface pipe. Drilling continues on as straight a path as possible to a predetermined point where the deflection angle is slowly reduced to vertical. A straight hole is maintained in the target area to the total depth of the well from that point. However, if much straight hole is to be drilled below the deviated section of hole, or if undesirable geopressures are to be encountered, an intermediate casing string is usually set to protect and isolate the hole. The Type II pattern is usually used when multiple producing zones are to be developed from a single well bore or if wildcatting below a known producing horizon is desired.

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Type III. This type of pattern is usually used for either pre-planned short deviations or for plugging back and deviating a straight hole that has been drilled. Deviation is accomplished in the same manner as the Type I and II patterns except this type of well is usually not protected by casing until total depth is reached. the Type III pattern is usually used for exploratory purposes or when a single wellhead must be used for economy or surface location considerations. Protective casing is usually not set through the deviated section of the hole in this type of pattern.

III. Planning And Supervising The Directional Well Introduction This section contains check lists and guidelines that will assist in planning and supervising a directional well. The first Planning Information Check List contains items that the Operator should provide the Directional Drilling Company so that the program can be properly developed. The second Planning Information Check List contains items that the Directional Drilling Company should provide the Operator so that the program can be controlled. In preparing a directional well program, various parts of the well course pattern are studies. The Well Course Planning Section contains control activities beneficial in drilling a directional well. Although the actual planning of directional drilling operations is usually done at the office of the operator in communication with the directional service company, the on-site drilling foreman should be informed of the drilling plans in order to insure that instructions are followed and good drilling practices adhered to.

A. Planning Information Required by Service Companies 1. Well name, number, location and lease description. 2. True vertical depth of well. 3. Deflection distance and direction from the surface location. 4. Target description and limitations. 5. Hole sizes and casing program. 6. Mud program. 7. Location of adjacent wells including any available directional surveys. 8. Drilling information from adjacent or nearby wells. 9. Name and rig number of Drilling Contractor. 10. Drill pipe description. 11. Drill collar and heavy weight pipe information. 12. Pump type, horse power, liner sizes, length of stroke, pressure rating, etc. 13. Type of wireline equipment available. 14. Transportation of tools and personnel schedule. 15. Available communications. 16. Names and telephone numbers of duty Contractor and Company foreman personnel.

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17. Minimum inside diameter of tubular drilling equipment. 18. Accommodations for directional drilling personnel. 19. Any other pertinent data regarding directional well. 20. Dog-leg severity limitations. 21. Survey procedure for measuring dog-leg severity.

B. Planning Information Required by the Operators 1. A copy (copies) of the directional drilling proposal plot. 2. A proposed tool and equipment inventory furnished by the Service Company. 3. Additional inventory requested by the Service Company. 4. Non-magnetic collar requirements. 5. Compass declination required for drilling area to correct compass reading to True North. 6. Survey recommendations. 7. Outline of overall directional drilling procedure to be used. 8.Name, location, address and telephone number of supervisor assigned to job. 9. Name, location, address and telephone number of immediate superior of supervisor. 10. Survey calculation methods to be employed. 11. Transportation schedule for men and equipment.

C. Composition of a Directional Drilling Proposal Plat A Directional Drilling Proposal Plat is shown in Figure P2-3.

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Figure P2-3 Directional Drilling Proposal

It consists of the following segments: A. Targets A target should be selected as large as acceptable to achieve the objective. If multiple zones are to be penetrated, the multiple targets should be selected so that the planned pattern is reasonable and can be attained without causing excessive drilling problems. B. Kickoff and Build Angle The selection of the kickoff point depends on many factors such as hole pattern selected, casing program, mud program, displacement required and the maximum angle to be used. The direction of the kickoff is determined by offsetting the anticipated walk of the hole in the opposite direction. Angle building rate is usually planned for 1-1/2° to 2°/100 feet of hole drilled.

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C. Locked-in Angled Straight Section Once the desired inclination angle is reached, a stiff bottom assembly is used to hold the angle and drill a lockedin angled straight section of hole. Bit weight and rotary speed can usually be used to control the inclination and direction. Hole walk is hard to predict and almost equally hard to control. The usual practice is to predict the amount and direction of walk and then have that amount of lead established when the average angle is reached. For better directional drilling, the inclination angle of locked-in straight section should be between 15 degrees and 45 degrees. Angles over 45 degrees often produce excessive drag and torque on the drill string and present logging, casing, cementing and production problems. Angles less than 15 degrees often produce directional control problems. D.

Angle Drop-Off Section

In patterns with an angle drop-off section, the rate of drop-off is not as critical as the rate of build up in the angle build section. There is less tension in the drill pipe run through the deeper dog-leg and less time is spent rotating below the dog-leg. E.

Dog-leg Severity Figure

Directional drilling intentionally creates bore hole deviations or dog-legs; however, the severity of the dog-legs must be controlled to prevent fatigue failure of the drill string, key seating, difficulty in logging and surveying below the bend, production problems, inferior cementing caused by non-centralized casing and easing coupling failure due to excessive flexure. A dog-leg, even a severe one, does not cause immediate trouble. It is only much later that a dogleg may become responsible for trouble and large losses of money. When drilling a few thousand feet below the dog-leg, the tool joints in the dog-leg are subjected to extremely high stress reversals which can cause early failure of the drill pipe. Early detection of dog-legs is very important. In the event a severe dog-leg appears in the hole above the expected total depth, then an important decision must be made before further drilling. A dog-leg can be smoothed to some extent by string reaming, but a severe dog-leg should be wiped out and resurveyed or side tracked to be sure the severe dog-leg has been eliminated. For complete dog-leg severity planning see Section VIII. Dog-Leg Seventies.

D. Supervising a Directionally Drilled Hole General Guidelines Check the Service Company proposal, Figure P2-3 Directional Drilling Proposal, against the well prognosis before hole deflection actually starts. 1. Be sure the target direction and distance are correct. 2. Check the tool inventory with the delivery ticket to be sure everything required has reached the location. 3. Read the single shot survey film discs to insure correctness. 4. Check survey calculations for correctness. 5. Be sure dog-leg severities are within prescribed limits set by the operator. 6. Keep well plot posted daily. 7.Do not allow the service company to let the hole drift off course more than one normal tools run. 8. Avoid rotating the drill pipe off bottom unnecessarily in a directional hole. 9. Instruct drillers in procedures to prevent swabbing trips. 10. Do not permit rig drillers to pull on the pipe in tight places excessively. A series of easy pulls will usually work the pipe through tight places.

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11. Do not permit rig driller to drill through bridges encountered on trips in the hole without the directional supervisor being present. 12. Instruct the directional drilling supervisor in keeping drilling records your company will require.

IV. Sub Surface Surveying A. Surveying Instruments 1. Single Shot A magnetic survey instrument consists of a compass, inclination unit, camera section, batteries and a time device. This instrument records drift angle and direction of the hole data on a single film disc. This instrument is used by the directional supervisor during drilling operations. 2. Multi-Shot A magnetic survey instrument that consists of the same elements as a single shot instrument except multiple readings of drift angle and direction are recorded on movie film. This instrument can be dropped in the hole and landed inside of a nonmagnetic collar to record many survey stations on trips in or out of the hole. 3.

Gyroscope

This type of survey instrument can record single or multi-shot surveys depending on the type of timing device and camera unit used. This instrument must have a known direction to set its pointer toward and all hole directions are referenced from the known direction. The instrument can be used inside of a cased hole because it is not affected by magnetized pipe or influenced by formations that would affect a magnetic compass.

B. Non-Magnetic Drill Collars The maximum length of non-magnetic drill collar required can be determined by referring to Figures P2-5, Figure P2-6 and Figure P2-7.

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Figure P2-5 Data Chart - Zone I

Notes for Zone I Data Chart Zone I Use 18' Collar in area below Curve A Use 25' Collar in area below Curve B Use 30' Collar in area below Curve C Use Tandem (18' + 25') Collars in areas above Curve B Compass spacing 18' collar: 1' to 2' below center 25' collar: 2' to 3' below center 30' collar: 3' to 4' below center tandem 18' + 25': center of bottom collar

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Figure P2-6 Data Chart - Zone II

Notes for Zone II Data Chart Zone II Use 30' collars in area below curve A Use 60' collars in ama below curve B with packed bottom hole assembly Use 60' collars in area below curve C with near bit stabilizer only. Use 90' collars in area above curve C Compass Spacing 30' collar: 3' to 4' below center 60' collars: at center ( curve B ) 60' collars: 8' to 10' below center (curve C) 90' collars' at center

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Figure P2-7 Data Chart - Zone III

Notes for Zone III Data Chart Zone III Use 60' collars in area below curve A with packed bottom hole assembly . Us 60' collars in ama below curve B with near bit stabilizer only. Use 90' collars in area below curve C with any bottom hole assembly. Compass Spacing 60' collars: at center ( curve A ) 60' collars: 8' to 10' below center ( curve B ) 90' collars: at center These charts vary as to location. Refer to the Zone Selection map, Figure P2-4.

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Figure P2-4 Zone Selection Map

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Magnets are sometimes used in non-magnetic drill collars by the Directional Driller for orientation only, and should be replaced with brass pugs when they are not required for orientation.

C. Surveying Procedure All Surveys should be reported as located at the angle unit depth. Report all acceptable surveys (exclude orientation surveys). The IADC API drilling report is the place to record each bottom assembly used. 1. Location of Baffle Plate The baffle plate for the survey instrument should be located at the bottom of the bottom non-magnetic drill collar. 2. Declination The difference between true north and magnetic north is declination. The declination varies around the world as shown on the example Isogonic Chart attached, Figure 2-8.

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Figure P2-8 Isogonic Chart

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Notes for Figure P2-8 Isogonic Chart Magnetic declination (also called "variation of the compass") is here shown as of the beginning of 1975 by means of isogonic lines, i.e. lines of equal declination. These lines are solid in the area where the compass points east of true north, and broken in the area where it points west of true north. The lines are drawn to show a relatively smooth distribution. The irregularities remaining in the lines, particularly the local anomalies, rather than as a close representation of the declination, If Disc Reading

EAST DECLINATION (Add in Azimuth)

NE

ADD to reading

SE

SUBTRACT from reading

SW

ADD to reading

NW

SUBTRACT from reading

WEST DECLINATION (Subtract in Azimuth) SUBTRACT from reading ADD to reading SUBTRACT from reading ADD to reading

Magnetic declination (also called "variation of the compass") is here shown as of the beginning of 1975 by means of isogonic lines, i.e. lines of equal declination. These lines are solid in the area where the compass points east of true north, and broken in the area where it points west of true north. The lines are drawn to show a relatively smooth distribution. The irregularities remaining in the lines, particularly the local anomalies, rather than as a close representation of the declination, If Disc Reading

EAST DECLINATION (Add in Azimuth)

NE

ADD to reading

SE

SUBTRACT from reading

SW

ADD to reading

NW

SUBTRACT from reading

WEST DECLINATION (Subtract in Azimuth) SUBTRACT from reading ADD to reading SUBTRACT from reading ADD to reading

There is an annual variation in declination. The chart used must be up to date. The declination can be corrected to true north or to grid north. The correction will be made to true north unless stated otherwise in the drilling program or directional plat. 3. Calculation of Surveys The radius of curvature method is the most accurate way to calculate a directional survey. This is usually done by means of a computer or programmable pocket calculator. However, the balanced tangential or vector averaging method approaches the accuracy of the radius of curvature method and is usually used by directional drilling supervisors in the field.

V. Deflection Tools A. Downhole Motors The downhole mud motor has replaced the Whipstock as the primary tool to deviate the direction of a wellbore. The mud motor function is to rotate the bit when a bent sub assembly is used. This eliminates drill string rotation and the well bore is deviated in the direction of the oriented bent sub. The deviation assembly is made up of a nonmagnetic collar, a bent sub, a mud motor and the drilling bit. The downhole mud motor is either a positive

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displacement type or a turbine. The motor size is determined by the size of the bit being run. Performance characteristics are given in Table P2-1 and Table P2-2.

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TABLE P2-1a Dyna Drill - PDM - Micro Slim Tool

TABLE P2-1b Dyna Drill - PDM - Data and Requirements

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TABLE P2-2a D-89 Turbodrill Specifications

TABLE P2-2b D-89 Turbodrill Performance Data

The drilling bit can be either tricone or diamond, whichever is most suitable for the formation being drilled. This deviation assembly has replaced the Whipstock because it is a time saver, provides dog-leg control and drills a full gauge hole. The assembly is oriented from the surface by means of conventional single shot survey instruments or surface indicating conductor cable guidance instruments. The orientation is maintained and controlled by the rotary table which is locked while drilling. Since the drill string does not rotate, controlled deviation is achieved by the bent sub, which maintains the motor and the bit at a fixed angle relative to the non-magnetic drill collar. As hole is made, this angle builds along a continuous smooth are of a circle. The radius of the circle is determined by the angle of the bent sub, the motor size and the hole size. 1. Turbines Turbines are in general, higher speed, lower torque motors when compared to the positive displacement motors. The net horsepower of the turbine is equal to or greater than that of positive displacement motors. These characteristics make the turbine ideal for diamond bits, but still suitable for many tricone bit applications. Turbine fluid requirements and performance characteristics are given in Table P2-2.

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Dog-leg expectancy is a function of the assembly geometry and not the type of mud motor. You would expect to develop the same rate of hole deviation change if the bent sub angle, motor O.D. and length and average weight on bit are the same regardless of the type of mud motor. When a turbine is used, a screen should be placed between the kelly and the drill pipe to insure against foreign material being pumped through the turbine and causing a motor failure. If the mud system is using lost circulation material, the screen procedure is not feasible and a turbine should not be used. 2. Positive Displacement Mud Motor The positive displacement mud motor runs at lower RPM for a given mud volume than the turbine. Large diameter tricone bits with high torque requirements are easily handled. Tool operating data is given in Table P2-1. The positive displacement motor torque varies in a direct ratio to the pressure differential across the motor. This provides surface indication on the mud pump gauge. Increasing bit torque up to stall conditions can be monitored. Lost circulation material in the mud is normally handled by positive displacement motors without problems.

B. Whipstocks The removable whipstock is a reliable deflection tool that is usually used when jetting or when downhole motors cannot be used. It is a cylindrical steel casting, five to thirteen feet long, with a ring at the top, a concave inclined groove formed on one side and a chisel point bottom. The ring at the top is smaller than the bit and provides the means of transporting the whipstock in and out of the hole. The chisel bottom holds the whipstock stationary when it is set, and the indented groove, (usually 3 degrees) guides the bit to a new course. There are two types of whipstocks: 1) the bottom circulating in Figure 2-9a and 2) the standard or conventional shown in Figure 2-9b. Figure P2-9 Whipstocks

The circulating whipstock differs from the standard whipstock, in that there is a control sub immediately above the bit that prevents the flow of circulating fluid through the bit and deflects it through a hollow shear pin used to pin the whipstock to the drill pipe assembly. The flow of fluid passes through the shear pin and down to the bottom of the whipstock via a bored circulating channel in the back of the whipstock. The fluid then flows out the bottom of

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the whipstock. This permits the bridges in the hole to be washed through, and fill up on the bottom of the hole to be circulated clean. Prior to setting the whipstock, a ball is dropped through the drill pipe and seated in the control sub. The drilling fluid is then diverted from the bottom of the whipstock and established through the bit. The whipstock can then be set and drilling commenced. A 15' - 20' rat hole is usually drilled below the whipstock setting point. The diameter of this hole is smaller than the open hole, and must be reamed out to the full hole size by means of a hole opener. Therefore, setting a whipstock is slower than other deflection tool methods because more trip time is needed to set and ream the rat hole out to full gauge. A combination universal knuckle joint and short drill collar may be run in conjunction with the whipstock when extreme angles are required to sidetrack an enlarged hole.

C. Jetting Holes in soft formations are usually deviated by using a bit which has all but one of the nozzles closed off, or substantially reduced in size. One 3/4" or 5/8" nozzle and two 1/4" nozzles are popular sizes frequently used. To use, an angle building assembly (see Fig. 10) and jet bit designed for deviation jetting is run in the hole and oriented in the desired direction. Figure P2-10 Jetting for Directional Control

Notes for Figure P2-10 A. Washing action by large jet (left) B. When rotation is started stabilizer smooths out dog-leg on high side (middle)

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C. After initial deflection has been accomplished, stabilizer acts as a fulcrum for continuing the hole curvature (right) A high rate of circulation is established and the bit with weight applied is set on bottom. Fluid circulating through large nozzle permits the hole to erode on one side. The drilling assembly is spudded to force the bit to follow the jetted hole. After two to four feet of jetted hole is obtained drilling is commenced. After jetting, a single shot survey is run to determine the dog-leg severity of the hole. Reaming may be necessary if the dog-leg obtained is more than desired.

D. The Rebel Tool The Rebel Tool is designed to prevent and correct lateral drift. See Figure P2-11 Figure P2-11 Rebel Tool

Without orientation, the tool counteracts the bit's tendency to walk either left or right.

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With a Rebel Tool, Drilling can continue under normal or near-normal weight loads, rotary speeds and pump pressures. The drift angle can be maintained as effectively with the Rebel Tool as with ordinary drill collar and stabilizer drilling assemblies. Mounted just above the bit, the Rebel Tool imparts a lateral shove to the sidewall by means of two opposing paddles. The paddles are rigidly secured to a common shaft which is free to turn within a groove along the tool's body. As it rotates to the low side of a slant hole, the top paddle is forced by weight into a recess in the body of the tool. This extends the bottom paddle to shove against the sidewall in the direction desired -- down near the bit, where the effect is greatest. In cases where the Rebel Tool is used to correct lateral drift that already has occurred, slight overcompensation is recommended before pulling the tool to resume normal drilling. Several hundred feet of depth should be allowed to effect the desired walk. To walk bit left: with left paddles (seen here in cross section from above, the bottom paddle kicks bit to the left when extended by weight on its opposing member

VI. Orientation Of Deflection Tools Deflection tools may be oriented by many means, the most common of which are:

A. Mule Shoe A lug inside of a special sub is aligned with the bend or face of a deflection tool that is run into the hole with the deflection tool. A single-shot instrument is run into the hole inside of a protective case that has a stinger on the bottom that is helixed in a curving manner so that when helex curving engages the orientation lug inside of the special sub, the instrument is rotated so that the key slot on the stinger sets exactly on the lug. A single-shot survey is taken so that the direction of the key slot can be determined. Orientation of the tool can then be completed.

B. Direct Method North and South magnets are placed inside of a nonmagnetic drill collar in a position to align with a needle located inside of the single-shot instrument. The compass unit is below the magnets and is not affected by the magnets. The needle pointing to the magnets is superimposed on a directional survey film disc. When a survey is taken, the direction of the deflection tool can then be found and the tool set.

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C. Surface Readout Figure P2-12 Steering Tool

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This method of tool orientation is used in conjunction with a downhole mud motor in order to accurately measure reactive torque generated by the motor while drilling. A mule-shoe orienting sleeve is run in the mud motor drilling assembly. A probe is run on electrical conductor wireline through the drill pipe and seated in the mule-shoe sleeve. Data from downhole is transmitted continuously via the wireline to the surface readout equipment located on the rig floor and in the wireline unit. The readout unit, depending on the brand used, can deliver one or all of the following typos of information: 1. Tool Face Direction 2. High Side of the Hole 3. Hole Direction 4. Drift Angle 5. Bottom Hole Temperature 6. Magnetic Information The kelly is not used while drilling with a surface read out unit in the hole. Instead, a circulating head is assembled on top of a joint or more of drill pipe.

VII. Principles Of Directional Drilling Stabilization A. Building Angle A Downhole Motor or Jet Bit assembly is usually used to start the deflection in a directional hole and to establish the deflection towards the bottom hole target. After the drift angle has approached approximately 5 degrees to 8 degrees, the deflection tool may be replaced with a drilling assembly as shown in Figure P2-13. Figure P2-13 Maximum Angle Building Assemblies

However, if jetting has been the method of initial control, the assembly shown probably has been the one used in conjunction with the orientable jet bit. In this event, drilling continues without requiring a trip.

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Building angle with a limber drilling assembly is based upon the fulcrum principle. The near bit stabilizer, properly spaced above the bit creates a pivot point wherein the bending drill collars force the top of the stabilizer to the low side of the hole and causes a lateral force at the bit in the opposite direction or high side of the hole. This causes the bit to increase drift angle.

B. Controlling Rate of Angle Increase Controlling the rate of angle increase is imperative if fatigue to drill pipe and drill collars is to be avoided. This can be accomplished with the angle building drilling assembly in one of several ways: 1. Reducing the O.D. of the stabilizer blades or cutters. 2. Changing the fulcrum point of the stabilizer. 3. Placing the stabilizer closer together in the drilling assembly. 4. Increasing the stiffness of the drill collars. 5. Changing bit weight, rotary speed and pump pressure. Type of stabilizers depend upon the formation in which they are to be used, (Figure P2-14). Figure P2-14 Minimum Angle Building Assemblies

Stabilizers are bearings placed on a drilling shaft (drill collars) and in general practice, the placing of bearings (stabilizers) closer together on a shaft (drill collar) stiffens the shaft. Therefore, by carefully controlling the span between the stabilizers, the directional driller can control the rate of deflection angle movement reasonably well.

C. Maintaining Angle When the deflection angle has reached the desired amount, the maximum or minimum angle building assemblies may be replaced with a stiff bottom hole assembly that will permit optimum drilling operations to continue in the directional hole. Usually, these assemblies are custom designed at the well site by the directional driller, based upon known experiences in the general area.

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Figures P15a, P-15b and P-15c show the progressive stiffness of the drilling assembly, but Figure P-15c is by no means the stiffest bottom hole assembly used. Figure P2-15 Packed Hole Assemblies

The use of square or triangle drill collars, multiple welded or integral blade stabilizers may be required, or roller reamers in conjunction with any appropriate mixture of stabilizer typos in order to "lock" the hole on course and to allow maximum penetration rates to be obtained. If an extremely stiff bottom hole assembly is desired to be run in a directional hole after a large amount of controlled hole has been drilled, then a Set of drilling jars should be used on the reaming trip in to hole with the stiff assembly to prevent sledging the string in tight portions of the hole. It may be necessary to lead the assembly into the hole with a pilot reamer to prevent side tracking the deviated portion of the hole.

D. Dropping Angle In Type II directional well patterns it is necessary to allow the drift angle to straighten back to vertical or near vertical. By controlling the distance between the bit and first stabilizer, (usually 60') and the stiffness of the drill collars, the rate of angle descent can be controlled. Since gravity and the weight of the drill collars apply a lateral force at the bit on the low side of the hole that is helped by the pivot point at the first stabilizer above the bit, straightening usually occurs.

E. Care of Stabilizers The bottom 120' of a drilling assembly is the critical portion for controlling a directional well. The stabilizers used in this area should be full gauge to 1/16" under unless undergauge stabilizers are required to hold angle. Undersized tools should be moved up higher in drill collar assembly or replaced with full gauge tools. Additional information on the subject of stabilization is contained in the Straight Hole Section of the manual.

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VIII. Dog-leg Severities A. Drill Pipe Fatigue Changes in hole curvature are often referred to as dog-legs. The severity of a dog-leg is determined by the average changes in angle and/or direction of the distance this change occurs. For example, if there is a 5 degree change in angle (no direction change) over 100 feet of hole, the dog-leg severity is 5 degrees per 100 feet. If directional survey information is known, Figure 16 can be used to determine dog-leg severity. Figure P2-16 Dog-Leg Severity Chart

Notes for Fig. P2-16 - EXAMPLE: STATION 1: 2910 FT DEPTH, 3° INCLINATION N11°E STATION 2: 3000 FT DEPTH, 5° INCLINATION N23°E A) CHANGE OF HORIZONTAL ANGLE: 23° - 11° = 12° B) AVERAGE HOLE INCLINATION: (3 + 5)/2 = 4° C) CHANGE IN INCLINATION: 5° - 3° = 2° E) SURVEY INTERVAL: 3000' - 2910' = 90' F) DOG-LEG SEVERITY = 2.5° Courtesy of Sii Drilco, ARTHUR LUBINSKI. "How To Determine Hole Curvature" Petroleum Engineer, February 1957 Until a dog-leg reaches some threshold value, no drill stem fatigue damage occurs. This threshold value is called Critical Dog-leg. The critical dog-leg is dependent upon the dimensions (size) and metallurgy of the drill pipe and drill pipe tension (pull) in the dog-leg.

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The charts in Figures P-17 through 20, constructed for most of the common size and type drill pipe, can be used to determine the Critical Dog-leg or the Maximum SAFE DOG-LEG limit that should not cause drill pipe fatigue damage. The charts in Figure P-17 and Figure P-18 are identical. Both are for Grade E drill pipe. Figure P2-17 Maximum Safe Dog-leg Limits Grade E Drill Pipe

Notes for Fig. P2-17 - EXAMPLE: Dogleg @ 3000 ft. (A) proposed mud weight at td 12,000 ft. = 16.0 lb/gal (B) 4-1/2'' 16.60 ppf drill pipe (17.8 ppf actual weight) DC length: 1000 ft DC weight: 60,000 lbs. in 16.0 ppg mud (C) Drill pipe below dog-leg = proposed TD - depth of dog-leg - DC length = 12,000 ft - 3000 ft - 1000 ft = 8000 ft. (D) Maximum safe dog-leg limit = 4.7° Complements of Drilco Figure P-18 simply shows an example of the damaging effect of rotating the bit off the bottom.

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Figure P2-18 Maximum Safe Dog-Leg Limits, Grade E DP, Ex. 2

Notes for Fig. P2-18 Example: (dog-leg at 3,000 ft.) (A) proposed mud weight at TD 12,000 ft. = 16.0 ppg (B) 4-1/2'' 16.60 ppf drill pipe (17.8 ppf actual weight) DC length: 1,000 ft. DC weight: 60,000 lb. in 16.0 lb./gal. mud (C) drill pipe below dog-leg = 8,000 ft. (E) 60,000 lb DC weight added (F) = 3.2° courtesy of SII Drilco Note: in the Figure P-18 example, rotating the bit off bottom subjects the drill pipe at 3000 ft (depth of dog-leg) to an additional 60,000 lbs. tension. This moves the maximum SAFE DOG-LEG limit (CRITICAL DOG-LEG) from 4.7 degrees to 3.2 degrees/100'. The charts in Figure P-19 and Figure P-20 for Grade S135 drill pipe are identical with Figure 20 showing an example of the poor practice of rotating off bottom.

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Figure P2-19 Maximum Safe Dog-Leg Limits, S-135 DP,

Ex. 1 Notes for Fig. P2-19 - EXAMPLE Example: (dog-leg at 3,000 ft.) (A) proposed mud weight at TD 18,000 ft. = 18.0 ppg (B) 4-1/2'' 16.60 ppf S-135 drill pipe (18.8 ppf actual weight) DC length: 1,000 ft. DC weight: 60,000 lb. in 16.0 lb./gal. mud (C) Drill pipe below dog-leg = proposed TD - depth of dog-leg - DC length = 18,000 ft - 3000 ft - 1000 ft = 14,000 ft. (D) Maximum safe dog-leg limit = 3.2° Complements of Drilco

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Figure P2-20 Maximum Safe Dog-Leg Limits, S-135 DP,

Notes for Fig. P2-19 - EXAMPLE Example: (dog-leg at 3,000 ft.) (A) proposed mud weight at TD 18,000 ft. = 18.0 ppg (B) 4-1/2'' 16.60 ppf S-135 drill pipe (18.8 ppf actual weight) DC length: 1,000 ft. DC weight: 60,000 lb. in 16.0 lb./gal. mud (C) Drill pipe below dog-leg = proposed TD - depth of dog-leg - DC length = 18,000 ft - 3000 ft - 1000 ft = 14,000 ft. (D) Maximum safe dog-leg limit = 3.2° Complements of Drilco The planning of directional wells should include a Dog-leg Control Program, Dog-leg severity limits do not pose great difficulties for competent directional drillers, but limits must be realistic. Figure P-21 illustrates a Critical Dogleg severity curve that could be calculated for drilling conditions expected to exist in a typical 12,000 foot well.

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Figure P2-21 Critical Dog-Leg Notes for Figure P2-21

Operating conditions to the left of this curve would almost insure a "fatigue free" well. Conditions to the right would probably result in drill pipe fatigue damage. Dog-leg limits are established to prevent drill pipe fatigue, but when those limits are maintained, there is also a reduction in associated hole problems. Excessive dog-legs cause key seats, casing wear, rotating torque, trip drag, etc. Overall drilling rate can be greatly improved by a carefully planned and executed dog-leg control program.

B. Drill Collar Fatigue Most drillers are familiar with Critical Dog-leg limits for drill pipe, but consideration is rarely given to the effect of dog-legs on drill collar fatigue. Critical dog-leg limits should be considered for drill collars. K.D. Schenck discussed this problem in the O.G.J. October 12, 1964.

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P-3 Horizontal Drilling The following is a series of five articles in the 1988/89 Drilling Contractor Magazine addressing horizontal drilling.

A. Planning (Authors Denny Kerr And Albert Odell) 1. Introduction A great deal of debate has taken place in the drilling industry in the past year or so regarding the classification of medium vs. long-radius wells. The means of differentiating between the two types invariably boils down to build rate expressed in degrees/100 ft. From a practical standpoint regarding drilling the well and designing the bottomhole assembly (BHA), the most significant difference between the two is the ability or inability to rotate the BHA and the drill stem without exceeding the endurance limits of the components. This factor has a major impact on almost every aspect of BHA design, well profile selection and a host of other drilling parameters such as mud properties and the hydraulics program. From a design and operations viewpoint, it makes a great deal of sense to consider long-radius wells as those where drill stem rotation is feasible at all times. Medium-radius wells, on the other hand, must deal with the not insignificant burden of being unable to rotate the BHA while drilling the build section of the well.

2. Long-Radius Assemblies Long-radius wells usually are drilled with steerable motors such as the one shown in Figure P3-1A.

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Figure P3-1A Long-Radius Assembly

This bottomhole assembly is typical of a 4-5 degree/100 ft build assembly. Note in the chart that the assembly was designed to achieve the desired 4-5 degree/100 ft angle change by sliding the assembly for approximately two joints of pipe and rotating the assembly for one joint of pipe. Should any decrease in build rate occur, caused by hole enlargement, unfavorable and/or unexpected changes in drilling conditions such as formation dip, the operator has a safety margin of approximately 33 % built into the BHA itself.

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An unexpected decrease in build rate can be compensated for by increasing the percentage of sliding vs. rotating time. Conversely, should the assembly build at a higher than expected rate, the operator has the option of increasing the percentage of rotating time thereby reducing the effective build rate. Assuming that the assembly has been properly designed initially, the operator could most likely adapt to changing lithologies, hole enlargement, etc., as they occur. Such an assembly could produce a smooth curve profile without the need for a tangent section, like the one shown in Figure P3-5A. Figure P3-5A Medium-Radius Well Profile

However, should a tangent section be desired, either to increase the safety margin over and above the 33 % intrinsic to the assembly or simply to increase well departure, then the proven ability of the steerable assembly to rotate and maintain angle assures that a trip simply to change-out the BHA is unnecessary. Strictly from a trajectory control standpoint, the ability to drill to a 90 degree inclination with such a system is no more difficult than is controlling a conventional directional well.

3. Medium-Radius Assemblies Once the ability to rotate the drillstring is forfeited, the design approach for the bottomhole assembly and the well profile itself changes significantly. More emphasis must be placed on accurate trajectory prediction. The inability to rotate without exceeding the endurance limits of the drill stem may also place greater demands on the hydraulics and mud programs. The agitation caused by rotation of the string is a very significant factor in high-angle/high-curvature hole cleaning and in preventing the formation of a cuttings bed. Without this mechanical agitation, the operator must rely solely on hydraulics and mud properties to remove cuttings from the wellbore. For now let us assume that the assembly is limited to the sliding mode only. Medium-radius assemblies typically are double-bend assemblies -- specifically, a single-bend steerable motor in conjunction with a second bent member aligned immediately above the motor. Because of the potential for sticking, such assemblies are generally run without stabilization.

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In the absence of rotation, stabilization below the bent motor housing serves no useful purpose and should be avoided. Figure P3-2A graphically illustrates a typical double-bend assembly. Figure P3-2A Medium-Radius Assembly

One of the most common misunderstandings concerning such double-bend configurations is that the bent sub is required to achieve the higher build rates. This normally is not the case. Figure P3-3A compares a single-bend assembly to the same assembly which has a second bend added, a 1-1/2 degree bent sub in this case.

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Figure P3-3A Build-up Rate (dog/100 ft*)

Notice that approximately 83% of the build rate is provided by the lower bend. The addition of the bent sub enhances build rate by only 18%. This result is typical of virtually all double-bend configurations. The smaller diameter, more limber motors with a single-bend configuration are capable of even higher' build rates than those shown in Figure P3-3A. So why bother with the second bend? In addition to slightly enhancing build rate, the bent sub serves several other useful purposes: * It helps to orient the top of the motor against the low side of the hole at kickoff which maximizes the bit high-side force. * It decreases the weight sensitivity of the assembly, probably because the relatively limber motor is now packedoff between two stabilization points (i.e., the bent sub and bent motor housing). * It reduces the hole enlargement sensitivity of the assembly. Figure P3-4A shows the change in build rate as a function of hole enlargement for three separate assemblies.

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Figure P3-4A Build-up vs Hole Enlargement

The relatively large bit offset produced by a bent sub/motor combination helps to maintain a constant lateral bit force when hole enlargement occurs. The result is a more uniform rate of build as hole diameter increases. The lateral force exerted on the bit by a single-bend stabilized assembly changes rapidly with hole enlargement. As might be expected, the end result is often a less consistent build rate. Combining a bent housing motor and a bent sub provides an assembly that not only is less susceptible to hole enlargement (the bent sub effect), but one that can achieve medium-radius build rates (the bent-housing effect).

4. Medium-Radius Well Plan When designing BHAs for medium-radius applications, much more emphasis must be placed on achieving predictable and uniform build rates. This is simply because the medium-radius assembly does not have the intrinsic safety margin of the long-radius steerable system. A properly designed medium-radius assembly essentially has one build rate only. It may increase slightly with more weight-on-bit or with increased hole angle, or it may decrease somewhat with higher flow rate and accompanying hole enlargement. None of which, however, provides the operator with much flexibility to alter build rate without tripping. For this reason, medium-radius wells usually incorporate a tangent section into the well plan to help compensate for build rate unpredictabilities. Figure P3-5A shows such a profile. This tangent interval provides a vertical depth safety margin which is calculated with the formula: Cos (tangent section angle) x (length of tangent section). Certainly anyone drilling the first medium-radius well in a given location should seriously consider incorporating a tangent section into the well plan in order to obtain as much of a safety margin as possible. In areas where geology is unpredictable, well profiles with tangent sections will be necessary. However, when planning an extended medium-radius drilling program in a field with predictable formation characteristics, much can be gained by eliminating this section. Inclusion of a tangent section not only may require two additional bit trips, it produces unnecessary stresses on the motor and other downhole components as the well is kicked-off for a second time at the end of the section. The ability to accurately predict the trajectory of a given BHA can provide considerable cost savings.

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5. Performance Predictions It was mentioned earlier that build rate is not the only determinant of tool configuration (i.e., single vs. double bend). It has been shown that in some formations drillability perpendicular to the bedding planes is greater than drillability parallel to the bedding planes. The net effect of this formation anisotropy (crooked-hole tendency) from a trajectory prediction standpoint is that the build rate is influenced by the relative angle between wellbore inclination and formation dip. In moderately crooked-hole country this effect can add or subtract several degrees of build as the well angle builds from vertical to horizontal. It can be a continuous effect if the wellbore inclination is changing consistently across a formation with a constant dip angle or it can be a more instantaneous effect if the dipping planes or formation type changes suddenly: Failure to take such effects into account, particularly when coupled with other factors such as changing hole diameter, can have serious repercussions. These factors, and others, have always influenced wellbore drift and bit walk. In most cases, the long-radius profile is forgiving and allows ample opportunity for corrections should they even be necessary at all. However, such is not the case with medium-radius wells. Figure P3-6A shows output from a typical trajectory prediction program simple enough to be run on a portable computer yet complex enough to provide an accurate prediction of BHA trajectory.

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Figure P3-6A Trajectory Prediction Worksheet

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The following parameters are taken into account: hole size and angle, formation dip, crooked-hole tendency of formation, bend configuration, stiffness of drillstring, mud weight, weight-on-bit and any BHA configuration. The solution, expressed in degrees/100 ft, is in the third column from the right. Notice the significant difference between the three cases illustrated. All three cases are for the same double-bend assembly run with 20,000 pounds weight-on-bit in a moderately crooked-hole formation. Dip angle remains constant for all cases. Cases 1 and 2 represent the effect of hole angle change from 10 to 60 degrees inclination (fifth column from left) and Cases 2 and 3 represent the effect of hole enlargement. Case 3 shows a 15% decrease in build rate with one inch of hole enlargement. Such programs are only as good as the quality of the input data. Nevertheless, with even minimal offset data, the results are surprisingly accurate. For combinations of hole angles and hole size, for 5inch, 19.5 lb/ft steel drill pipe in 15.5 ppg mud.

B. Proper Drill Stem Design (Authors Denny Kerr And Sam Clayton)

1. Introduction It is a reasonably straightforward process to design longradius bottomhole assemblies (BHAs) that can guide the drill bit to horizontal and maintain hole angle for several thousand feet. It is an equally direct process to design a BHA that will guide the drill bit to horizontal at very high rates of build (20 deg/100 ft or greater). These extended horizontal sections and high build rates, however, tend to produce significantly higher torque and drag loads on the drill stem. A competent drill design that can safety handle the increased axial and torsional loading is as significant a problem as the design of the BHA itself. The following factors must be addressed when designing the drill stem for a horizontal well: 1) High build rates and long horizontal sections produce pick-up and torsional loads that can quickly exceed the operating limits of standard-grade oilfield tubulars. 2) The need to transmit axial load to the bit in the horizontal section often subjects heavy-weight drill pipe and, in some cases, standard drill pipe to compressive loading. 3) The need for heavier drill stem components in the upper (vertical) section of the wellbore to overcome the axial effects of friction while tripping in the hole and to provide adequate weight-on-bit while drilling. Designing a drill stem to overcome these problems requires the ability to accurately predict the tensile, torsional and compressive loads at any point along the drill stem. This capability will permit the following: 1) Placement of tubular components within a given drill stem such that the components within each section are not subjected to mechanical loading that exceeds their design limitations. 2) Placement of the appropriate components in the compressive portion of the drill stem that can transmit adequate axial load (weight-on-bit) without buckling. 3) Selection of a rig with sufficient capacity to rotate and hoist the drill stem.

2. Weight-on-Bit Drill collars are typically used near the bottom of the drill stem in conventional wells to provide weight-on-bit (WOB) and to ensure that the drill pipe above the collars always remains in tension. Heavy weight drill pipe is used in conventional wells between the drill collars and standard drill pipe to provide additional weight and to further isolate the drill pipe from compressive loading. In horizontal wells, however, placement of the drill collars near the bit cannot increase weight-on-bit. Drill collars in the horizontal section increase torque, drag and the potential for differential sticking.

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For this reason, the only drill collars run in the horizontal section should be the non-magnetic collars required to isolate the survey instruments from magnetic interference. The primary WOB component must be located in the vertical or near-vertical section of the drill stem. Drill collars and / or additional heavy weight drill pipe are "stacked" in the vertical section of the wellbore to provide weight to the bit. The result is that the entire drill stem below this section is subject to compressive loading. This drillstring commonly referred to as a "reverse-tapered" string. Heavy weight drill pipe is typically run from the end of this weight-supplying section through the build portion of the wellbore to the horizontal section. The inability of standard drill pipe to handle axial loading at lower angles has been proved by Dawson and Pasley <1> (Figure P3-1B). Note for Figure P3-1B: For combinations of hole angles and hole size, for 5" 19.5 ppf steel DP in 15.5 ppg mud. Heavy weight drill pipe typically is used through this area of the hole to avoid pipe buckling.

3. Transmitting Adequate WOB Perhaps the most significant design consideration is the selection of drill stem components for the horizontal section that can safely transmit WOB from the upper "stacked" portion of the drill stem through to the horizontal section, while minimizing overall drill stem weight and the resulting higher pick-up loads. For short horizontal sections, heavy weight drill pipe generally is the optimum choice because it is designed for compressive service and is capable of transmitting very high axial loads without buckling. For example, a 5-inch (49 lb/ft) joint of heavy-weight drill pipe in a 8-1/2-inch hole is capable of transmitting in excess of 100,000 pounds of weight to the bit without buckling, provided the hole is at or near horizontal. As the horizontal section is extended, the weight of the heavy-weight drill pipe may become a length limiting factor because the overall drill stem pickup load increases as the horizontal lengthens. At some point, the use of standard grade drill pipe must be considered as a means of minimizing overall pickup load. Dawson and Paslay also have shown that it is indeed practical to run drill pipe in compression in high angle wells. Figure P3-1A indicates that standard 5-inch (19.5 lb/ft) drill pipe can safely transmit in excess of 30,000 pounds weight-to-bit without buckling, provided the wellbore is at or near horizontal. Although there are cases where minimal buckling may be tolerated, in the interest of conservative drill stem design it is assumed here that any buckling condition whatsoever should be avoided.

4. Pick-Up Weights & Torsional Loads The case study illustrates the fact that drill stem pick-up weights and torsional loads in horizontal wells often exceed the mechanical limits of standard-grade oilfield tubulars. Even when this is not the case, these unusually high loads may justify the use of premium grade tubulars to provide safe operating margins based on an operator's individual requirements. Tables P3-1B and Table P3-2B, taken from the API RP7G, show tensile and torsional yield strengths for some of the more commonly used sizes of drill pipe. It should be noted that these tables denote API Class 2 drill pipe which makes some allowance for minimal and uniform pipe wear. It is important to recognize that, given current oilfield economy, many rigs may not have API Class 2, standard tubulars. It is recommended that all drill pipe to be used in horizontal wells be carefully re-inspected.

5. Case Study The following case study illustrates a typical drill stem for a medium-radius well with an extended horizontal section (Figure P3-2B).

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Figure 3-2B Drill String for Drilling at Horizontal

The computer program used is based on a sliding friction model developed by Exxon Production Research. It is simple enough to run on a standard field portable personal computer, yet sufficiently detailed to provide accurate results. Well Data: Kickoff Point:

9,400 ft MD

Hole Diameter:

8.5 inch

Mud Weight:

9.0 lb/gal

Build Rate:

16 degrees/100 ft

Horiz. Section Length:

2,200 ft

Total Horiz. Displ.:

2,558 ft

Total Measured Depth:

12,163 ft

Maximum Required WOB: 30,000 pounds Casing Point:

9-5/8 inch at 9,200 ft MD

Overpull at Bit:

100,000 pounds

The friction coefficients used for this hypothetical well were 0.24 and 0.42 for the cased and open hole sections of the well, respectively. Experience has shown these values to be fairly conservative and as such are very useful for preliminary work. However, designing the drill stem for a specific well requires more accurate friction coefficients. The computer program derives these friction coefficients from offset directional wells. The following outputs are calculated at intervals specified by the user (typically 100 ft breaks): Pick-Up Load Slack-Off Load Rotating Off-Bottom Load Rotating Off-Bottom Torque Drilling Load

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Drilling Torque The computer model predicted the following values for the case study well: Maximum Pick-Up Load (at surface): 448,000 pounds Maximum Drilling Torque:

15,500 ft-pounds

Rotating Off-Bottom Load:

210,500 pounds

Surface Slack-Off Load:

148,000 pounds

The surface slack-off load of 148,000 pounds is the amount of drill stem weight over and above that required to offset the axial friction effects while tripping in the hole, or the weight available to "shove the bit to bottom". Table P3-1B shows that Schedule E drill pipe would be adequate from the standpoint of torsional strength. TABLE P3-1B Torsional Yield Strength - API Class 2

However, Table P3-2B shows that Schedule 135 pipe is necessary because of tensile strength.

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TABLE P3-2B Tensile Yield Strength - API Class 2

Further down the drill stem, as incremental pick-up load decreases, Schedule 95 pipe may be used and drill stem integrity is maintained. Drill collars are stacked in the vertical section to provide weight-on-bit. Heavy-weight drill pipe is used through the build section of the well to transmit weight to the bit and to ensure that buckling does not occur. Figure P3-1B clearly shows that the standard 5 inch (19.5 lb/ft) drill pipe used in the horizontal section is adequate to transmit the required 30,000 pounds weight-on-bit without buckling.

6. Use of Top Drive One obvious advantage of using a drilling rig equipped with a top drive can be observed in the difference between the maximum pick-up load of 448,000 pounds and the rotating off-bottom load of 211,000 pounds The ability to rotate while tripping negates the axial effects of friction which significantly reduces the hoisting requirements of the drilling rig, and allows the operator to use a less expensive grade of drill pipe.

7. Non-Magnetic HW Drill pipe There has been some debate concerning the substitution of non-magnetic, heavy-weight drill pipe for the required 6090 foot of non-mag drill collars. The output from the torque/drag computer model reveals the effects of such a substitution to be insignificant. Unless the potential for differential sticking is severe, the use of expensive, nonstandard equipment is a waste of operator's funds.

8. Aluminum Drill Pipe The use of aluminum drill pipe is another highly discussed issue. Aluminum drill pipe buckles at approximately half the compressive load of its steel counterpart and is generally unacceptable for transmitting adequate weight to the bit. This severely limits its use in the lower section of the drillstring. To offset the fact that aluminum has a yield strength that is approximately 77% that of steel, a joint of standard aluminum pipe must have a 30% larger cross-sectional area to provide tensile strength comparable to Schedule E drill pipe. For our example well, aluminum could not be used for the same reason that Schedule E drill pipe could not be used: inadequate tensile strength.

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In instances where use of aluminum drill pipe is feasible from a tensile strength standpoint, the operator must sacrifice wellbore hydraulics efficiency. Even wells as demanding as the example well can be safety designed and drilled using standard-grade oilfield tubulars.

9. Reference: Dawson, R. and Paslay, P.R., "Drill Pipe Buckling in Inclined Holes", SPE 11167 presented at 1982 Fall Technical Conference and Exhibition, New Orleans, September 26-29.

C. Factors Determining Optimum Well Profiles (Authors Denny Kerr And Don Swain)

1. Introduction There are many factors that come into play when determining the optimum well profile for a specific horizontal well. Determinants of the well profile include: 1) reservoir applications (amount of horizontal extension required); 2) location, thickness and dip of target interval; 3) formation characteristics and casing requirements; 4) formation friction coefficients; 5) degree of geological certainty (or uncertainty); 6) well spacing regulations and requirements; 7) completion methods; 8) weight-on-bit requirements; 9) local availability of equipment; 10) rig capacity; and 11) minimized measured depth. It has been shown that relatively minor changes in the build profiles of extended-reach wells can have a significant impact on their torque/drag values and the corresponding drill stem loads. For wells having target true vertical depths (TVDs) in excess of 10,000 ft and horizontal displacements in excess of 5,000 - 8,000 ft, optimizing the specific build profile can have a tremendous effect on the torque/drag values of the well. However, these wells are not representative of the typical horizontal well being drilled today. Today's typical horizontal well has a target TVD of 10,000 ft or less and a total displacement of less than 5,000 ft. This article will demonstrate that, for the most part, the typical horizontal well can be designed independent of a given build rate, based on practical considerations such as well spacing requirements and minimizing drilling by utilizing locally available equipment.

2. Reservoir Applications The length of horizontal section required generally has less effect on the well profile and build rate than one might think. Horizontal sections of at least 5,000 ft are possible with both long and medium-radius wells. Medium-radius wells with horizontal sections in excess of 3,000 ft have been drilled, and there is no reason from a drill stem design standpoint that the horizontal sections in medium-radius wells cannot be extended to at least 5,000 ft using standard

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tubulars. Both target TVD and displacement from the original wellbore or surface location can have major effects on the basic build profile. Lease line restrictions frequently dictate a high build rate in order to minimize well offset at the reservoir entry point and thereby maximize the horizontal section length. Medium radius wells with their shorter displacement are optimal choices here. Targets with a thickness of 12 ft or less may require placement of a section with a reduced build rate in the lower well. The effect is similar to adding a tangent section at the very bottom of the build. Exactly where this lower build rate starts and how much vertical section it must cover is a function of formation consistency, operational experience and the service company's confidence in their build assembly. Execution of a perfect 16.0 degree/100 ft build from a 60 degree to horizontal in order to "bull's-eye" a 6 ft thick pay zone requires an impossible build rate predictability, simply from a formation inconsistency standpoint. Targeting a medium-radius well into a thin formation is much easier with a flexible steerable assembly. It is the formation dip, of course, that determines the final inclination of the wellbore. Extreme formation inconsistency can make drilling a medium radius well virtually impossible. Severe hole enlargement can limit even the most radical build assemblies to build rates of 5-6 degrees/100 ft. The vertical depth between target TVD and existing intermediate casing may dictate use of a high rate of build. While important for extended-reach wells, high friction coefficients generally have little restrictive effect over the relatively short, high-angle course lengths of the typical horizontal well. The case study presented at the end of this article uses relatively high friction coefficients and shows little or no restrictive effects. Lower build rates produce higher displacements to the target, which can add an element of uncertainty from a geological standpoint. Where formation discontinuities or erratic dipping planes are a problem, a practical solution for a medium-radius well would be to drill a pilot hole as an extension of the tangent. Figure P3-1C shows such a profile. Once the exact location of the target is determined with the pilot hole the well can be plugged back and sidetracked to horizontal. Well spacing regulations and requirements, which vary from well to well and state to state can be complex, and also play an important role in choosing the well profile. It is beyond the scope of this article to discuss completion methods at length but they obviously are a prime consideration when planning the well. The vast majority of horizontal wells drilled to date have either been longradius wells that were completed by essentially conventional means or medium-radius wells that were drilled through competent limestone or dolomite formations and then were completed with slotted liners. Weight-on-bit (WOB) requirements can have a significant impact on long, extended-reach wells, but generally are non-restrictive in typical horizontal wells. High WOB may require running heavy-weight, or at least heavier drill pipe in the horizontal section to avoid buckling. This increases the torque and drag forces throughout the well. Conventional horizontal wells generally do not have a problem with WOB requirements. From a practical standpoint, local availability of equipment and rig capacity are two of the most important design considerations when planning a conventional horizontal well. Typical horizontal wells generally do not require any specialized equipment (i.e., aluminum, wear-knotted, or non-magnetic heavy-weight pipe). As with conventional drilling in a tight market based on low oil prices, making horizontal drilling a widespread practice depends upon strict cost controls. The cost of a horizontal well escalates rapidly when high-priced, special equipment is specified. Experience has shown Smith that 99 % of the horizontal wells drilled to date could have been designed around locally available rigs and tubulars.

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As shown in Figure P3-1C, several of the widely-used, long-radius well profiles result in measured depths that are many hundred feet longer than medium-radius wells that accomplish the same thing. Figure P3-1C depicts three long-radius horizontal well profiles as well as a typical medium-radius profile. Should a long-radius well be chosen for completion reasons, the additional measured depth may be necessary. But it should be noted that medium-radius wells often offer a less expensive option in terms of, both minimized measured depth and lower overall drilling torques, drill stem loads, and the resulting lower repair and maintenance cost on the tubulars. Each profile had 1500 ft horizontal sections at 7,000 ft TVD. Based on an 8-1/2 inch hole diameter and a weighton-bit design limitation of 30,000 pounds, all four profiles carried 800 ft of 5 inch 25.6 lb/ft, drill pipe in the horizontal section and each steerable bottomhole assembly was 140 ft long with 6.25 inch OD. Mud weight was 9.2 pounds/gal. One design restriction was that drill collars would not be carried into the inclined hole sections. As a result, only the medium-radius assembly used drill collars to provide weight-on-bit (Table P3-1C). In the three long-radius wells, WOB was provided exclusively by the heavy-weight drill pipe. While drilling with 30,000 pounds WOB, all four profiles had 15,000 pounds of additional weight available above the neutral point in the form of drill collars or the heavy-weight drill pipe. Table P3-1C and Table P3-2C show pertinent drillstem data and torque/drag values.

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TABLE P3-1C Torque/Drag Values

TABLE P3-2C Drill Stem Data

Notice the lack of difference between the three long-radius profiles. The values of pick-up load, drilling torque, slack-off weight and rotating weight are very nearly the same. The medium-radius well has approximately 60% less drilling torque, almost twice as much available slack-off weight, and the lowest predicted pick-up load of the four profiles. The medium-radius profile also requires less heavy-weight pipe and much less directional work than its long-radius counterparts. It also results in much less displacement to the target interval which may or may not be desirable. In the case of re-entry work, it may also maximize the use of the existing well duc to its lower kickoff point.

3. Pipe Fatigue The three long-radius profiles with their conventional dogleg severities are not subject to fatigue damage as per Fig. 6.1 of the API RP-7G<2>. Assuming a non-corrosive environment, the tensile loads on the drillpipe through the upper portion of the build are lower than those that would be expected to cause fatigue damage. This holds true even in the worst case (rotating off bottom).

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While rotating off bottom however, the drillstring is in tension through a portion of the dog-leg and some fatigue damage could be anticipated. Our experience shows that this has not been a problem to date; however, this may be due to the fact that there simply are not any drillstrings around that have been subjected to any significant number of fatigue cycles in high build rate wells. If in time fatigue failure should prove to be a significant problem, the use of steel drill pipe protectors would almost certainly prove to be a reasonably inexpensive solution <3>.

4. References 1) Maurer Engineering Inc.: "Project to Determine the Limitations of Directional Drilling", Report No. TR88-4, January 4, 1988. 2) American Petroleum Institute: "Recommended Practice for drill Stem Design and Operating Limits (RP-TG)". May 1, 1987. 3) Lubinski, A., and William S.: "Usefulness of Steel or Rubber drill Pipe Protectors", SPE Paper 11381 presented at the 1983 IADC/SPE Conference, New Orleans, LA, February 20-23, 1983.

D. Four Factors That Affect Fatigue Damage The first three articles in this series illustrated the feasibility of designing and drilling horizontal wells using standard oilfield tubulars which are readily available and relatively inexpensive. The most conventional hole sizes, i.e., 6-1/8 to 9-7/8 inch horizontal wells can be drilled to measured depths in excess of 15,000 ft to vertical depths in excess of 10,000 ft. and in horizontal sections in excess of 3,000 ft while still using standard grades and weights of tubulars. This is true for both medium-radius and long-radius profiles. As an industry, we can design highly flexible, steerable bottom-hole assemblies that will not produce excessive torque and drag in the horizontal section. We can also design lightweight portions of the drill stem for the horizontal section that are more than capable of transmitting adequate weight to the bit. In doing both of these things, we can reduce the torsional and tensile requirements in the upper portion of the drill stem to the point where standard components can also be used there. The experience of Smith International alone of 35 horizontal wells to date has proven this. At no time during the drilling of any of these 35 wells were drill stem components subjected to stresses outside of their design limitations with one exception. The exception? drill stem fatigue associated with reaming and rotating off-bottom through the extreme doglegs associated with medium-radius wells. To date, however, Smith has not experienced any fatigue failures or identifiable fatigue damage. With this in mind, let us examine the four factors that determine the amount of fatigue damage as they relate to wellbores in general and to horizontal wellbores in particular. These four factors are: 1) Tensile load in the pipe at the dogleg, 2) Severity of the dogleg, 3) Number of rotational cycles experienced in the dogleg, and 4) Mechanical properties of the pipe itself. The tensile load in the pipe at the dogleg, (i.e., at the kickoff point), generally tends to be less than for most standard directional wellbores. the reason for this is that the well is usually built to 90 degree inclination immediately following kick-off. The faster this build takes place, the less distance is available below the kick-off point for suspended members to produce a tensile load while drilling. With medium-radius wells, there is typically no tensile load while drilling.

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It is important to remember that there are collars stacked in the vertical section of the hole above the kick-off point. Everything below these collars is in compression. Tensile load may exist at the kick-off point of the mediumradius well while rotating off bottom and while reaming. Although it is certainly true that this tensile load is associated with extreme doglegs in medium-radius wells, the tensile load can be very great. Medium-radius wells build to horizontal very quickly and have little vertical section distance below this high dogleg in which tensile loads can develop. Long radius wells may have higher tensile loads than their medium-radius counterparts while drilling or while rotating off bottom, but, by definition, these loads are associated with much lower doglegs. In October of 1960, Arthur Lubinski published a significant work which outlined the maximum permissible doglegs in rotary boreholes <2>. A great deal of the practical work done in the paper was based on the fact that the maximum reversed bending stress which will cause no fatigue failure in a joint of drill pipe depends on the average tensile stress to which the pipe is subjected. One of the most useful aspects of the paper was a dogleg severity versus tension curve for 4-1/2 inch Grade E drill pipe. the end result of Lubinski's work can be found in Section 6 of the API Recommended Practice RP7G <1> in the form of dogleg severity versus tension curves for various grades and sizes of drill pipe. The set of curves illustrated in Figure P3-1D was derived from Lubinski's work for Range 2 (30 ft) joints of drill pipe.

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Figure P3-1D1 Dog-Leg Severity vs Tensile Curves, Grade E DP

Figure P3-1D2 Dog-Leg Severity vs Tensile Curves, Grade S-135 DP

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Figure P3-1D3 Dog-Leg Severity vs Tensile Curves, HW-DP

These curves plot the allowable tensile load for drill pipe versus the dogleg experienced by the drill pipe at that point. The equations from which these curves were derived are taken directly from Section 6 of the API RP7G, specifically Equations 6.1 through 6.6. Across the range of dogleg severities shown in these curves, standard Grade E drill pipe is shown to be least resistant to fatigue damage. Schedule 135 drill pipe offers only modest improvements over Grade E drill pipe. However, Hevi-Wate* drill pipe, with its center upset, offers significant improvements over standard drill pipe. The last curve is for the pipe that is commonly referred to as "compressive service drill pipe", (i.e., S-135 drill pipe with three additional upsets in addition to the tool joint upsets). This pipe was originally patented by Arco to eliminate fatigue damage in drill pipe rotating at fairly low doglegs but under high tensile loads. In this application, it is highly effective. Compressive service drill pipe also appeared the following year in an Arco medium-radius drilling methods patent for reducing fatigue in higher doglegs, (i.g., those encountered in medium-radius drilling). The graphs show that this pipe does offer some additional fatigue resistance over standard Hevi-Wate. Consider: A typical medium-radius well with a 20 degree/100 ft build rate and a 200 ft tangent section placed between the upper and lower builds at an average angle of 40 degrees. Assume that this well also has a 1,500 ft horizontal section, a true vertical depth of 7,000 ft, and a kick-off point of 6,561 ft This well would be quite similar to Profile "D" from Part 3 of this series. While on bottom and drilling, this profile would be expected to have a minimum compressive load of 10,300 pounds at the top of the build. In this case the drill pipe in the build section would not be subject to fatigue while drilling. Having the drill stem in compression through the build while drilling is typical of all medium-radius wells. However, while rotating off bottom, we can predict a "worst case" tensile load of approximately 18,700 pounds in that portion of the drill stem rotating in the top of the dogleg. This corresponds to Point "A" on the graph shown in Figure P3D2. (figure not found - HAK) Based on this graph, we could eventually expect fatigue damage with any of these drill stem components.

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Yet, the fact remains that Hevi-Wate and compressive service drill pipe have indeed been rotated in higher doglegs, (e.g., doglegs of greater than 22 degrees/100 ft), and under more tension than that predicted without showing any signs of fatigue damage. This is possibly due to the following reasons: 1) Tensile loading is always small while rotating off bottom in medium-radius wells; thus, it has a very minor effect on reducing the life of the member. 2) Tensile loading in medium-radius wells exists only while rotating off bottom or while reaming. It does not exist while drilling. 3) While reaming, tensile loading is either significantly reduced or drill pipe in this upper portion of the build is actually in compression due to down-drag from the drill stem and stabilizers as well as resistance at the bit. 4) While reaming, no single joint of drill pipe is in the danger zone for any significant amount of time. 5) The tubulars in this section during the build-up portion of the medium-radius well are not subject to rotation; therefore, they cannot experience fatigue damage. 6) The tubulars in this section during the horizontal portion of the wellbore (while the string is constantly rotating) never undergo a significant number of fatigue cycles for two reasons: a) The tensile load quickly drops as the component in question is moved into a higher angle section of wellbore. This moves the component into a region of reduced tension or actually into compression and out of the danger zone quickly. b) Whether reaming or rotating off bottom, the drill stem does not normally turn at a speed greater than 25 to 30 rpm's. The drill stem is rotated only to negate the effect of the bent, steerable motor. Bit rpm comes primarily from the downhole motor. NOTE: This last point makes a strong argument for running steerable motors in the horizontal section versus rotary drilling to avoid drill pipe fatigue. As medium-radius drilling becomes more popular, drilling contractors and operators alike should be aware of the potential for fatigue damage to their drill stem as a result of medium-radius drilling. For the reasons given above, it is unlikely that it will become a serious problem, but it always pays to be vigilant. Let's examine the bottomhole assemblies used in three individual cases. In the first example, the horizontal section was thin and extended. In the second example, the horizontal section followed erratically dipping pay zones in an area of geologic uncertainty.

References: 1) "Recommended Practice for drill Stem Design and Operating Limits (RP7G)", American Petroleum Institute, April 1, 1989. 2) Arthur Lubinski, "Maximum Permissible Dog-Legs in Rotary Boreholes", Transactions of AIME, 222 (1961), 251-270. 3) H.M. Rollings, "Drill Pipe Fatigue Failure", Oil & Gas Journal, April 18, 1986.

E. Directional Control In The Horizontal Section 1. Introduction A significant percentage of horizontal projects around the world are drilled through pay zones that are less than 12 ft thick.

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The degree of economic success of such wells may be directly proportional to the amount of time that the operator is able to stay in the pay zone. Modem steerable PDM's make this kind of precise control possible. At times, a well plan demands a tremendous amount of flexibility and adaptability from the bottom hole assembly. For example: 1) When one well intersects multiple pay zones, e.g., where the assembly is required to build or to drop to reenter a zone after crossing a fault; 2) When pay zones which dip erratically must be followed; or 3) When the ability to adapt to unexpected changes in lithology is important. In each of these three cases, the degree of flexibility and adaptability that the bottomhole assembly provides is critical. However, there are also horizontal applications where the pay zone is particularly thick or where long extensions are not required. In these cases, it may be preferable to drill the horizontal section with standard rotary assemblies. In the third example, the horizontal section was drilled with a standard rotary assembly.

2. Case 1: An Extended Thin Horizontal Section The 1,270 ft horizontal section was drilled off the coast of Western Australia in a fine-to-medium grain sandstone reservoir. The target was a rectangle 6.56 ft high and 32.8 It. wide. Extremely fine control was required in this 25 ft thick oil zone to maintain optimal distance from the gas-oil and the oil-water contacts. Figure P3-1E illustrates the end section of the target relative to the reservoir. Figure P3-1E End Section of Target

Figure P3-2E is a vertical section plot of the actual wellbore.

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Figure P3-2E Vertical Section Plot

The true vertical depth of the target center is 4,040 ft, the hole diameter is 8-1/2 inch When designing a steerable assembly for such an application, take great care to design the assembly so that it will remain as neutral as possible while rotating. The ability to rotate the assembly a majority of the time results in constant hole agitation which maximizes the removal of cuttings. If the assembly is not perfectly neutral (and, in fact, it never is), then the next best thing is for it to exhibit a slight drop tendency. Experience has shown that it is somewhat easier to orient the steerable PDM toolface-up and then correct up to the planned course than it is to roll the steerable PDM upside down to correct. Even with an optimal assembly, the Directional Supervisor must make minor corrections on a continuing basis to maintain the necessary control. An MWD tool is, or course, essential in a situation of this type to provide continuous toolface updates as well as frequent surveys. Drilling records show that for the 1,270 ft horizontal section, the steerable assembly (see Table 1) was rotated 85% of the time and was in the toolface mode 15% of the time.

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Figure P3-3E What the Records Show

TABLE P3-1E BHA Used in Horizontal Extension

TABLE P3-2E Steerable BHA Used

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TABLE P3-3E Rotating BHA Builds from 85 to 93.5 degrees

This was accomplished by sliding 14 ft for every stand of drill pipe. Because the assembly exhibited a slight build tendency, the oriented corrections were accomplished by rolling the steerable PDM upside down and correcting it down to the proposed well path. From a practical standpoint, the ability to maintain the bit within a thin horizontal section is limited primarily by the distance of the inclination measurement from the bit. The closer the inclinometers in the MWD tool are to the bit, the less lag time there is from the time the Directional Driller makes a course correction to the time he is able to evaluate the results of the correction. Since maintaining the wellbore within such a thin section is nothing more than a series of short corrections interspersed between rotating time, the need to minimize this lag time is obvious. Existing PDM and MWD tool configurations will normally result in the inclinometers being 40+ ft behind the bit. This is a limitation when controlling a wellbore through a thin horizontal section.

3. Case 2: Following Erratically Dipping Pay Zones and/or Reacting to Geologic Uncertainty The 1,401 ft horizontal section was drilled in the Central United States in a fractured carbonate formation. The horizontal well was sidetracked from a vertical pilot well. Dipmeter log results indicated erratic dipping planes and directions through the intervals above the pay zone. The pay zone itself was 35-45 ft thick at a true vertical depth in excess of 9,800 ft A medium-radius well was chosen, in part, to minimize the offset distance from the pilot well to reduce the risks of geologic uncertainty. An MWD tool with a real time focused gamma-ray was run to provide correlation with the pilot well and to assist in controlling the horizontal section. The horizontal section (see Figure P3-1E) was a series of drops, followed by builds back to horizontal, followed by drops. The steerable assembly followed a pay zone that was dipping down and away from the pilot well in a somewhat unpredictable manner. The bottomhole assembly used to drill this 8-3/4 inch hole is shown in Table P3-2E. While an adequate amount of pay zone was intersected, the task was made more difficult by the distance of the focused gamma-ray tool from the bit. Even when the ROP indicated that the bit had exited the pay zone, the focused gamma-ray was too far from the bit to assist in decision making. This was especially true when the change in dip was abrupt.

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The question then became: Did we drill out the top of the formation or the bottom? Precious distance is lost as the focused gamma-ray tool must now drill ahead 40-60 ft to determine whether the assembly exited the top or the bottom of the formation. Steerable PDM assemblies do make drilling such wells economical, but this situation would have been greatly improved if the bit-to-sensor distance could have been shortened considerably.

4. Case 3: Horizontal Section Drilled with Standard Rotary Assembly The 286 ft horizontal section was drilled on Alaska's North Slope with a standard rotary assembly. The relatively thick pay zones in the area do not require 57 ft directional control. Similarly, favorable reservoir porosity and permeability do not dictate lengthy horizontal sections. The primary concerns here were twofold. First, coning problems had to be reduced; and second, the recovery rates had to be increased by extending contact with the pay zone. The true vertical depth of this 8-1/2 inch wellbore was 8,700 ft. The horizontal displacement of the horizontal section was in excess of 6,800 ft. The horizontal displacement of the horizontal section was in excess of 6,800 ft. The final build from 65 degrees inclination to horizontal was made with a rotary assembly (no steerable PDM). The bottomhole assembly used here (see Table P3-3E) produced a smooth build to 93.5 degrees inclination. A portion of the actual survey results are shown in Table P3-4E. TABLE P3-4E Partial Results of a Survey

Note: the well has no true horizontal section. The assembly builds right through horizontal to a maximum inclination of 93.5 degrees (and even greater in some cases). This particular method was popularized by British Petroleum and Arco Alaska, Inc. and is routinely used today. Any formation that is thicker than 40 ft or that docs not require a lengthy horizontal extension to be economically feasible is a potential candidate for drilling with a rotary assembly. Consider the following "rules of thumb" when switching from drilling with a steerable PDM to drilling with a basic rotary assembly: 1. The potential for casing wear will increase because of the higher RPM of the rotary assembly. Remember: Steerable PDM's do not rotate in the sliding mode; nor generally faster than 25-35 RPM at the surface while rotary drilling.

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2. The increased number of rotary cycles increases the potential for drill stem fatigue in some medium-radius wells. 3. The rate of penetration in many fixed-head bit applications will increase significantly when a PDM is used as a result of the higher bit RPM provided by the motor. This is frequently enough to offset the additional cost of the motor.

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Table of Contents - Chapter R Hydraulics Preface ............................................................................................................................................... R-3 R-1 Introduction to the Bit Hydraulics Problem ......................................................................................... R-4 Determine Maximum Operating Pressure and Volumetric Discharge ..................................................... R-4 Tables R-1 Mud Circulation Equipment - Pump Data ........................................................................ R-13 R-2A Circulation Rates for Duplex Pumps ........................................................................................ R-21 R-2B Circulation Rates For Triplex Pumps ........................................................................................ R-31 R-3A Annular Velocity Around Drill Pipe .......................................................................................... R-36 R-3B Annular Velocity Around Drill Collars ...................................................................................... R-45 R-4 Surface Equipment Descriptions ................................................................................................ R-62 R-5 Surface Equipment Pressure Losses ......................................................................................... R-62 R-6 Drill Pipe Bore Pressure Losses ................................................................................................. R-65 R-7 Drill Pipe Annular Pressure Losses ............................................................................................. R-73 R-8 Drill Collar Pressure Losses ....................................................................................................... R-84 R-9 Drill Collar Annular Pressure Losses .......................................................................................... R-89 R-10 Selection Of Jet Nozzle Size .................................................................................................. R-104 R-11 Calculation Of Jet Velocity ..................................................................................................... R-114 R-12 Discharge Area Of Jet Nozzles .............................................................................................. R-124 R-13-1. Equations Used in Hydraulic Calculations ........................................................................... R-125 A. Bit Selection Equations ............................................................................................................... R-126 D. Drilling Fluid Property Equations ................................................................................................ R-133 R-13-8 Nomenclature for Equations - Smith Int. ............................................................................. R-134 R-13-9 Nomenclature and Terminology .......................................................................................... R-137 R-13-10. Pipe Flow Equations ....................................................................................................... R-138 R-13-11. Annular Flow Equations ................................................................................................... R-138 R-13-12. Bit Hydraulic Calculations ................................................................................................ R-139 R-13-13. Chip Rate Calculations .................................................................................................... R-140 R-13-14. Completed Work Sheet ................................................................................................... R-141 R-13-15. Blank Work Sheet ........................................................................................................... R-142

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Chapter R Hydraulics The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study. This chapter was updated under the direction of Mr. Bruce Harwell of DI Industries Inc. The following text has been provided by the Security Division of Dresser Industries and Smith International.

Preface The purpose of this section is to provide a straightforward, step-by-step procedure to design a hydraulics program that will enable the operator and/or contractor to achieve maximum penetration rates with the equipment available. Please note that this section is set up on a step-by-step basis. An example problem is worked for you in a continuous manner. A worksheet for the program is located at the end of the section, as well as a sample worksheet that has been filled out with the information from the example problem.

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R-1 Introduction to the Bit Hydraulics Problem Determine Maximum Operating Pressure and Volumetric Discharge STEP 1 Table R1 contains the pressure ratings (in psi) and volumetric discharge (in gallons per stroke) for various models of pumps using different liner sizes. The data comes from literature published by the manufacturers. Pressure ratings are based on 100% volumetric efficiency of the pumps. Instances will occur when the rig equipment will dictate a lower pressure limit than the maximum pressure derived from Table R1. When this situation exists, the lower value is the maximum operating pressure to be used in the calculations. EXAMPLE WORKSHEET INSTRUCTIONS STEP 1. PUMP DISCHARGE PRESSURE (psi); PUMP DISCHARGE VOLUME (gal/stroke) SEE Table R1 Mud Circulation Equipment - Pump Data The pump is an Ideco MM-1000 GB (duplex) with a 6" liner. Using Table R1-7, it is found that an Ideco MM-1000 GB with a 6" liner has a maximum discharge pressure rating of 3280 psi and a discharge volume of 6.8 gals/stroke. Since the 2500 psi rig operating pressure given in the example is well below the maximum rating, the 2500 psi will become the maximum operating pressure. VOLUMETRIC DISCHARGE--Duplex Pumps V = c[p(2RL2 - RR2) x L] Example: Stroke Length = L = 14 inch; Rod Size = 2" rad.; RR = 1 inch; Liner Size = 6" rad.; RL = 3 inch V = Volume of Liner, Gallons;

p = pi = 3.141592654

RL = Radius of liner, inch;

RR = Radius of rod, inch

L = Stroke Length, inch

C = constant = 0.004329

V = c[p(2RL2 - RR2) x L]

= 0.004329[p{2(3)(3) - (1)(1)}] x 14

= 0.004329[3.1416(18 - 1) x 14] = 0.004329[3.1416 x 6 x 14] = 0.004329 x 747.699 = 3.24 gal/st/liner The duplex pump has two liners so V = 6.48 gal/st @ 100% eff. VOLUMETRIC DISCHARGE -- Triplex Pumps V=[(p x R2 x L) x C] x 3 Example: Stroke Length = 11 inch; Liner Size = 6 inch Radius = 0.5 Liner Size = 3 inch V = Volume (gal/stroke); p = pi, 3.141592654 R = Radius of liner, inch; L = Stroke Length, inch

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C = Conversion Constant, 0.004329 V = 3 x 0.004329[3.1416(3)(3) x 11] = V= 0.012987[3.1416 (99)] = 4.04 gal / Stroke @ 100 % eff. Record the values 2500 and 6.8 on appropriate spaces, line 1 of the work sheet. See R13-14. Completed Work Sheet. Now, proceed to Step 2 - Circulation Rate

Step 2 - Circulation Rate Table 1 is output data at 100% volumetric efficiency expressed in gallons per stroke, g/s See Table R-1 Mud Circulation Equipment - Pump Data Circulation rate, Q, = E x S x O where: E = 1.0 for triplex pumps, or E = 0.90 for duplex pumps. S = pump strokes per minute for the pump. S, maximum, is limited by the lesser of: 1. maximum rate from manufacturer's data, or 2. maximum set by contractor, based on pump wear data, or 3. maximum set by operator, based on hole erosion or other. O is the gal/stroke from manufacturer's data, table 1. In our example, the Ideco duplex pump, the MM-1000 has a output of 6.8 g/s. It will be operated at 49 spm. So output = 0.9 x 6.8 x 49 = 300 gpm. Enter "300" gpm on line 2 of the hydraulic worksheet See R13-14. Completed Work Sheet Now, proceed to Step 3a - Annular Velocity Around Drill Pipe

Step 3a - Annular Velocity Around Drill Pipe The annular velocity depends on the circulation rate, hole or casing size, and size of drill pipe in use. Using the circulation rate obtained from Step 2, and the hole and pipe size, calculate the annular velocity around the drill pipe. This annular velocity should be equal to, or slightly exceed the value established as the minimum annular velocity around the drill pipe. The annular velocity should be at least sufficient to carry the drill cuttings up the hole, around the drill pipe. In our example, the annular velocity around the drill pipe depends on hole size, 8-1/2", drill pipe size, 4-1/2", and flow rate, 300 gpm. Using equation (1) from R13-1. Equ. in Hydraulic Calculations V = 24.5 Q/{(Dh)2 - (Dp)2} = 24.5 x 300 / {(8.5 x 8.5) - (4.5 x 4.5)} = 7350 / {72.25 - 20.25} = 141 ft/min Lookup tables can be obtained from several bit manufacturers that provide answers to the above equation. Record "141" on line 3a) of the work sheet.

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See R13-14. Completed Work Sheet Now, proceed to Step 3b - Annular Velocity Around Drill Collars

Step 3b - Annular Velocity Around Drill Collars The annular velocity depends on the circulation rate, hole or casing size, and size of drill collars in use. Using the circulation rate obtained from Step 2, and the hole and collar size, calculate the annular velocity around the drill collars. The annular velocity around the drill collars should not be so great as to cause excessive hole washout around the drill collars. Hence, the annular velocity around the drill collars is also of concern. In our example, the annular velocity around the drill pipe depends on hole size, 8-1/2", drill pipe size, 6-3/4", and flow rate, 300 gpm. Using equation (1) from R13-1. Equ. in Hydraulic Calculations V = 24.5 Q/{(Dh)2 - (Dp)2} = 24.5 x 300 / {(8.5 x 8.5) - (6.75 x 6.75)} = 7350 / {72.25 - 45.56} = 276 ft/min Lookup tables can be obtained from several bit manufacturers that provide answers to the above equation. Record "276" on line 3b of the work sheet. See R13-14. Completed Work Sheet Now, proceed to Step 4 - Description of the Surface Equipment

Step 4 - Select Surface Equipment Type Table 4 describes four types of surface equipment (standpipe, hose, swivel, and kelly). Select the type of Surface Equipment which best describes the surface equipment. EXAMPLE WORKSHEET INSTRUCTIONS Table 4 - Description Of Surface Equipment Types

The surface equipment for the example problem consists of: 45 ft of 4.0" I.D. standpipe 55 ft of 3.0" I.D. hose 5 ft of 2-1/4" I. D. swivel 40 ft of 3-1/4" I.D. kelly Using Table 4, it is seen that this is the type 3 surface equipment. Record the type "3" on line 4 of the work sheet. See R13-14. Completed Work Sheet

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Now, proceed to Step 5 - Surface Equipment Pressure Losses

Step 5 - Surface Equipment Pressure Losses From Step (4), the Surface Equipment Type = 3. From C and Surface Equipment Type, C = 0.22 Using equation (2) from R13-1. Equ. in Hydraulic Calculations DP = Cp (0.01Q)1.86

where 0.15 < C < 1.0;

For comparison, we will assume that the field mud weight is 10.0 ppg, then correct it back later to 9.5 ppg. This is just so that the pressures calculated will agree with the pressure losses as determined from hydraulics tables. This step is NOT required in a real example as long as the formulas provided are followed. These calculations do require that decimal exponents are used. Instructions are provided for those not familiar with this technique. Thus, use C = 0.22; p = 10.0 ppg, and Q = 300 gpm so DP = 0.22 x 10.0 (0.01 x 300)1.86 = 2.2 x (3)1.86 = 2.2 x 7.72 = 17 psi Lookup tables can be obtained from several bit manufacturers that provide answers to the above equation. Record "17" on line 5 of the work sheet. See R13-14. Completed Work Sheet (Move ladder on the right edge of R13-4) Now, proceed to Step 6 - Pressure Loss through Drill Pipe Bore

Step 6 - Pressure Loss through Drill Pipe Bore STEP 6 - Using the circulation rate and the drill pipe size, weight, and type, determine the pressure loss through the drill pipe bore. Using equation (3) from R13-1. Equ. in Hydraulic Calculations 3. Drill Stem Bore Pressure Losses

See Nomenclature (R13-8a, R13-8b, R13-8c)

DP = {0.000061 p L Q1.86 }/ (d4.86) For comparison, we will assume that the field mud weight is 10.0 ppg, then correct it back later to 9.5 ppg. This is just so that the pressures calculated will agree with the pressure losses as determined from hydraulics tables. This step is NOT required in a real example as long as the formulas provided are followed. These calculations do require that decimal exponents are used. Instructions are provided for those not familiar with this technique. Example Worksheet Step 6 Pressure Loss Through The Drill Pipe Bore: The pressure loss through our drill pipe bore depends on the drill pipe size, 4-1/2", drill pipe weight, 16.60 Ib/ft, type tool joint, XH, 300 GPM, and the length, 8000 ft. See ID of drill pipe in V. General Information. Ans. = 3.826" DP = {0.000061 p L Q1.86 }/ (d4.86) = {0.000061 x 10 x 8,000 x 3001.86 }/(3.84.86) = (4.88 x 40,499)-/ (657) = 304 Record "304" as the drill pipe bore pressure loss, line 6 of the work sheet. See R13-14. Completed Work Sheet (Move ladder on the right edge of R13-4)

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Now, proceed to Step 7 - Pressure Loss through Drill Pipe Annulus

Step 7 - Pressure Loss through Drill Pipe Annulus Using the circulation rate, the hole size, and drill pipe size, determine pressure loss in the drill pipe annulus. The pressure loss in the drill pipe annulus is governed by hole size, 8-1/2", drill pipe size, 4-1/2", and 300 GPM. Using equation (5) from R13-1. Equ. in Hydraulic Calculations 5. Annular Pressure Losses (Turb. Flow) See Nomenclature (R13-8a, R13-8b, R13-8c)

DP = {(1.4327 X 10-7) p LV2 }/(Dh - Dp) For comparison, we will assume that the field mud weight is 10.0 ppg, then correct it back later to 9.5 ppg. This is just so that the pressures calculated will agree with the pressure losses as determined from hydraulics tables. This step is NOT required in a real example as long as the formulas provided are followed. These calculations do require that decimal exponents are used. Instructions are provided for those not familiar with this technique. Example Worksheet Step 7 Pressure Loss Through The Drill Pipe - Borehole Annulus: The pressure loss through our drill pipe borehole annulus depends on the drill pipe size, 4-1/2", 300 GPM, 8-1/2" hole size, and length, 8000 ft. DP = {(1.4327 X 10-7) 10 x 8000 x V2 }-/(Dh - Dp) From Step 3a - Annular Velocity Around Drill Pipe, V = 141 ft/min, so DP = {(1.4327 X 10-7) 10 x 8000 x (141 x 141}-/(8.5 - 4.5) = {256}-/(4.0) See R13-14. Completed Work Sheet (Move ladder on the right edge of R13-4) Now, proceed to Step 8 - Pressure Loss through Drill Collar Annulus Record "64" psi as the drill pipe annulus pressure loss, line 7 of the work sheet.

Step 8 - Pressure Loss through Drill Collar Bore STEP 8 - Using the circulation rate and the drill collar size, determine the pressure loss through the drill collar bore. Using equation (3) from R13-1. Equ. in Hydraulic Calculations 3. Drill Stem Bore Pressure Losses

See Nomenclature(R13-8a, R13-8b, R13-8c)

DP = {0.000061 p L Q1.86 }/ (d4.86) For comparison, we will assume that the field mud weight is 10.0 ppg, then correct it back later to 9.5 ppg. This is just so that the pressures calculated will agree with the pressure losses as determined from hydraulics tables. This step is NOT required in a real example as long as the formulas provided are followed. These calculations do require that decimal exponents are used. Instructions are provided for those not familiar with this technique. Example Worksheet Step 8 Pressure Loss Through The Drill Collar Bore: The pressure loss through our drill collar bore depends on the drill collar size, 2-1/4", 300 GPM, and the length, 500 ft. DP = {0.000061 p L Q1.86 }/ (d4.86) = {0.000061 x 10 x 500 x 3001.86 }/(2.254.86) = (0.305 x 40,499) / (51.47) = 235

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Record "235" as the drill pipe bore pressure loss, line 8 of the work sheet. See R13-14. Completed Work Sheet (Move ladder on the right edge of R13-4) Now, proceed to Step 9 - Pressure Loss through Drill Collar Annulus

Step 9 - Pressure Loss through Drill Collar Annulus Using the circulation rate, the hole size, and drill collar size, determine pressure loss in the drill collar annulus. The pressure loss in the drill pipe annulus is governed by hole size, 8-1/2", drill pipe size, 4-1/2", and 300 GPM. Using equation (5) from R13-1. Equ. in Hydraulic Calculations 5. Annular Pressure Losses (Turb. Flow) See Nomenclature(R13-8a, R13-8b, R13-8c) DP = {(1.4327 X 10-7) p LV2 }/(Dh - Dp) For comparison, we will assume that the field mud weight is 10.0 ppg, then correct it back later to 9.5 ppg. This is just so that the pressures calculated will agree with the pressure losses as determined from hydraulics tables. This step is NOT required in a real example as long as the formulas provided are followed. These calculations do require that decimal exponents are used. Instructions are provided for those not familiar with this technique. Example Worksheet Step 9 Pressure Loss Through The Drill Collar - Borehole Annulus: The pressure loss through our drill pipe bore depends on the drill collar size, 6-3/4", 300 GPM, 8-1/2" hole size, and length, 500 ft. DP = {(1.4327 X 10-7) 10 x 500 x V2 }/(Dh - Dp) From Step 3b - Annular Velocity Around Drill Collars V = 276 ft/min, so DP = {(1.4327 X 10-7) 500 x (276 x 276)}/(8.5 - 6.75) = {52.5}/(1.75) = 30 See R13-14. Completed Work Sheet (Move ladder on the right edge of R13-4) Now, proceed to Step 10 - System Pressure Loss (excluding bit nozzle pressure loss) Record "30" psi as the drill pipe annulus pressure loss, line 9 of the work sheet.

Step 10 - System Pressure Loss (excluding bit nozzle pressure loss) Calculate System Pressure Loss (Excluding Nozzles) STEP 10 - Add values found from tables 5, 6, 7, 8, and 9 to obtain total pressure loss (excluding nozzles). Note: Since all calculations were made based on a 10 ppg mud, a correction must be made when other mud weights are used: So, the Actual System Pressure Loss = Pressure Loss x (actual mud weight/10) STEP 10 - SYSTEM PRESSURE LOSSES (EXCLUDING NOZZLES) The system pressure loss (excluding nozzles) is the sum of lines 5 through 9: See R13-14. Completed Work Sheet (Move ladder on the right edge of R13-4) So, 17 + 304 + 64 + 235 + 30 = 650 psi Since all calculations made so far were based on 10 ppg mud, a correction must be made for the 9.5 ppg mud used in the example.

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System losses = 650 x (9.5/10) = 618 psi (Note: if the actual mud were always used then this step would not be necessary) See R13-14. Completed Work Sheet (Move ladder on the right edge of R13-4) Record "618" psi on line 10 of the work sheet. Now, proceed to Step 11 - Determine Pressure available for Bit Nozzles

Step 11 - Determine Pressure available for Bit Nozzles Calculate Pressure Available For Nozzle Selection STEP 11 -The pressure available for nozzle selection is the difference between the operating pressure limit and the actual system pressure loss, corrected to a 10 ppg mud. From R13-14. Completed Work Sheet, line (1) allows that the system pressure can be as high as 2500 psi. Subtracting the system loss of 618 psi would allow 1882 psi to be consumed by the bit nozzles. While the worksheet shows this pressure should be corrected to 10 ppg so the 10 ppg tables can be used. The corrected pressure would then be 1882 x (10/9.5) = 1981 psi. See R13-14. Completed Work Sheet (Move ladder on the right edge of R13-4) Record "1981" psi on line 11 of the work sheet. Now, proceed to Step 12 - Determine Bit Nozzle Sizes

Step 12 - Determine the Bit Nozzle Sizes Lookup tables are available for relating flow rate to nozzle size for a 10 ppg mud. However, we will use equation (4) from R13-1. See R13-1. Equ. in Hydraulic Calculations (4) Jet Nozzle Pressure Losses

See Nomenclature(R13-8a, R13-8b, R13-8c)

DP = p Q2 / {10858 (An)2} Rearrange equation (4) to solve for An. And Q = 300 gpm. (An)2 = p Q2 / {10858 DP} = 9.5 x (300 x 300) / {10858 x 1881} = 855,000 / 20,423,898 = 0.04186 So, An = 0.2046. This is the area for ALL nozzles. From Table R-12, the optimum nozzle would be greater than 9/32" but less than 10/32" Table R-12 Discharge Area of nozzles, sq ins Assume three equal nozzles, then An = 0.0682 sq ins for each nozzle. Select from:

9 + 9 + 9 = 0.1864 9 + 9 + 10 = 0.201 9 + 10 + 10 = 0.2155

We see that the optimum selection is between the 9, 9, 10 combination and the 9, 10, 10 combination.

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This jet nozzle selection should yield optimum energy expenditure at the bit for the given circulation rate and pressure limit. The latter would allow greater flexibility (with depth) so record "9, 10, 10" on line 12 of the work sheet. See R13-14. Completed Work Sheet (Move ladder on the right edge of R13-4) Now, proceed to Step 13, Actual Bit Pressure Loss

Step 13, Actual Bit Pressure Loss Given 300 gpm, 9.5 ppg mud, and 9,10,10 nozzles, use equation (4) of R13-1, and Table R-12 So, An = 9 + 10 + 10 == 0.0621 + 2 x 0.0767 = 0.2155 See R13-1. Equ. in Hydraulic Calculations (4) Jet Nozzle Pressure Losses

See Nomenclature(R13-8a, R13-8b, R13-8c)

DP = p Q2 / {10858 (An)2} = 9.5 x (300 x 300) / {10858 (0.2155 x 0.2155)} = 855,000 / (504.25) = 1695 psi. Record "1695" psi on line 13 of the work sheet. See R13-14. Completed Work Sheet (Move ladder on the right edge of R13-4) Now, proceed to Step 14, Bit Nozzle Velocity

Step 14, Bit Nozzle Velocity Step 14 - Determine the Bit Nozzle Velocity from equation (6) of R-13 See R13-1. Equ. in Hydraulic Calculations. Q = 300 gpm, An = 0.2155 from Step 13 6. Jet Velocity

See Nomenclature(R13-8a, R13-8b, R13-8c)

Vn = {0.32086 Q }/(An) = (0.32086 x 300)/(0.2155) = 445.7 ft/sec Record "445" psi on line 14 of the work sheet. See R13-14. Completed Work Sheet (Move ladder on the right edge of R13-4) Now, proceed to Step 15 - Total Circulating Pressure

Step 15 - Total Circulating Pressure See R13-14. Completed Work Sheet (Move ladder on the right edge of R13-4) Step 15 - the Total Circulating Pressure = line 10 + line 14 = 618 + 1695 = 2313 psi Record "2313" psi on line 15 of the work sheet. See R13-14. Completed Work Sheet (Move ladder on the right edge of R13-4) Now, proceed to Step 16 - Bit Hydraulic Horsepower

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Step 16 - Bit Hydraulic Horsepower Step 16 - Bit Hydraulic Horsepower. Use Equation (8) of R13-1. See R13-1. Equ. in Hydraulic Calculations. See R13-14. Completed Work Sheet (Move ladder on the right edge of R13-4) Use P = 1695 psi from line 13, and Q = 300 from line 2. 8. Hydraulic Horsepower

See Nomenclature(R13-8a, R13-8b, R13-8c)

HHp = PQ/(1714) = 1695 x 300 / 1714 = 297 HHP. Record "297" psi on line 16 of the work sheet. See R13-14. Completed Work Sheet (Move ladder on the right edge of R13-4) Now, proceed to Step 17 - Percent of Bit Hydraulic Horsepower at Bit, compared to Surface

Step 17 - Percent of Bit Hydraulic Horsepower at Bit See R13-14. Completed Work Sheet (Move ladder on the right edge of R13-4) Use Pb = 1695 psi from line 13, and Ps = 2313 from line 15. % Bit Pressure = .01 x (Pb/Ps) = 0.01 x (1695/2313) = 73.3 % Record "73.3" % on line 17 of the work sheet. See R13-14. Completed Work Sheet (Move ladder on the right edge of R13-4) Now, proceed to Step 18 - Area of Bottom Hole

Step 18 - Area of Bottom Hole Area of the bottom hole = (p/4) D2 sq ins = (3.14/4) x (8.5 x 8.5) = 56.745 sq ins Record "56.745" sq ins on line 18 of the work sheet. See R13-14. Completed Work Sheet (Move ladder on the right edge of R13-4) Now, proceed to Step 19 - HHP/sq in

Step 19 - HHP/sq in HHP/sq in = Line 16 / Line 18 = 297/ 56.745 = 5.2 Record "5.2" HHP/sq in on line 19 of the work sheet. See R13-14. Completed Work Sheet (Move ladder on the right edge of R13-4) The work sheet is now complete!

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Tables R-1 Mud Circulation Equipment - Pump Data R1-2 - Alfred Wirth - Duplex

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R1-11a - Alfred Wirth - Triplex

R1-11b - Continental Emsco - Triplex

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R1-12c - National Supply - Triplex

R-2A Circulation Rates for Duplex Pumps

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R-2B Circulation Rates For Triplex Pumps

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R-3A Annular Velocity Around Drill Pipe

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R-3B Annular Velocity Around Drill Collars

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R-4 Surface Equipment Descriptions

R-5 Surface Equipment Pressure Losses

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R-7 Drill Pipe Annular Pressure Losses

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R-8 Drill Collar Pressure Losses

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R-9 Drill Collar Annular Pressure Losses

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R-10 Selection Of Jet Nozzle Size

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R-11 Calculation Of Jet Velocity

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R-12 Discharge Area Of Jet Nozzles

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R-13-1. Equations Used in Hydraulic Calculations 1. Annular Velocity

See Nomenclature

2. Surface Equipment Pressure Losses

where 0.15 < C < 1.0;

See Nomenclature

See C and Surface Equipment Type

3. Drill Stem Bore Pressure Losses

See Nomenclature

4. Jet Nozzle Pressure Losses

See Nomenclature

5. Annular Pressure Losses (Turb. Flow) See Nomenclature

6. Jet Velocity

See Nomenclature

7. Jet Impact Force

See Nomenclature

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8. Hydraulic Horsepower

See Nomenclature

A. Bit Selection Equations A1. Cost per foot

13-8 Nomenclature for Equations

A2. Breakeven time, at constant rate of penetration.

B. Bit Weight-Rotational Speed Equations B3. Drilling rate (soft formation)

13-8 Nomenclature for Equations

B4. Drilling rate (hard formation)

B5. Bit size versus penetration rate a. Up to 17-1/2":

b. 17-1/2" to 36":

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B6. Bearing Wear Constant

7. Tooth Wear Constant

8. Mechanical Horsepower at Bit

9. Bit Weight-rpm Relationship to Bit Pressure Drop 9a. From Fullerton, for (Wb x R) < 250

9b. for 250 < (Wb x R) < 350

9c. for (Wb x R) > 350

13-8 Nomenclature for Equations

C. Hydraulic Calculation Equations C10. Drill stem bore pressure losses (turbulent flow)

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C10a. From Fanning

C10b. From Security

C10c. From Smith Tool

C11. Bit Hydraulic Horsepower

C12. Jet Nozzle Pressure Loss

C13. Total Nozzle Area

C14. Jet Velocity

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C15.Jet Impact Force

C16. Bottom Hole Pressure

C17. Bottom Hole Circulating Pressure

C18. Annular Pressure Losses C18a. From Hagan-Poiseuille for Newtonian Laminar Flow

C18b. From Beck, Nuss and Dunn for Plastic Laminar Flow

C18c. From Fanning, Turbulant Flow

C18d. From Security, Turbulent Flow

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C18e. From Smith Tool, turbulent flow

C19. Equivalent circulating density

C20. Renolds' number

13-8 Nomenclature for Equations

C20a. Newtonian fluids

C20b. Plastic fluids (to determine "f")

C21. Average annulus flow velocity

C22. Annulus critical velocity

C23. Optimum annular velocity from fullerton 13-8 Nomenclature for Equations

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C24. Optimum flow rate C24a. From Fullerton

C24b. From Fullerton

C25. Rock chip slip velocity C25a. From Stokes, laminar flow, spherical chips

C25b. From Pigott, laminar flow, spherical chips

C25c. From Rittinger, turbulent flow, spherical chips

C25d. From Pigott, turbulent flow, flat chips

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C26 Effective viscosity C26a. Viscosity definition

C26b. Bingham Plastic

C26c. Shear stress, Power law fluids 13-8 Nomenclature for Equations

C26d. Effective viscosity, Power law

C26e. Annular shear rate

C26f. Consistency Index

C26g. Power law index

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27. Total system losses or pump discharge pressure 13-8 Nomenclature for Equations

D. Drilling Fluid Property Equations 28. Effects of plastic viscosity

13-8 Nomenclature for Equations

29. Bentonitic clay effects

30. Effects of water loss

31. Oil content effects (Vol % Oil < 30 %)

32. Total drilling fluid effects (density, viscosity, solids, pressure loss) For depths from 8,000 feet to 12,000 feet

33. From Fullerton, density effects

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R-13-9 Nomenclature and Terminology

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R-13-10. Pipe Flow Equations Average Velocity, ft/min

Critical Velocity, ft/sec

EQN - 6.1

EQN - 6.2

Determine DP using EQNs 6.3 & 6.4. Use lowest value! - HAK Laminar Flow, psi

EQN - 6.3

Turbulent Flow, psi

EQN - 6.4

R-13-11. Annular Flow Equations Average Velocity, ft/min

Critical Velocity, ft/see

EQN - 6.5

EQN - 6.6

Determine DP using EQNs 6.7 & 6.8. Use lowest value! - HAK Laminar Flow, psi

EQN - 6.7

Turbulent Flow, psi

EQN - 6.8

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Note: Calculations based on Bingham Plastic Fluid.

R-13-12. Bit Hydraulic Calculations Area of one Nozzle, sq ins

EQN - 6.9a

Total Area, sq ins

EQN - 6.9b

Nozzle Velocity, ft/sec

Bit Pressure Loss, psi

EQN - 6.10

EQN - 6.11

Hydraulic Horsepower per Square Inch

Impact Force, lbs

EQN - 6.12

EQN - 6.13

Note: Calculations based on Bingham Plastic Fluid.

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R-13-13. Chip Rate Calculations Slip Velocity, ft/min

Chip Rate

EQN - 6.14

EQN - 6.15 ft/min

Note: Calculations based on Bingham Plastic Fluid.

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R-13-14. Completed Work Sheet

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R-13-15. Blank Work Sheet

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Table of Contents - Chapter T Cementing 1. Cementing ............................................................................................................................................ T-4 I. Introduction ..................................................................................................................................... T-4 II. Types Of Cement Used In Oil Wells ............................................................................................... T-4 2. Casing Strings ....................................................................................................................................... T-9 I. Introduction ..................................................................................................................................... T-9 II. Plug Back Cementing ................................................................................................................... T-12 III. Squeeze Cementing ..................................................................................................................... T-15 IV. Horizontal Well Completions ....................................................................................................... T-21 T3. Balancing A Plug .............................................................................................................................. T-22 I. Balancing A Plug ........................................................................................................................... T-22 II. Calculating Fillup .......................................................................................................................... T-24 III. Pumping Large Diameter Surface-string Up The Hole .................................................................. T-24 T-4. Estimating Cement Required For Various Cementing Jobs ................................................................ T-26 Glossary of Cementing/Casing Terms ...................................................................................................... T-27

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Chapter T Cementing The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study. This chapter was updated under the direction of Mr. Mickey Thomas and Mr. Charles George of Halliburton Services Division of the Halliburton Company.

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T1. Cementing I. Introduction In completion of most wells, the contractor, his superintendents or tool pushers have little to say about the easing string design, setting points or the cementing of the casing. However, the past several years have seen an increase in the amount of well drilling done on a complete "turnkey" basis. The techniques and materials used in cementing operations vary from area to area and in some cases, from well to well in the same field. So much has been written on cementing that only the basic techniques and equipment can be noted here.

II. Types Of Cement Used In Oil Wells A. Conditions and Required Properties Cement that is used in oil wells today is subjected to a wide range of conditions. These conditions range from 15oF or lower in arctic wells to deep wells having temperatures in excess of 500oF. The use of single type cementing material to fit these wide variations of temperature and pressure is impractical; therefore, it is necessary that different types of cements be manufactured or that suitable admixtures be developed to meet these variable conditions. The first property of a cement slurry that should be considered is that which is commonly referred to as the pumping time or thickening time. A cementing slurry must remain fluid for a sufficient length of time to allow it to be pumped down the casing and up the annular space behind the pipe. A suitable cement should possess an adequate safety factor in case of unavoidable shut down while pumping the cement slurry. Secondly, the cement, after having been properly placed in the well, must set in a reasonable period of time and should develop sufficient strength to allow continuation of normal drilling operations are resumed will vary with the operator, but a figure of 500 psi compressive strength is generally accepted by the industry as being adequate. According to work by R. F. Farris, the minimum strength required to support pipe on a primary casing cement job is 8 psi tensile strength or approximately 100 psi compressive strength.

B. Astm Types There are two major classification systems for cements. The first cement classification was developed by the American Society for Testing Materials (ASTM) and covered five types of portland cement, primarily for construction usage: Type I for use in general concrete construction when special properties specified for Types II, III, IV and V are not required. Note: Type I is usually referred to as "common" cement. Type II for use in general concrete construction exposed to moderate sulfate action, or when moderate heat of hydration is required. Note: Type II is usually referred to as "high early." Type III for use when high early strength is require. Type III cement is not commonly used in oil wells.

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Type IV for use when low heat of hydration is require. Type IV cement is not commonly used in oil wells. Type V for use when high sulfate resistance is require. Type V cement is not commonly used in oil wells.

C. API Specifications With the advent of drilling of deeper oil wells it became apparent that the ASTM classification for cement would not meet the conditions necessary for the cementing of these deeper wells. This necessitated the formulation of an API (American Petroleum Institute) Specification for Oil-Well Cements. The are classified in API Spec 10 as follows: A well cement which has been manufactured and supplied according to this specification may be mixed and placed in the field using water ratios or additives at the user's discretion. It is not intended that manufacturing compliance with this specification be based on such field conditions. Classes and Grades. Well cement shall be specified in the following Classes (A, B, C, D, E, F, G and H) and Grades (O, MSR and HSR). Class A This product obtained by grinding Portland cement clinker, consisting essentially of hydraulic calcium silicates, usually containing one or more of the forms of calcium sulfate as an interground addition. At the option of the manufacturer, processing additions* may be used in the manufacture of the cement, provided such materials in the amounts used have been shown to meet the requirements of ASTM C 465. This product is intended for use when special properties are not required. Available only in ordinary (O) Grade (similar to ASTM C 150, Type I). Class B The product obtained by grinding Portland cement clinker, consisting essentially of hydraulic calcium silicates, usually containing one or more of the forms of calcium sulfate as an interground addition. At the option of the manufacturer, processing additions* may be used in the manufacture of the cement, provided such materials in the amounts used have been shown to meet the requirements of ASTM C 465. This product is intended for use when conditions require moderate or high sulfate-resistance. Available in both moderate (MSR) and high sulfateresistance (HSR) Grades (similar to ASTM C 150, Type II). Class C The product obtained by grinding Portland cement clinker, consisting essentially of hydraulic calcium silicates, usually containing one or more of the forms of calcium sulfate as in interground addition. At the option of the manufacturer, processing additions* may be used in the manufacture of the cement, provided such materials in the amounts used have been shown to meet the requirements of ASTM C 465. This product is intended for use when conditions require early strength. Available in ordinary (O), moderate sulfate-resistance (MSR) and high sulfateresistant (HSR) Grades (similar to ASTM C 150, Type III). Class D The product obtained by grinding Portland cement clinker, consisting essentially of hydraulic calcium silicates, usually containing one or more of the forms of calcium sulfate as an interground addition. At the option of the manufacturer, processing additions* may be used in the manufacture of the cement, provided such materials in the amounts used have shown to meet the requirements of ASTM C 465. Further, at the option of the manufacturer,

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suitable set modifying agents* may be interground or blended during manufacture. This product is intended for use under conditions of high temperatures and pressures. Available in moderate sulfate-resistant (MSR) and high sulfate-resistant (HSR) Grades. Class E The product obtained by grinding Portland cement clinker, consisting essentially of hydraulic calcium silicates, usually containing one or more of the forms of calcium sulfate as an interground addition. At the option of the manufacturer, processing additions* may be used in the manufacture of the cement, provided such materials in the amounts used have been shown to meet the requirements of ASTM C 465. Further, at the option of the manufacturer, suitable set modifying agents* may be interground or blended during manufacture. This product is intended for use under conditions of high temperatures and high pressures. Available in moderate sulfate-resistance (MSR) and high sulfate-resistant (HRS) Grades. Class F The product obtained by grinding Portland cement clinker, consisting of essentially of hydraulic calcium silicates, usually containing one or more of the forms of calcium sulfate as an interground addition. At the option of the manufacturer, processing additions* may be used in the manufacture of the cement, provided such materials in the amounts used have been shown to meet the requirements of ASTM C 465. Further, at the option of the manufacturer, suitable set-modifying agents* may be interground or blended during manufacture. This product is intended for use under conditions of extremely high temperatures and pressures. Available in moderate sulfate-resistant (MSR) and high sulfate-resistant (MSR) Grades. Class G The product obtained by grinding Portland cement clinker, consisting essentially of hydraulic calcium silicates usually containing one or more of the forms of calcium sulfate as an interground addition. No additions other than calcium sulfate or water, or both, shall be interground or blended with clinker during manufacture of Class G well cement. This product is intended for use as a basic well cement. Available in moderate sulfate-resistant (MSR) and high sulfate-resistant (HRS) Grades. Class H The product obtained by grinding Portland cement clinker, consisting essentially of hydraulic calcium silicates, usually containing one or more of the forms of calcium sulfate as an interground addition. No additions other than calcium sulfate or water, or both, shall be interground or blended with the clinker during manufacture of Class H well cement. This product is intended for use as a basic well cement. Available in moderate sulfate-resistant (MSR) and high sulfate-resistant (HSR) Grades. The placement of any cement composition depends primarily on temperature rather than depth. The API testing schedules for standardization purposes have been developed after many years of study and industry cooperation. This is an average and extrapolative data should be used with caution as it may not meet your well conditions. Instrumentation is available to measure bottom hole circulating temperature very easily in today's field operations before each cement job. These schedules in Table T1-1 represent average temperatures at various depths along the Gulf Coast and may not correspond to temperatures at the same depths in other areas.

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Table T1-1 Basis For API Well-Simulation Test Schedules

Values in parenthesis represent the time for the first sack of cement to reach bottom hole conditions.

D. Testing and Blending In recent years, major advancements have been made in oil well cements, admixtures for cements and equipment for testing cements. The development of the Pan American thickening time tester makes possible the testing of oil well cements under simulated temperature and pressure conditions encountered in actual well operations. See Figure T1-1. Figure T1-1. The Pressure-Temperature Thickening Time Tester

It should be used with samples of actual cement and mixing water where placement conditions are critical. Tests such as these give accurate data as to the thickening time of a cement under prescribed well conditions.

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The cements used in oil wells are usually referred to as portland, high early strength and retarded. However, with the tremendous number of admixtures available, the cementing of an oil well has developed into what may be regarded as a chemical service. Cementing compositions are now being tailormade for specific well conditions. The inauguration of bulk cement blends are then delivered to the well site in specially designed carriers where cementing units complete the job of mixing and pumping the cement into the well.

E. Yield of Cements Due to the ease of making calculations, it is becoming more common to estimate the amount of cement required in terms of cubic .feet of cement in cementing oil wells. Overseas operations often require the quantity of cement reported in cubic meters and the weight of the slurry in specific gravity, instead of pounds per gallon or pounds per cubic foot. This change has been due to the fact that more cement is brought to the job in bulk trucks rather than sacks. Table T1-2 gives the relations of the yield of cement slurry in cubic feet per standard sack and cubic meters per standard sack. Table T1-2 Yield of Cements

Density is expressed in pounds per gallon, pounds per cubic foot and specific gravity.

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T2. Casing Strings I. Introduction A. General Types of Casing and Reasons for Cementing 1. Conductor casing or pipe: set to prevent caving around the mouth of the bore and conduct drilling fluid to a sufficient height while drilling surface hole. 2. Surface casing or pipe: set to protect fresh water zones, to guard against possible cave-in of the near-surface formations and to provide a position for the initial well control devices. 3. Intermediate or protection string: run inside the surface pipe to protect the hole for various reasons. One or more such strings may be set. 4. Oil string: set to isolate and protect the prospective producing formations; to test for production and for purposes of completing the well as a producer. With respect to the above general types of easing, it is only when it is cemented and a strong tight seal is formed between the casing and wall of the hole, does casing do the job for which it is intended.

B. Reasons for Cementing The cementing of oilwells accomplishes the following: 1. Bonds the casing to the formation, thus supporting and strengthening it. 2. Protects the oil producing zones. 3. Seals against contamination to fresh water zones that may be used for domestic supply and protects other possibly useful strata such as coal, potash, and other oil and gas zones not being used. 4. Helps prevent blowouts from high pressure zones behind the casing. 5. Protects the casing from excluded corrosive waters and lowers electrolytic currents. 6. Seals off "lost circulations" zones and other troublesome formations in order to drill ahead. 7. Protects surface pipe and intermediate casing strings while drilling additional hole. Uncemented pipe is severely shock loaded. 8. Prevents the vertical migration of formation fluids between the casing and hole wall. 9. Provides a base for fracturing, squeeze cementing and future workover during the life of the well.

C. Casing Running Equipment and Accessories The surface equipment usually required for running of casing in a well consists of a spinning line, or power tongs, conventional power tongs, special slips, or spiders. The subsurface equipment attached to the casing are centralizers, casing shoe or float shoe and/or float collar, and wall cleaners. The type of each piece of subsurface equipment varies with the requirements peculiar to the well to be cemented, the type and design of the casing string used. The subsurface equipment may be described briefly as: 1. The guide shoe usually used with a float collar in the casing string; it is placed on the bottom joint of casing and has a rounded nose to prevent digging into the side of the hole wall. 2. Float shoes can be divided into two classifications:

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a. Seal type shoe that allows the casing to be floated down -- filling the casing at the top from a hose connected to the standpipe. b. The differential type shoe that allows the drilling fluid to enter the casing at the bottom as it is being lowered but only allows the fluid level in the easing to reach 91% of the fluid level in the annulus. Designed to eliminate or reduce high pressure surges against the formation as casing is lowered. 3. The float collar is usually made up in the easing string about one joint above the casing shoe -- essentially serves the same purpose as the float shoe but for different application of the cement. 4. Centralizers are attached to the casing to center the casing in the bore of the hole thus securing a uniform deposit of cement around the casing. 5. Scratchers or wall cleaners are attached to the casing to remove the mud cake from the hole wall thus assuring a better bond between the wall and the cement. Wall cleaners are generally cable or spring wire devices and are of two types: a. The rotating wall cleaner which removes the mud cake by simply rotating the casing while circulating the drilling fluid. Often preferred because it does not require the movement of the casing once it is set at the desired depth. b. The reciprocating wall cleaner which requires the raising and lowering of the entire casing string i.e.,reciprocation, to remove the mud cake. 6. Cement Baskets attached to casing are commonly used to isolate the troublesome zones or coal, mineral, or potable water strata above the production zones. A packer is set inside the casing opposite the basket on the outside. The casing is perforated at the point and cement is squeezed through the perforations into the basket. As the weight of the cement builds up, the basket is forced against the hole wall to prevent the heavier cement slurry from slipping down in the annulus.

D. Types of Cementing Jobs Most cementing jobs fall under three general classifications: 1. cementing through pipe and casing; 2. cementing through drill pipe; 3. cementing through tubing. 1. Cementing through pipe and casing. a. Conductor pipe cementing job. b. Surface casing cementing job. c. Protection or intermediate string job -- single stage. d. Protection or intermediate string job -- two stage. 1) Placing two batches of cement with continuous cementing operations overlapping; 2) Bell hole job with two stages: a) Gel, water or petroleum base compounds placed through top stage, this string being placed through a very large string casing to allow for shilling of formations; modifications of this same job being used to combat corrosion, then; b) Bottom stage is cemented. e. Protection string job -- three stage.

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f. Production string job -- single stage. g. Production string job -- two stage. h. Production string job -- three stage. i. Split pipe or split easing job. 1) Locating split or leak in casing using plug method and measuring line. 2) Locating split or leak using hook wall packer. j. Liner or short string job. k. Bull head squeeze job. 2. Cementing through drill pipe or tubing. a. Placing cementitious materials for lost circulation problems. b. Open hole plug back job. c. Straight plug back job. d. Bradenhead squeeze job. 3. Cementing through tubing and, in some cases, drill pipe. a. Retainer (drillable) squeeze job. b. Packer (retrievable) squeeze job. c. Scabbing methods 1) Placing cement through perforated liner using straddle took, dump bailer, open ended tubing or drill pipe, down swab assumable, retainer and drillable tailpipe. 2) Drillable sleeve cemented in place. d. Liner or short string squeeze job using bradenhead. e. Liner or short string squeeze job using packer type setting tool. 4. Combination of various jobs and new developments. a. Top outside job, between easing or between casing and hole, using tubing or small diameter pipe. b. Cementing annulus between string through casing head surface connection. c. Combination job. 1) Two sections of casing -- bottom section liner job. 2) Top section single stage job using special Tool to joint two strings together. d. Full hole job (in some areas called combination string), placing cement through tool above a liner which is the same size as the casing. e. Permanent-type completions (PWC). f. Concentric tubing. g. Multiple tubingless completions.

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h. Casing patch. i. Wireline squeeze jobs.

II. Plug Back Cementing A. Reasons for Placing a Cement Plug Figure T2-1: There are several reasons for setting a cement plug

1. ZONE ISOLATION In a well with two or more producing zones, it is sometimes beneficial to abandon a depleted or unprofitable producing zone by placing a permanent cement plug above it, thus helping to prevent possible production loss into, or fluid migration from, the lower interval. 2. LOST CIRCULATION CONTROL During the drilling operation, if mud circulation is lost, it is sometimes possible to restore circulation by spotting a cement plug across the thief zone and drilling back through the plug. Generally, this operation is less expensive than a squeeze cementing job. 3. DIRECTIONAL DRILLING In an operation designed to sidetrack the hole around a non-retrievable fish, such as a broken drill string which has become stuck in the hole, it is necessary to place a cement plug at a specific depth to help support the whipstock for directing the bit into the desired area. Another example of a controlled change in the drilling direction to help reach a specific target area is in shoreline drilling operations for offshore production.

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4. FORMATION TESTING A cement plug is sometimes placed below a zone to be tested which is considerable distance from the bottom, and a straddle packer with a side wall anchor or a bridge plug is not possible or practical. 5. ABANDONMENT To seal off a dry hole or depleted well, a cement plug placed at the required depth, helps prevent zone communication and any migration of fluids that might infiltrate underground fresh water sources or cause undesirable surface conditions.

B. Common Plug Back Techniques 1. THE BALANCE METHOD Using this technique, Figure T2-2, the desired quantity of cement slurry is usually placed in the drill pipe or tubing and displaced from the bottom of the string until the level of cement outside is equal to that inside the string. Figure T2-2: Balance plug method

The pipe or tubing is then pulled slowly from the slurry, leaving the plug in place. See T-3 Balancing a Plug for calculations. ADVANTAGES: This method is simple and requires no special equipment other than a cementing service unit. OTHER CONSIDERATIONS: A) When it is difficult to establish the top of a cement plug, it may be necessary for the well owner to run an excess of cement, then pull the running-in string to the desired plug top and reverse out the excess cement above that point. A loss of fluid to the formation below this point may cause a movement in the plug. B) Contamination of the cement with mud is possible, especially when using small volumes of cement. C) If the drilling mud is of low viscosity it may be necessary to place a viscous pill to keep the cement slurry from falling downhole.

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2. THE DUMP BAILER METHOD This technique is usually employed at shallow depths, but with the availability of new materials it has been used to depths of over 20,000 feet. The dump bailer, containing a measured quantity of cement, is lowered on a wire line. A Limit Plug, Cement Basket, permanent type bridge plug, or gravel pack is usually placed below the desired plugging location. The bailer is dumped and raised to place cement above the plug or basket, Figure T2-3. Figure T2-3: Dump bailer method

Method may include limit plug* (b), or a basket (c). ADVANTAGES: A) Since the tool is run on wire line, depth of plug is easily controlled. B) The cost of a dump bailer is usually low. OTHER CONSIDERATIONS: A) Not as readily adaptable for setting deep plugs. B) Mud Contamination of cement may occur unless the well operator circulates the hole prior to dumping. C) Limited on the quantity of slurry that can be placed per run and initial set must be attained before the next run can me made and the bailer dumped. 3. THE TWO PLUG METHOD This method, Figure T2-4, involves running top and bottom cementing plugs to isolate the cement from the well displacement fluids (similar to standard primary cementing practices).

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Figure T2-4: Two Plug Method

A plug catcher is placed near the bottom end of the drill pipe and lowered to the desired depth. When ready to pump the cement, the bottom plug is placed in the drill pipe followed by the desired amount of slurry. The bottom plug will pass through the plug catcher and out the bottom of the drill pipe. The top plug, retained in a plug container during displacement of cement, is released and pumped into the drill pipe behind the cement. When the top plug reaches the plug catcher it enters the baffle and is locked and sealed in place. This is indicated by a sharp rise in surface pressure. The drill pipe is then picked up until its lower end is at the desired top of the cement. A predetermined pressure is then applied to drill pipe, releasing the baffle in the plug catcher. the baffle and plug are now locked in the lower end of the tool and will remain there throughout the reverse circulation operation. All cement above the end of drill pipe may now be circulated out through the drill pipe. After all excess cement is circulated out, pull the drill pipe and recover the plug catcher and top plug. ADVANTAGES: A) The two plug method minimizes the possibility of overdisplacing the cement; B) tight, hard cement structure; C) top of cement plug is established accurately. OTHER CONSIDERATIONS: Initially more expensive, (but often less than other methods which may involve several attempts to get a good plug) however, this is the preferred method for most accurate placement.

III. Squeeze Cementing A. Definition of a Squeeze Squeeze cementing is the most common type of remedial (secondary) cementing. The process involves applying hydraulic pressure to force or "squeeze" a cement slurry against the pore spaces of a formation, either in open hole or through perforations in the casing or liner.

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B. Applications and Benefits of Squeeze Cementing 1. HIGH GAS/OIL RATIOS Where an oil zone can be isolated from an adjacent gas zone, the gas/oil ratio can usually be improved to help increase oil production. 2. EXCESSIVE WATER Water sands can be squeezed off below the oil sand to help improve water/oil ratios. Independent water zones can usually be squeezed to eliminate water intrusion. 3. CASING LEAK REPAIR A casing leak may be repaired by squeezing cement through the leak. 4. THIEF ZONES Low-pressure zones that engulf oil, gas, or drilling fluids can usually be sealed by squeeze cementing. 5. BLOCK SQUEEZING Greater protection against fluid migration into a producing zone is often possible by perforating below this zone, squeezing these perforations, then repeating the process above the zone, drilling out, and perforating for production. 6. PERMANENT-TYPE COMPLETIONS After casing a well having a multiple producing zone potential, it is common practice in any areas to isolate the first selected zone for production (No. 5 above) and produce the zone to depletion. After squeezing the depleted zone, the remaining zones are, in turn, perforated, produced, depleted, and plugged. 7. DEFECTIVE PRIMARY CEMENTING JOB Channeling or insufficient fill-up of the primary cementing job can usually be overcome by squeeze cementing. 8. ABANDONMENT Squeeze cementing is sometimes employed to seal old perforations or plug a depleted producing zone completed in open hole. This helps prevent fluid migration from the abandoned zone or well.

C. Common Squeeze Cementing Techniques 1. BRADENHEAD SQUEEZE METHOD In this method, Figure T2-5, cement is pumped into the cased hole through tubing (or drill pipe), displacing well fluids into the annulus.

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Figure T2-5: Bradenhead Squeeze Method

After the cement is spotted across the zone to be squeezed (calculated by the amount of fluid displaced) the tubing is pulled above the perforations and the annulus is closed at the surface (casing-head or bradenhead). As pumping of cement continues, the cement must move into another zone because further circulation up the annulus is prohibited by the closed hydraulic system. After the cement is displaced, the slurry remaining in the casing can sometimes be reversed out. Usually, however, drilling-out is required. Since no packer is used, only low pressure squeezes are permitted because of easing limitations. Pinpoint accuracy of spotting the cement across the interval to be squeezed is difficult to obtain since no packers are used. 2. SQUEEZE PACKER METHOD This method, Figure T2-6, is generally considered to be superior to the bradenhead method.

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Figure T2-6: Squeeze Packer Method

The interval to be squeezed is isolated from the surface by a packer run on tubing. Many types of packers are available, each designed for use when specific well conditions are anticipated. Both retrievable and permanent (drillable) packers can be used. It is recommended practice to pressure-test the tubing and casing prior to placing cement. In certain instances it is necessary to isolate the section below the perforations to be squeezed. A drillable or retrievable bridge plug is placed below the perforations for this purpose. The perforations above are then squeezed and the remaining slurry reversed out. ADVANTAGES: A) Permits high squeeze pressures. The squeeze packer isolates the zone to be squeezed. B) Closer control of the entire operation than with the bradenhead method. C) Permits more efficient placement of the slurry by the hesitation squeeze method. D) It is possible to get an effective squeeze job without having to drill out. 3. HESITATION SQUEEZE METHOD In general, modern cements with low fluid loss characteristics and the availability of retrievable packers and bridge plugs have made this the most effective squeeze cementing method. The hesitation method, Figure T2-7, involves the placement of cement in a single stage, but divided the placement into alternate pumping and waiting periods.

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Figure T2-7: Hesitation Squeeze Method

This "hesitation" practice utilizes controlled fluid loss properties of the slurry to build filter cake nodes against the formation and inside perforations while the parent slurry remains in a fluid state in the casing. A cement slurry is not a true fluid because of its content of solid particles (cement) surrounded by a true fluid (water). For this reason cement cannot be pumped into the permeability of a formation. True fluids such as water, oil, acid, plastics, etc., can be pumped into permeability. When cement dehydrates against permeability, the water phase of the slurry is squeezed out and a cement falter cake of solid particles forms on the face of the formation. If excessive pressures are exerted at the surface, the formation will fracture and any cement pumped into the formation will be in these fractures. The basic philosophy of a "low fluid loss squeeze" is never to exceed the fracturing pressure either on the "breakdown" or during the squeeze. Fluid loss in neat cement slurries is usually very rapid, and can cause a buildup of cement in the casing before the slurry can be completely cover all the formation. The result can be a cement plug across the top several perforations -- but not cement across the lower perforations, thus preventing successful completion of the squeeze job. Conversely, controlled fluid loss rates (obtained by using special additives in the slurry) help avoid premature loss of fluid from the slurry in the casing, when the fluid is lost to the formation, the rate is normally much lower than with neat cement, resulting in denser, more pressure resistant cement filter cake. Also, because fluid loss is occurring in the formation while little or no fluid loss activity is taking place in the casing, it is often possible to obtain good cement plug in the formation and across perforations, and still have sufficient time to reverse excess slurry from the casing, thus avoiding (or at least reducing) drilling out time or expense. The benefit of hesitating during the pumping operation is that this action tends to encourage the controlled deposition of cement solids against the formation. The faster this deposition can be obtained, as a general rule, the sooner the squeeze job can be successfully completed. 4. CONTINUOUS PUMPING METHOD In this, as in some types of squeeze cementing methods, a quantity of water (or chemical wash) is pumped in to determine the breakdown pressure of the formation to be squeezed. After breakdown, the slurry may be spotted near the formation and pumped at a low rate. As pumping continues, injection pressures begin to build up until surface pressure indicates a squeeze has occurred.

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Pressure is held momentarily on the formation to verify static conditions and then released to determine if cement will stay in place. The excess slurry above the perforations is then reversed out. 5. STAGE METHOD The stage method is often employed in cases where continuous pumping fails to result in a pressure build-up because of thief zones in the formation. This method involves mixing one batch of cement (30 to 100 sacks), displacing this into the formation, waiting at least until initial set, and repeating the operation as many times as required.

D. Squeeze Cementing Materials The ideal squeeze cement slurry is designed to permit adequate thickening time, yet produce sufficient compressive strength with minimum waiting-on-cement time. Most slurries are designed with neat or retarded cements. In addition, there are a wide variety of special cements and additives to cope with specific well problems.

E. Special Cements 1. Diesel Oil Cement (DOC) A mixture of cement, Diesel oil, and a dispersing surfactant. This slurry is for water control; it has an indefinite pumping time and sets only when contacted by water. 2. Radioactive Cement Formulated with special tracer particles to aid in located squeezed cement sections with tools. 3. Cal Seal (Fast Setting Plaster of Paris) An extremely fast-setting materials. They are often used in lost-circulation control and Low-temperature squeeze cementing. 4. Non-Cementitious Chemical solutions used in water control operations.

F. Additives 1. LOW FLUID LOSS ADDITIVES These additives help prevent rapid fluid loss (dehydration) under high-pressure squeeze conditions. Adding small quantities of certain low fluid loss additives builds up a filter cake which controls filtration rates and retards the slurry so setting of the cement against the formation and perforations can be accomplished, yet sufficient time is allowed to reverse the parent slurry form the casing. Each of the additives in common use have been developed for specific hole and temperature conditions. They can be effective in formations containing shales or bentonitic sands that are sensitive to fresh water. 2. OTHER ADDITIVES Lost Circulation Materials, LCM, are sometimes helpful in partially bridging-off permeable formations in order to permit squeezing the thief zone with a minimum of slurry volume. Retarders help extend cement pumping time at high bottom hole temperatures. Accelerators are often employed in squeezing shallow zones to shorten waiting-oncement time, and to aid in obtaining an initial set of the slurry. There is a complete selection of these and other additives to help improve squeeze cementing results.

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IV. Horizontal Well Completions Oil and gas wells are drilled horizontally for a variety of reason, mostly to improve production with drilling multiple vertical wells and to prevent water or gas coning. Where the productive zone may be thin and of large areal extent, a horizontal well can help provide increased exposure to the production area, rather than drilling multiple vertical wells.

Cementing The more cementing experience you have, the better able to advance the technology required for horizontal completions. Computerized centralizer spacing programs provide optimum easing standoff to insure the casing has a protective cement sheath around it. This is essential for a successful primary cementing operation. In addition, proper centralization enhances the capability for pipe movement which helps clean gelled mud and solids from the wellbore. The stage cementer hydraulics have been used extensively in horizontal well applications for single stage cementing above a slotted liner. It is often utilized where external casing packers are used for zone isolation. The hydraulic operated stage cementers operate without rotation or mechanical manipulation and requires no opening plug to be dropped from the surface, thus saving expensive rig time. The stage cementer can be opened hydraulically by increasing pressure inside the casing to a predetermined level. There is no waiting for the opening plug to reach the cementer, therefore, excess cuttings, mud cake and other debris are kept in constant motion for improved removal. Parameters such as cement free water and solids suspension capability, spacer composition, wetting characteristics, pipe movement and mud properties, have been demonstrated by full scale laboratory testing and field experience to be important in horizontal cementing.

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T3. Balancing A Plug I. Balancing A Plug A. General Considerations When a cement plug is spotted on bottom through tubing or drill pipe, the tubing or drill pipe is run to bottom. The cement is pumped down the tubing or drill pipe and up around it in the annular space between tubing or drill pipe and casing. Usually, the hole will be full of mud and it is general practice to pump a few barrels of water ahead of the cement to displace the mud and wash up ahead of the cement plug. The spacer of water also helps keep the cement from channeling through the mud. The amount of water used for this purpose is generally in the neighborhood of 5 to 10 barrels. After pumping the cement, the tubing is pulled up to just above the needed top of the plug and reverse circulated. When running a plug, the column of fluid in the tubing must balance the column of fluid in the annulus. If the fluid in the tubing is heaviest, then the fluid in the tubing will continue flowing down out of the end of the tubing and up into the annulus after pumping is stopped. If the annulus fluid is heaviest, then flow will be in the opposite direction down the annulus and up the tubing after the pumping is stopped. In any case, the cement is liable to become contaminated with mud during such movement. To avoid these difficulties, an effort is made to balance the column of fluid in the tubing with the column of fluid in the annulus. Since some water is pumped ahead of the cement into the annulus, it is necessary to put some water behind the cement in the tubing in order to keep the columns balanced. Also, displacement by the tubing or drill pipe in the cement slurry will cause the slurry to rise higher than the fillup required until the tubing is pulled out of it. The term, "balancing a plug" refers to simply putting the right amount of water behind to balance that put ahead of the cement and pumping the right amount of mud to balance the two columns of fluid.

B. To Calculate Amount of Water to Follow Cement The easiest way to do this is use Tables in Chapter V. General Information to obtain the volume per linear foot of the annulus and the tubing. Then, after it is decided how much water to pump ahead of the cement, take that volume of water times the ratio of tubing volume per foot over annular volume per foot. For instance, with 2-3/8'' 4.7 lb/ft., EUE tubing in 6-1/2" open hole, it has been decided to run 10 barrels of water ahead of the cement in the annulus. How much water must be run behind the cement to balance the plug? Annular Volume = .0356 bbl/ft OR .1997 cu ft/ft.* Tubing Volume = .0039 bbl/ft OR .0217 cu ft/ft.* *From Chapter V Amount of water with which to follow cement to balance water in annulus: = (0.0039/0.0356) x 10 = 1.09 bbl; If 7 bbl of water were pumped ahead, instead of 10 bbls, then the amount to follow with would be: = (0.0039/0.0356) x 7 = 0.76 bbl or 3/4-bbls

C. Height of Cement The following formula is used to find the height of cement for plug balancing purposes: H = V/(A + CP)

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H = Height of balanced cement column (in ft) V = Volume of cement slurry used (in cu ft) A = Annular volume between tubing or drill pipe and open hole or casing (in cu ft per ft) CP = Capacity of tubing or drill pipe (in cu ft per ft)

D. Amount of Mud Needed to Displace Cement and Water to Bottom The cement fillup has been calculated and the water fillup has been calculated so the amount of mud to use to pump the cement to the proper point will be: [Total length of tubing - (Cement fillup + water fillup)] x bbls capacity per ft of tubing

E. Example 1 Balance 100 sack cement plug in 6-1/2" open hole with 2 3/8" 4.7 lb/ft, EUE tubing at 8000 ft. Run 10 bbl water ahead of plug. Determine: 1) Depth to top of plug if common (Class A) neat cement is used. 2) Amount of water to run behind cement to balance the 10 bbl of water run ahead. 3) Amount of mud to pump to balance plug. 100 sacks neat common cement will yield 100 x 1.18* = 118 cu ft of slurry. Annular Volume = 0.0356 bbls OR 0.1997 cu ft/ft** Tubing Volume = 0.0039 bbls OR 0.0217 cu ft/ft** * Yield in cu ft per sack from Table T1-2 Yield of Cements **From Chapter V Height of Plug = V/(A + Cp) = 117/(0.1997 + 0.0217) = 528 ft Depth of Top of Plug = 8000 - 528 = 7472 ft Amount of water behind plug to balance 10 bbl ahead of cement: = {(Tbj. Vol. per ft)/(Annulus Vol. per ft)} x 10 bbls = (0.0039/0.0356) x 10 = 1.1 bbls Feet of Water in tubing = 1.1/(bbl/ft) = 1.1/0.0039 = 282 ft. Amount of mud needed to pump a balanced plug: = [(8000 ft total depth) - (528 ft of cement + 282 ft of water)] x (.0039 bbls mud per ft) = 28 bbls It is advisable, after balancing the plug as above, to under displace the cement down the tubing by a small amount, say 1/4 to 1/2 bbl, in order that the fluid column in the tubing will be slightly heavier than the fluid column in the annulus due to the added small amount of cement in the tubing. This practice will help the tubing fluid to fall when the tubing is pulled to the top of the plug for reverse circulating. The cement tends to hang in the tubing and sometimes requires a little added weight to move it out of the tubing. The added cement left in the tubing by under displacement will generally give the needed additional weight.

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II. Calculating Fillup It is necessary in all cementing operations, except squeeze work, to have a pretty good idea of the fillup to be obtained from a certain amount of cement in a certain size hole or annular space. These figures are available in cubic foot per barrels per foot in Section VI. Calculation is then worked as follows: First, decide fillup desired (number of feet cement is to come up hole) and get the figure for cubic feet per foot of fillup for that particular hole or annular space. Second, then find the yield per sack in cubic feet for the particular slurry to be used from Section 1. Third, next divided the fillup desired in cubic feet by the slurry yield in cubic feet per sack. This will give the number of sacks of cement needed per 100% fillup to the desired level. It is usually necessary to add to the cement volume calculated as above, because the hole is oversize or uneven or perhaps because cement may be lost into some formations. The amount to be added varies from area to area, but often runs between 10 and 50%.

A. Example 1 It is desired to cement 5-1/2-inch OD casing in 7-3/4-inch open hole to a height of 500 feet. Operator wants to use 50% safety factor because this has been found necessary in this area. The cement to be used is neat Class A cement, with a yield of 1.18 cubic feet per sack. How many sacks of cement are needed to get desired fillup? From Section IV. Estimating Cement Required For Various Cementing Jobs Annular volume between 5-1/2" OD casing and 7-3/4" OH = 0.1626 cubic feet per foot. Total Calculated Volume = 500 ft fillip x 0.1626 cu ft/ft Total Calculated Volume = 81.3 cu ft Sacks needed: Total Calculated Volume = 81.3 cu ft / 1.18 cu ft/sk = 69.5 sacks 50% Safety Factor = 69.5 sacks x 1.5 = 104 sacks.

B. Example 2 It is desired to plug to abandon a 6-3/4" hole (no casing set). Plug to cover bottom 200 feet of hole. Operator wants to use Class A cement with 4% gel and it is common practice in area to allow a 20% safety factor, so he wishes to do that also. Volume of Hole (from Handbook) = .2485 cu ft/ft 200 ft x .2485 = 49.70 cu ft Yield Class A Cement in 4% gel = 1.55 cu ft/sack = (49.70 cu ft/155 cu ft/sack) = 32.1 sacks Total Sacks to be Used = (safety factor = 20%, so) 1.20 x 32.1 sacks = 38.5 sacks

III. Pumping Large Diameter Surface-string Up The Hole Pumping the pipe up the hole may occur when attempting to start (break) circulation is preparation for the cementing job on large diameter surface or conductor strings. The usual cause is the accumulation of cuttings and cavings around the outside of the pipe. If the rig pump is started to fast and the annulus is bridged, the pipe may be raised from the hole. The pipe should be chained down in any case where there is a possibility of pumping it out of the hole. Good hole conditioning just before pulling the drill pipe, and breaking circulation at intermediate points while

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running the casing are two good practices to minimize the likelihood of this problem developing. The formula for calculating the pressure required to pump the pipe up the hole, if the same fluid is in the pipe and the annulus, is as follows: P = (Weight of Pipe/Area of Pipe OD) With cement in the annulus and water in the pipe, the difference in the weights of the two materials will cause a lift on the pipe also. That lift may be calculated as follows: Lift = Pipe L x [(Hd. of cmt/ft) - (Hd. water/ft)] x (Area Pipe ID) Note: some manuals call Hd. of fluid/ft the Fluid Gradient and express it in psi/ft. If such lift exceeds or approaches the pipe weight, then the pipe should be anchored in some manner.

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T-4. Estimating Cement Required For Various Cementing Jobs To estimate the quantity of cement required to set a given string of casing in a give size hole, use the Volume and Height Tables, Chapter V. Example: To determine the amount of cement to set 535 feet of 10.75 inch surface pipe to the top. The surface hole was drilled and reamed to 13.5 inches to 542 feet. From Chapter V it requires 0.3637 cubic feet of cement slurry to fill one foot of the annulus between the casing and the hole wall. Therefore: 535 x 0.3637 = 194.6 cu ft of cement slurry Open Hole: 542 - 535 = 7 ft of 13.5 inch hole From table in Chapter V Capacity of Hole": It requires 0.9940 cu ft of cement slurry for each foot of 13.5 inch hole. Therefore: 7 x 0.9940 = 6.96 cu ft of cement slurry Hence the theoretical total required: (Annulus = 194.6 cu ft) + (Open Hole = 6.9 cu ft) = 201.5 cu ft cement slurry To estimate the number of sacks of cement required, use Table T1-2 Yield of Cements for yield of type of cement to be used. Then: Total Slurry Required (cu ft) = {(No. sxs dry cement)/(Yield(cu ft/sack)} Hence, for Class D or Class E Cement: (201.5/1.08) = 130.0 sack of dry cement Or for Class A + 4% Gel: (201.5/1.55) = 130.0 sack of dry cement Note (1): Most of the older tables for hole and pipe capacity are based on an estimated yield of 1.1 cu ft per sack of dry cement. Note (2): Except where air and gas is used as a drilling fluid, most holes have a tendency to wash out to a larger diameter than bit gauge. It is common practice for cementing casing by 20 to 25% in the Mid - Continent Area and by as much as 50% in the Gulf Coast Areas. Thus a cementing job calculated to require as much as 252 cu ft cement slurry in the Mid - Continent Area or approximately 302 cu ft in the Gulf Coast Area. The above is a rule of thumb to make sure that there is a sufficient cement on the location to do the job. When drilling in a new or "wildcat" area, a safe practice is to run a "Caliper Log," so that the average diameter of the hole can accurately be determined -particularly in the zone to be cemented.

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Glossary of Cementing/Casing Terms A glossary of cementing terms commonly used is included for better understanding of the data presented in this section. This is in addition to the description of API classes in Section T1. ASTM Type Cement -- A portland cement, of which there are several types, meeting requirements of ASTM C 150, Standard Specifications for Portland Cement. Common Cement -- Either API Class A or ASTM Type I cements referred to as "common cement". Construction Cement -- ASTM Type I, II or III and air-entrained modifications. Although API Class A, B, and C conform similarly to these cements, respectively, the air-entrained variations are not suitable for oil well cementing. Gel Cement -- A cement or cement slurry modified with addition of bentonite. High Early Cement -- API Class C or ASTM Type III cement. High Temperature Cement -- A cement designed to overcome strength retrogression. Hydraulic Cement -- Cement that hardens underwater. Modified Cement -- A cement whose properties are altered through the use of additives, Neat Cement -- Cement or slurry containing no additives. Oil Well Cement -- Cement or any mixture of cement with other materials that is intended for use in oil, gas or water wells (API definition). Portland Cement -- A closely controlled combination of lime, silica, alumina, iron and small amounts of other ingredients, to which gypsum is added in the final grinding process to regulate setting time. Named for an island famous for its gray limestone quarries. Pozzolan Cement -- A mixture containing cement and pozzolan, a volcanic ash type substance, with advantages in certain high temperature, deep wells, or as an expanded lightweight cement. Some 2000 years ago Roman engineers mixed the first "pozzolana" or volcanic cement, which was the first hydraulic cement, hardening underwater. Retarded Cement -- Cement in which the thickening time is extended by adding a chemical retarder. API Classes D and F are retarded cements. Slow-Set Cement -- Cement in which the thickening time is extended by eliminating the rapid hydrating components in its composition or by adding a chemical retarder. API Classes D, E, and F are slow-set cements. Weighted Cement -- Cement slurry containing additives to increase the normal density. Definitions Of Oil Well Cementing Additives Accelerators -- Used for accelerating the early strength of oil well cementing slurries. Small additions of these materials in cement reduce waiting on cement time, promote greater early strength and result in a saving of rig time to the operator. Cement Dispersant -- Use of dispersants lower the apparent viscosity of the slurry. This dispersing or thinning effect means that a slurry will go into turbulence at a flow rate lower than would be required without such an additive. Fluid Loss Additives -- Provide fluid control for deeper penetration and more efficient use of expensive acid. Small amounts of special additives may be combined with most fracturing fluids to help confine them within the fracture, thus increasing extension efficiency and enhancing proper placement of the propping agent.

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Heavy-weight Additives -- Added to different type cements to increase density of slurries in deep wells where it is desired to have the weight of the cement near that of drilling mud at the time of cementing for the control of high pressure oil and gas zones. Latex -- Added to cement to achieve low fluid loss values, lower viscosity in fresh and salt brine slurries, better flow properties, and improved bonding. Light-weight (extenders) -- Used for the reduction of slurry densities and to increase fill-up of cement between the casing and formation. Mud Decontaminant -- An additive to reduce the effects of contamination of cement slurries by the organic chemicals commonly found in drilling muds. Retarders -- Retarders make possible the formation of cementing compositions for any range of high temperature well conditions. Silica (Flour) -- Used as an additive to oil well cement making it possible to maintain low permeability and improve cement compressive strength under "hot hole" conditions. Special Additives -- Used to control gas migration problems in cement. Thixotropic Cement -- Thixotropic cements possess the ability to rapidly develop a high degree of gelatin, or static gel strength, giving some unique advantages in special applications. Spacers & Washes Fibers -- Synthetic fibrous materials are used for reducing shattering due to perforating, and improving total resiliency. Spacers -- Aid in preventing combining of cement slurries with drilling muds, and in the minimizing of formation damage. Special Cements -- Used to control gas migration problems in cement. Washes -- Used principally as reactive flush ahead of primary cementing to improve mud displacement, control fluid loss, and alleviate lost circulation during cementing.

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Table of Contents - Chapter U Electric Drilling Rigs U-1. Silicon Controlled Rectifier Systems .................................................................................................. U-4 1. Introduction .................................................................................................................................... U-4 A. DC/DC and SCR Systems ............................................................................................................. U-4 B. DC Drilling Motors ........................................................................................................................ U-4 U-2. SCR (AC/DC) Power Systems ........................................................................................................ U-6 A. Ac Electrical Power Generation ...................................................................................................... U-6 A3. AC Switchgear ............................................................................................................................ U-7 B. AC/DC Conversion ....................................................................................................................... U-8 U-3. DC/DC Power Systems ................................................................................................................. U-13 A. Introduction ................................................................................................................................. U-13 B. Controls ....................................................................................................................................... U-13 C. Braking ........................................................................................................................................ U-13 D. System Protection ........................................................................................................................ U-14 E. Driller's Console ........................................................................................................................... U-14 U-4. Maintenance ................................................................................................................................... U-15 General ............................................................................................................................................ U-15 Maintenance Section Outline ............................................................................................................. U-15 Daily Maintenance: ........................................................................................................................... U-22 Monthly Maintenance: ....................................................................................................................... U-22 Repair: ............................................................................................................................................. U-22 U-5. Technical Index .............................................................................................................................. U-23 1. Maintenance Checklists: ................................................................................................................ U-23 2. Reference Handbooks .................................................................................................................. U-24

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CHAPTER U SCR Systems The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study.

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U-1. Silicon Controlled Rectifier Systems 1. Introduction There are two types of electric drilling rig systems - DC/DC and AS/SCR. generator sets, control systems and electric motors.

Each system consists of engine/

DC motors are used on mud pumps, drawworks and rotary table, and AC motors are used to power auxiliary functions on both types of systems. The electric drilling rig is similar to the mechanical rig. Power is produced by engines on both the mechanical and the electric drilling rigs. This engine power is transmitted to the rig equipment through electric cables to motors on the electric rig. The mechanical rig uses chains, compounds, torque converters and V-belts to transmit the engine power to the rig equipment.

A. DC/DC and SCR Systems DC/DC systems typically include multiple engine/DC generator sets and control systems connected by cable to DC motors. Each generator is assigned to a specific motor. The DC/DC systems are generally arranged so that each motor can receive power from two or more engine/generator sets to provide back-up in case any engine/ generator set is not functioning. SCR systems typically include multiple engine/AC generator sets, AC to Dc conversion systems, and controls connected to DC motors. All the engine/generator sets are connected to a common AC bus. The SCR system converts the AC current to DC current and transmits the DC current to the DC motors.

B. DC Drilling Motors The motors used with SCR or DC/DC systems are either shunt or series type and are usually rated 800-12500 HP for drilling applications. The DC motor is used because of its ease of control. The shunt motor differs from the series motor both in its connection configuration and its operational characteristics. The shunt motor requires a separate DC power source to provide the field current (Figure U1-1). FIGURE U1-1: DC Shunt Motor Schematic

While the series motor allows the armature current to also flow through the field (Figure U1-2).

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FIGURE U1-2: DC Series Motor Schematic

The shunt motor is the simplest to control since its speed is directly proportional to the DC volts supplied across its armature and its torque output is directly proportional to amperes. Load does not appreciably effect the speed of the motor. The speed of an uncontrolled series motor is greatly affected by its load. With light loads, a series motor could overspeed and damage itself and the equipment it is driving. There are many methods in use today to protect the motor and equipment from this overspeed condition. They include: Electronic circuitry to make the series motor characteristic simulate that of a shunt motor. (Load has no appreciable effect on speed.) Speed regulation is provided via a motor mounted tachometer. A motor mounted overspeed device shuts off the motor if it exceeds a set speed. The motor is shut down any time the load (current) decreases below a given volume signifying a broken chain, belt, sprocket, etc. Series motors have excellent speed-torque characteristics for accelerating loads from a standing start to full speed which is perfect for efficient drawworks operation. Series motors also have excellent load sharing characteristics for multiple motor loads.

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U-2. SCR (AC/DC) Power Systems A. AC Electrical Power Generation Although it is sometimes feasible to use utility power, electrical power for an SCR type drilling rig is typically provided by alternating current generators driven by engines. The size and quantity of engine/generator sets is dependent upon the power requirements of the individual drilling rig. The deeper the drilling depth rating of the rig, the more power will be required to operate the rig. This section will attempt to provide a general understanding of power generation by dividing the information into three subtopics. 1. Engines 2. Generators 3. AC Switchgear

A1. Engines The engine converts a fuel to mechanical torque that turns the AC generator. Although diesel engines are the most source of power, other types such as gasoline, natural gas or gas turbines are also used to a lesser degree. Electrically operated actuators are provided on the engines to control the fuel rack, which in turn controls the torque output of the engines. The actuators are interfaced to an electronic governor control that is typically installed in the AC switchgear. In some cases the actuators have a mechanical "flyball" type control that may be used in the event of governor control failure. A magnetic pickup, which provides a speed signal for the electronic governor is usually installed on the engine, typically near the starter ring gear.

A2. Generators The generator converts rotating motion or torque of the engine to electrical power. Synchronous type AC generators or alternators are the most common units used. They provide an output of 600 volt, 3-phase power. A synchronous type generator is composed of three main elements. a. Rotor b. Stator c. Exciter The rotor is mounted on a shaft driven by the engine. Electromagnets, called "field poles", are mounted upon the rotor. Each pole is wound with a wire so connected that when direct current is supplied to the coils, from the exciter, alternate North and South magnetic poles are produced. The rotor revolves within the stator, or armature, which has insulated electrical conductors wound around a laminated steel core. As the rotor revolves at rated speed its magnetic fields generate alternating current of the proper voltage and frequency in the conductors. This generated voltage is transmitted via power cables to the AC switchgear. The exciter is controlled by a voltage regulator which is typically installed in the AC switchgear. Two types of exciter can be obtained. The first is the "brush" type exciter which uses brushes and a commutator. The "brushless" type (rotating rectifier) exciter, which eliminates the brushes and commutator, is becoming more popular as it requires less maintenance.

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A3. AC Switchgear The three main functions of the AC switchboard are: control, protection, and metering.

A31. CONTROL a. Voltage Regulator The output of the generator is controlled by the voltage regulator. The voltage regulator monitors the generated voltage and varies its output to the generator exciter to control the amplitude of the generator voltage. A second function of the voltage regulator occurs while two or more generators are connected in electrical parallel. The voltage regulators will force the paralleled generator to share the KVAR load equally. b. Governor Control The speed or torque output of the engine is controlled by an electronic governor that controls the engine fuel actuator. The actuator increases or decreases the engine fuel rack to provide constant speed. The governor control compares a pre-set speed reference with the speed signal from the engine mounted magnetic pickup. During operation of more than one engine, in parallel arrangement, the power (or Kilowatt [KW]) output of each engine/generator monitored by its governor control. The output signal is compared to that of other engine/generators and as the paralleled governor controls "communicate" with each other a correcting signal will cause each engine generator set to assume its proportional share of the total power demand or load. c. Synchronization Circuitry Generators to be operated in electrical parallel must be operating at the same frequency, voltage, and phase rotation. Most AC switchboards will have circuitry to monitor these three conditions. If any or all of the above conditions are not met, the circuit breaker of the generator to be paralleled will close.

A32. PROTECTION a. Generator Circuit Breaker The Generator circuit breaker protects the generator from short circuits and undesirable overload conditions. It also acts as a device to connect or disconnect its generator from the main AC bus. The generator circuit breaker typically is provided with an undervoltage release feature that prevents the circuit breaker from being closed when the generator is not energized. Usually a shunt trip mechanism, that allows the circuit breaker to be opened remotely by other protective devices, is also furnished. b. Reverse Power Protection The loss or reduction of engine torque, daring parallel operation of two or more engines, will result in a condition of the generator called "motoring". This condition occurs when current flows into a generator from other generators. It can cause engine or generator damage. The reverse power relay monitors the generator output and will open the associated generator circuit breaker during a sustained reverse power condition. c. Under Frequency Protection During periods of underspeed operation of an engine, the voltage regulator output is reduced by the under frequency protection device. This protects the voltage regulator, the exciter and generator from damage.

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d. Over Voltage Protection The over voltage protective device will remove power from the voltage regulator during conditions of over voltage (typically 125-150%). e. Power Limiting The power limiting circuit compares the generator power available with the power being used .or demanded. If the power demand exceeds the power that is available some of the load will be reduced to protect the engine/ generators from overload and a possible complete "blackout" of the rig power system. f. Ground Fault Detection Monitors system and detects AC grounds in cables and equipment.

A33. METERING The following metering is typically provided in the AC switchgear to monitor the output of the engine generator sets. a. AC Ammeter Measures the current output from the generator and is used to check for load balance. b. AC Voltmeter Monitors the generator output potential. c. AC Wattmeter Monitors the kilowatt or power output of the generator and is used to assure equal division of the KW load between paralleled generators. d. KVAR Meter Monitors the reactive power output of the generator and may be used to balance reactive power division between generators. e. Power Factor Meter Monitors the generator power factor and sometimes used in lieu of a KVAR meter to balance reactive power between generators. f. Frequency Meter Indicates the generator or main bus frequency in Hertz (or cycles) per second. g. Synchroscope Provides a visual indication of the relationship of the frequency or speed of the generator to be paralleled to that of the energized main bus.

B. AC/DC Conversion This section will describe the workings of the SCR system itself in converting AC power to DC power. For a simple one line flow diagram of a SCR converter system, see Figure U2-1.

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FIGURE U2-1: Three Phase AC Power

B1. GENERAL The SCR system changes the constant voltage AC power to an adjustable voltage DC power to enable speed control of the DC drilling motors, which in turn power the drilling functions and control rotary table speed, mud pump pressure and flow, etc. The following is a list of components found in all SCR cubicles: a. Circuit breakers; b. Power fuses; c. SCR -- heat sink assembly into a 3 phase full control bridge rectifier; d. Electronic controls; e. Driller's console; and f. DC assignment contactors.

B2. PROTECTION B2a. Circuit Breakers The circuit breaker connects and disconnects the 3 phase AC power bus to the SCR rectifier section with the added function of limiting fault current. B2b. Fuses Aiding in this protective function are current limiting power fuses. Some SCR systems have six fuses (one negative and one positive on the DC or load side of the bridge). Some SCR systems have 3 current limiting power fuses (one per phase on the AC or line side of the bridge).

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All power fuses have the task of limiting damage to the SCR's in a fault condition. FIGURE U2-2: Power Circuit Diagram

B2c. SCR Heat Sink Assemblies Since SCR's control a great deal of the current and all real world electrical components have some resistance, heat is generated. This heat is removed by mounting the SCR in a heat sink assembly consisting of an aluminum extrusion. The heat is passed from the SCR to the heat sink and then to the air by forcing a large volume of air over the heat sinks (by a blower assembly). When the cabinet doors of most SCR cubicles are opened the heat sinks are usually the most obvious components in view. B2d. Electronic Controls The DC control electronics have five (5) basic functions: 1. Receive a throttle signal. 2. Convert this signal to a synchronized gate firing signal to turn the SCR's on at the proper time. 3. Measure the result (DC power output) and make any error corrections. 4. Measure the DC current being produced and compare it to the current limit setting and inhibit the current from exceeding that setting. 5. Accept power limit signal from AC generator control section. B2e. Throttle Signal The throttle signal comes from the driller's console and represents a desired speed for a drilling load (mud pump strokes per minute or rotary table rpm). By determining when an SCR turns on in an electrical cycle the output DC voltage can be varied from 0 to 750 volts DC. See Figure U2-3.

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FIGURE U2-3: AC Input to SCR Bridge

If the SCR's are turned on continuously at point A on the AC sine wave, the DC voltage will be higher than if it is turned on at points B or C. After the throttle signal is interpreted, the electronics gate firing circuitry works like a distributor on a six (6) cylinder auto engine and tums each of the six (6) SCR's on in the proper sequence to produce a steady DC voltage output.

3. BRAKING B3a. Braking (Dynamic) Braking is necessary to stop the free wheeling drawworks motor after it is de-clutched. The braking action is induced by causing the motor to act as a generator. To rapidly stop the armature rotation, a load resistor is connected across the armature producing a reverse torque which slows the motor to "cathead speed" (a low speed); at that time, the motor is disconnected from the resistor and reconnected to the SCR. B3b. Braking (Regenerative) Instead of connecting the freewheeling drawworks motor to a resistor, it is connected through a reversing contact and the SCR bridge to the main 600 volt bus. The armature's rotational energy is dissipated through other electrical loads on the rig instead of heat in the resistor. B3c. AC Distribution There are many AC motors and loads on a rig which require a means of distributing the power in a safe, efficient manner. Every rig has some sort of AC distribution which normally consist of the following: 1. 600 volt distribution circuit breaker. 2. 600 to 480 volt distribution transformer. 3. 600 (or 480) to 120 - 208 volt lighting transformer. 4. Motor control centers. 5. Lighting panel.

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B3d. 600 to 480 Volt Distribution Transformer Electric rig power is produced at 3 phase, 60 hertz, 600 volts AC to allow efficient usage of the drilling motors at 750 volts DC. However, most AC motors of the size required on a drilling rig are built to use 3 phase, 60 hertz, 480 volt AC. A transformer is used to convert 600 volts to 480 volts AC. B3e. Motor Control Center (MCC) This 480 volts AC is used to power a motor control center which is a self contained collection of AC motor starters, all connected internally to a common AC bus. A typical MCC will contain approximately 30 starters and 10 to 12 circuit breakers only. The output of each starter is wired to a given AC motor on the rig. The starters purpose is to safely start and stop the AC electric motors on a bridge. The starters all contain: a disconnecting device (electrically operated switch); and an overload relay to protect the motor against a continuous overload. B3f. Lighting Panel Most lighting circuits run on 120 volts AC or 208 volts AC and, therefore, most rigs have another transformer which is connected to a lighting circuit breaker panel (just as a house has) which is connected to the lights on a rig.

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U-3. DC/DC Power Systems A. Introduction DC/DC Electric Drilling Rigs have been built with a variety of designs over the past 25 years. They range from a totally electric system to several hybrid configurations. the hybrid configurations generally have a compound which is used to drive the mud pumps, one or more DC generators, and sometimes the drawworks. The drawworks and/ or the rotary table is electrically driven by a DC drilling motor. The main attractiveness of such rig power arrangements is the rotary torque control, but the secondary advantages of reduced maintenance, fewer chain alignment problems, speed control, improved fuel efficiency, etc. are also attained.

B. Controls There are four main components to a DC/DC rig: the DC generators, the motors, the control cabinet, and the driller's console. On present day DC/DC rigs, the motors and generators are usually interchangeable (the hubs may have to be changed). This greatly reduces the required spares. The driller's console is a remote command post for the control cabinet. The heart of a DC/DC control system is the voltage regulator. It is an electronic module that controls the output of the generator in accordance with commands from the driller's console. There are no other active components in the system. All other components (i.e. blower starters, transformers, meter, etc.) are passive. The drilling motor speed and torque is controlled by regulating the generator output. This means each motor that is operating must have one generator assigned to it. Usually each generator can be assigned to either of two motors. These assignments as well as the speed and torque adjustments are made from the driller's console. Because of the one-on-one assignments described in the foregoing, the generators are not "pooled" into a common bus. This means the engines do not have to be operated at the same speed -- the speed of each drive engine can be varied in accordance with the power required. There is no need to parallel or synchronize generators. There are no engine/generator load sharing adjustment required. There are several choices in engine speed controls generally available with DC/DC systems: * Constant full speed * Constant full speed with automatic idle when not loaded * Constant or variable speed as selected by switches on the driller's console In the past, this fuel saving feature was made possible with an air operated governor system, but is now generally done with electronic governors. This engine speed control is an option not supplied on all systems and when supplied, generally can be simply bypassed for operation at a constant engine speed. Variable speed is the recommended mode of operation, when available, for best fuel consumption and improved engine life.

C. Braking To brake the drawworks motors down from hoisting speeds (foot throttle) to the cat head speed (hand throttle), DC/DC systems brake via regeneration not dynamic braking. No resistor grids are required. The motor, which is rotating due to its own inertia, acts as a generator and drives current back to the generator. The generator acts like a motor and tries to increase the engine speed. The engine acts like an air compressor and dissipates the energy as heat and friction.

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D. System Protection 1. Generator overcurrent trip: Open power contactor when generator current exceeds the current limit due to a failure of the control circuit.

2. Ground Relay: Detects presence of a leakage or short circuit to ground and stops all operations. Operation can continue with ground relay bypassed until the problem is corrected. (Bypass is normally simply done with a selector switch within the control cabinet.)

3. Circuit Breakers: Used at many points in control system to protect wiring and devices in case of short circuits. The AC circuits feeding the field supply panels and blower starters, for example, are protected with circuit breakers.

4. Enclosure: Because of the low heat generation of the DC/DC control components, an air conditioned control house is not usually required. The standard cabinet is often mounted outside with no additional protection.

E. Driller's Console The driller's console is the command post for the DC/DC system. The following are some of the controls and indicators usually included: * Hand throttle for each function (mud pump, rotary table, cat head, etc.) * Foot throttle (drawworks speed control when tripping) * Assignment switch for each generator * Reversing switches (rotary table and/or drawworks) * Ammeters and voltmeters to indicate motor speed and torque * Lights to indicate: * The motor blowers are operating. * The ground relay has shut down the system due to a ground fault.

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U-4. Maintenance General These maintenance procedures are guidelines to be used by the drilling contractor in his maintenance program. In addition, refer to the vendor maintenance manuals supplied with the equipment. In general, electrical equipment requires a minimum of amount of attention to keep it functioning well. A well planned maintenance program by the drilling contractor will prevent many failures that occur due to neglect and abuse. It is suggested that each rig manager maintain maintenance records on each type of equipment and document it well with any failures, replacements, repairs, or inspections. Nameplate information and other special data recorded will also aid in ordering and replacing parts as they are required. Care and caution should be used when inspecting, repairing, or replacing electrical equipment. Only authorized persons who have been trained in the operation and repair of the equipment should be allowed to perform these operations since shock, death, or equipment damage can occur. It is suggested that warnings be placed on equipment to alert personnel of the dangers that exist with electrical equipment. Typical of these signs are the following: WARNING THE ELECTRICAL EQUIPMENT CONTAINS HAZARDOUS VOLTAGES. WHEN WORKING ON HIGH VOLTAGE EQUIPMENT, ENSURE THAT ALL POWER HAS BEEN REMOVED. CAUTION DO NOT USE SANDPAPER, EMERY PAPER, OR OTHER ABRASIVE MATERIALS TO CLEAN PLUGS, CONTACTOR TIPS, RELAY TIPS, OR OTHER ELECTRICAL CONNECTIONS. USE A DRY CLOTH, PROPER SOLVENTS, OR PENCIL ERASER TO PERFORM THESE OPERATIONS. The IADC does not accept responsibility for any damage to equipment or personnel that results from the exercise of these maintenance suggestions. They are intended to guide the drilling contractor in the proper methods and frequency of preventive maintenance and repair.

Maintenance Section Outline A. SCR CONTROLS Daily Maintenance Procedure: 1. Inspect exterior surfaces of panels for dirt, grease, oil or physical damage. 2. Inspect interior for dust, dirt, oil, grease, metal, water, or corrosion. (CAUTION: Do not touch live electrical parts.) 3. Inspect all air filters for cleanliness; clean or replace as necessary. 4. With power off, check for loose hardware in the equipment, preferably during rig moves or down time. 5. During rig operation, inspect all meters, instruments and lamps for faulty operation or damage; replace as necessary. 6. Check all contactor tips for pitting or wear; replace as necessary. 7. Inspect plugs and connectors for damage or looseness.

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8. Inspect printed circuit boards, modules, and other electrical components for damage or overheating. Monthly Maintenance Procedure: 1. Clean each SCR bay monthly to remove dust and dirt by using the suction side of a vacuum cleaner. Never blow the equipment with forced air to clean it. CAUTION: Be sure all power is off before this procedure is followed. 2. Thoroughly tighten all bolts and hardware in the equipment and replace any hardware that is missing. CAUTION: Be sure all power is off before this procedure is followed. 3. Calibrate all meters from a reference source. 4. Check operation of all controls, including assignments, reversing, dynamic braking, operation of mud pumps, and other functions. Repair: 1. All repairs should be performed by competent, trained electricians or technicians who are familiar with the SCR equipment. All power must be removed from the equipment before any repairs are made. 2. These items that can be easily repaired or replaced are included in the following list and are considered to be at the module or assembly level. Repair of printed circuit boards or other electronic components should not be attempted except in emergencies. a. Replace fuses. b. Replace SCR bridges, cells, or assemblies. c. Replace printed circuit cards. d. Replace control modules, such as AC Module, DC Module, Voltage Regulator, Governor, Reverse Power, or similar assemblies. e. Repair wiring terminations. f. Replace damaged DC contactor tips. g. Replace defective relays. h. Repair mechanical damage. i. Adjust instrument "zero" with screwdriver. j. Replace any overheated component and determine cause of problem.

B. AC GENERATOR CONTROLS Daily Maintenance Procedure: 1. Inspect exterior surfaces of panels for dirt, grease, oil or physical damage. 2. Inspect interior for dust, dirt, oil, grease, metal, water, or corrosion. (CAUTION: Do not touch live electrical parts.) 3. Inspect meters for proper operations, including KW, KVAR, POWER FACTOR, AMMETER, VOLTMETER, FREQUENCY METER, and SYNCHROSCOPE. Cheek for proper load balance between paralleled generators using these instruments. 4. With power off, check for loose hardware in the equipment, preferably during rig moves or down-time.

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5. Check all modules and equipment for overheating or electrical damage through visual inspection. 6. Are generator controls and governors operating properly? Cheek for instability of voltage or frequency. 7. Check the status of all control switches, circuit breakers, and controls. Monthly Maintenance Procedure: 1. Clean each generator control bay monthly with a vacuum to remove dirt, dust, and oil particles. CAUTION: Be sure all power is off before this procedure is followed. 2. Thoroughly tighten all bolts and hardware in the equipment and replace any hardware that is missing. CAUTION: Be sure all power is off before this procedure is followed. 3. Calibrate all meters from a reference source. 4. Check operation of all controls, including voltage regulator, governor paralleling, synchronizing, load sharing, and circuit breakers. Repair: 1. All repairs should be performed by competent, trained electricians or technicians who are familiar with generator control equipment. All power should be removed from the equipment before any repairs are made to avoid costly accidents. 2. Those items that can be easily repaired or replaced are included in the following list and are considered modules or significant components. Repair of printed circuit cards, or other electronic components, should not be attempted except in emergencies. a. Replace circuit breaker. b. Replace AC Module, DC Module, Voltage Regulator, Electronic Governor, Reverse power Relay, Overvoltage/ Underfrequency Module or other control modules. c. Replace defective meters or instruments. d. Replace defective voltage or speed control adjusts. e. Repair wiring terminations. f. Replace defective lamps. g. Repair mechanical damage. h. Adjust instrument "zero" with screwdriver. i. Replace any overheated component and determine cause of problem.

C. MOTOR CONTROL CENTER AND SWITCHGEAR Daily Maintenance Procedure: 1. Inspect exterior surfaces of MCC sections and controls. 2. Inspect interior of each section for overheating and proper operation of components. Inspect for dust and other foreign matter. 3. Check for loose hardware. 4. Check all circuit breakers and disconnect switches.

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Monthly Maintenance Procedure: 1. Clean each MCC cubicle and switchgear bay with a vacuum to remove dust and other debris; do not blow the dust loose with a vacuum. CAUTION: Be sure all power is off before this procedure is followed. 2. Thoroughly tighten all bolts on components and equipment. Replace any missing hardware. CAUTION: Be sure all power is off before this procedure is followed. 3. Calibrate all meters and instruments from a reference source. 4. Inspect each overload relay and motor protective device. Repair: 1. All repairs should be performed by competent, trained electricians. Power should be removed from any equipment that is being serviced or repaired. 2. The following items should be repaired or replaced if found defective: a. Circuit breakers. b. Overload relays. c. Pushbuttons, lamps, controls, switches. d. Wiring terminations, connectors, plugs.

D. DRILLER'S CONSOLE AND FOOT THROTTLE Daily Maintenance Procedure: 1. Inspect exterior of console for damage to the enclosure or instrument window. 2. Inspect exterior of console for damage to connectors, throttles, meters, switches, pushbuttons, or other components. 3. Inspect exterior of foot throttle for damage to pedal or connector. 4. Inspect air pressure equipment to console and throttle to assure positive pressure or flow. 5. Inspect interior of console for dust, dirt, or foreign material. 6. Inspect interior of console for overheated components or loose connections. CAUTION: Be sure all power is off before touching any electrical terminal or component. 7. Check instruments and lamps for operation. 8. Operate the throttles and other controls for proper operation. 9. Operate the foot throttle for proper operation. Monthly Maintenance Procedure: 1. Clean the console and foot throttle monthly with a vacuum to remove dust, dirt and other debris. CAUTION: Be sure all power is off before following this procedure. 2. Tighten all loose hardware and replace any missing hardware. 3. Calibrate all instruments and controls with a reference source.

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4. Inspect all wiring terminations and reconnect as required. 5. Operate all control functions, including throttles, switches, assignments, and meters to assure proper operation from the driller's console. 6. Operate the foot throttle in conjunction with the driller's console. Repair: 1. All repairs should be performed by competent electricians or technicians who are familiar with the operation of this equipment. Power should be removed from all equipment that is being repaired or replaced. 2. The following items can be repaired or replaced in the driller's console or foot throttle: a. Throttle potentiometers or variable transformers. b. Meters or instruments. c. Pushbuttons, switches, or other controls. d. Connectors, wiring terminations, plugs. e. Adjust instrument "zero" with screwdriver. f. Mechanical components.

E. CABLE AND WIRING Daily Maintenance Procedure 1. Inspect all cable and wiring for mechanical damage. 2. Inspect all terminations to lugs, connectors, or compression devices. 3. Remove any grease, oil, or chemicals from the wiring insulation. 4. Protect any cables that are not covered in traffic areas. 5. Replace any tie wraps or supports that become defective. 6. Inspect junction boxes that are frequently used. 7. Inspect for signs of arcing at points of connection or where cuts or fraying are detected. Monthly Maintenance Procedure: 1. CAUTION: Power must be turned off. Tighten all lugs and connections to cables. 2. Replace any cut or damaged cable or wiring. 3. Rerun cable that is subject to heavy traffic. 4. Check all connectors and plugs. Repair: 1. All repairs or replacements should be performed by competent electricians with power turned off. 2. Repair or replace the following: a. Defective cable. b. Defective or damaged plugs, connectors, or lugs.

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c. Overheated connections or cable.

F. ELECTRIC BRAKE Daily Maintenance: 1. Inspect cooling water supply to assure that proper volume of water is being supplied to the brake. 2. Inspect the exhaust ports of the brake to assure that free flow of the cooling water is assured with gravity flow. 3. Determine that brake is not overheating during operation. 4. Check coupling between brake and drawworks. 5. Check mounting bolts to brake frame for tightness. 6. Inspect cable to junction box of brake. Monthly Maintenance: 1. Inspect air gap of brake through inspection ports with feeler gauge to assure concentricity and lack of corrosion buildup. Refer to brake manual for proper air gap distances. 2. With power off, check the brake coil resistance to assure continuity of each winding. Also, check for any coil grounds by measuring each coil to ground. All external connections to the brake control should be removed at the junction box for these checks. 3. With power applied to the brake control, turn the control to full on and determine that the full DC voltage is received by the brake. Operate the throttle over the full range and determine that the controller output voltage is smooth and continuous over the full range of operation. 4. Any controller in a east aluminum box should be opened and the cooling/insulating oil replaced with clean oil. Remove any foreign liquid or matter in the box before replacing the oil. 5. Other controllers in a NEMA box should be kept clean and free from dust and debris. Repair: 1. The brake should only be repaired by competent mechanics and electricians who are trained for this purpose. Only external hardware should be repaired or replaced on the brake under normal conditions. 2. Replace any electrical cable that becomes damaged or oil-soaked. 3. Replace the throttle if damaged and assure that the wiring is replaced correctly. 4. The brake control should be replaced in its entirety and not repaired at the rig site except in emergencies. 5. The transformer should be replaced in its entirety if damaged or faulty.

G. DC MOTORS AND GENERATORS Daily Maintenance: 1. Inspect the motor for excessive vibration. 2. Inspect the motor couplings, sprockets, hubs, mounting, and other mechanical connections. 3. View the motor commutator and brushes for proper commutation and minimum connections. 4. Confirm that the cooling blower motor is operating properly. 5. Inspect the cables for damage or corrosion.

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6. Confirm that the motor is not overheating during operation. 7. Inspect the field supplies and yield voltage on shunt motors. 8. Check bearings for excessive temperature after continuous running. 9. Blow out dust and debris with clean, dry air. 10. Lubricate bearings with proper grease, if not sealed bearings. 11. Check tightness of mounting bolts. Monthly Maintenance: 1. Disassemble, clean, inspect and repair as necessary. Repack bearings as required. 2. Inspect brushes for proper tension on commutator and position. 3. Inspect commutator for proper surface conditioning. 4. Check cooling blower for proper operation. 5. Check mounting of hub or coupling. Repair: 1. Replace brushes and brush springs as required. 2. Clean commutator according to motor manual. 3. Resurface commutator if evidence of uneven wear or pitting is observed. 4. Replace blower if found defective. 5. Remove motor/generator from service if bearings or windings are found defective and replace motor/generator on rig.

H. AC GENERATORS AND MOTORS Daily Maintenance Procedure: 1. Inspect for excessive vibration when running. 2. Assure that proper mating between Diesel Engine and AC generator is maintained. 3. Inspect motor couplings and mounting connections. 4. Inspect wiring to motor and generator. 5. Blow out dust and debris on motor and generator. Monthly Maintenance Procedure: 1. Check motor currents for overloads. 2. Check generator currents for overloads or unbalanced loads. 3. Inspect motors for overheating. 4. Operate each motor and generator for proper performance. 5. Tighten all mounting and coupling hardware. 6. Inspect all wiring and connectors.

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Repair: 1. Replace diodes on rotary exciter with exact replacements if required for generator. 2. Remove defective motor from service and replace. 3. Clean and dry out motors and generators if exposed to high humidity or moisture.

I. TRANSFORMERS General 1. Transformers usually do not have any moving parts, except for occasional cooling fans, and require minimal attention except for keeping it clean and dry. 2. Before performing any service on transformers, be sure all power is off.

Daily Maintenance: 1. Inspect for overheating. 2. Inspect for external damage to core or coil. 3. Inspect wiring and cabling to transformer.

Monthly Maintenance: 1. Clean and remove any moisture from the transformer. 2. Inspect for any hot spots on the transformer coils. 3. Inspect transformer connections. 4. High pet winding to ground to check insulation with all external leads disconnected. 5. Check all winding continuity with leads disconnected to loads and supply.

Repair: 1. Replace any lugs or connections to transformer that become defective. 2. Replace the transformer if found defective and return transformer to repair shop.

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U-5. Technical Index 1. Maintenance Checklists: A. Baylor Company, Sugar Land, Texas 1. Brake Systems 2. SCR Systems 3. Generator Controls B. General Electric Company, Dallas, Texas 1. SCR Systems 2. DC Motors 3. DC Generators 4. Generator Controls 5. Transformers 6. DC-DC Drive Systems 7. AC Generators C. Integrated Power Systems, Houston, Texas 1. SCR Systems 2. Generator Controls D. Ross Hill Controls Corporation 1. SCR Systems 2. Generator Controls

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2. Reference Handbooks 1. "The Electric Drilling Rig Handbook", by Will L. McNair; PennWell Publishing Company, Tulsa, OK 1980. 2. "Economic Operation of Electric Drilling Rigs", paper presented by Will L. McNair at the 1980 IADC Drilling Technology Conference in Dallas, Texas. Reproduced in "World Oil" Magazine in June, 1980, and in "Oil & Gas Journal" on April 7, 1980. 3. "Fuel Economy -- A Ten Year Projection For The Drilling Industry" by Will L. McNair & Roger D. Morefield, "Drilling -- DCW" Magazine, August, 1980. 4. "A Systems Approach To Electric Land Rigs" by William M. Stone, presented at 1979 IADC Technology Conference, March, 1979, Denver, Colorado. 5. "Electrical Design Considerations For Drilling Rigs", Frank A. Woodbury & Paul J. Thomas, a paper presented to IEEE Industry Applications Society, 1975 Milwaukee, Wise. 6. "Self-Study Technical Series For Rig Electricians", Electric Drilling Systems, Houston, Texas. 7. "A Comparison of Mechanical And Electrical Drives For Land Drilling Rigs", Glen Webb, presented at 1977 Drilling Technology Conference of IADC, March 1977.

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Chapter V General Information

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Table of Contents - Chapter V General Information Introduction ........................................................................................................................................ V-3 1. Selected API Publications (Producton) .................................................................................................. V-4 Introduction ........................................................................................................................................ V-4 Belting ................................................................................................................................................ V-4 Derricks And Masts ........................................................................................................................... V-4 Tubular Goods .................................................................................................................................... V-4 Valves And Wellhead Equipments ....................................................................................................... V-6 Drilling Equipment ............................................................................................................................... V-6 Hoisting Tools ..................................................................................................................................... V-7 Wire Rope .......................................................................................................................................... V-7 Oil Well Cements ................................................................................................................................ V-7 Drilling Fluid Materials ........................................................................................................................ V-8 Drilling Well Control Systems .............................................................................................................. V-9 Drilling And Production Recommended Practices ................................................................................ V-9 Special Publications .......................................................................................................................... V-10 2. Hole and Pipe Data ............................................................................................................................ V-13 Capacity ........................................................................................................................................... V-13 Displacement of Hole and Pipe ......................................................................................................... V-22 Volume and Height between Pipe and Casing: .................................................................................... V-27 Volume and Height between Pipe and Hole: ....................................................................................... V-39 3. Field Gas Lines ................................................................................................................................... V-49 Pipeline Flow Of Gas Formulae And Conversions ............................................................................. V-49 Gas Delivery, Based on 1000 Ft pipeline lengths ................................................................................ V-51 Gas Delivery, Based on 1 Mile pipeline lengths .................................................................................. V-54 Gas Delivery, Based on 10 Mile pipeline lengths ................................................................................ V-57 4. Waterlines - Line Pipe Capacities ........................................................................................................ V-60 5. Tank and Pit Capacity ......................................................................................................................... V-62 6. Conversion Factors ............................................................................................................................ V-68 7. Density of Oilfield Materials and Wood ............................................................................................... V-80 8. Density of Fluids and Petroleum Products ............................................................................................ V-82 9. Soil Bearing Capacity ......................................................................................................................... V-83

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CHAPTER V General Information The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study. This chapter has been updated and revised by Mr. Lawrence M. Jones.

Introduction In all operations it seems that we need some bit of information which had not been committed to memory and which is not always at our finger tips. Recognizing that values, formulas, conversion factors, tabulations, extcnded calculations, etc., can sometimes be of benefit on the drilling rig, we have collected and are presenting some data which may be useful in solving some of the common problems encountered in our Energy Industry.

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1. Selected API Publications (Producton) Introduction In many sections of this drilling manual reference has been made to various american petroleum institute (API) specifications and recommended practices. Users of this manual are encouraged to obtain the applicable API publications for any subject that is of interest: For Specific information concerning current forthcoming Production Department publications, call (214) 748-3841. and to order publications, write: American Petroleum Institute, Publications Department, 1220 L Street, N.W., Washington, D.C. 20005; or Phone: (202) 682-8375; or FAX: (202) 682-8537 A partial listing of API production publication follows.

Belting 811-00100 Spec 1B, Specification for Oil Field V-Belting, Fifth, Edition, March 1978 Covers standard and premium quality V-belts, dimensional marking requirements on V-belts sheaves, recommended practices for power application of V-belts, and recommendations on care and use of V-belts.

Derricks And Masts 811-01000 Spec 4E, Specification for Drilling and Well Servicing Structures, Third Edition, June 1, 1988 Covers steel derricks, portable masts, and substructures suitable for drilling or well servicing. It includes stipulations of materials, loadings, conditions of loading and allowable unit stresses intended to meet the requirements of present and future operating conditions, such as deeper drilling, offshore drilling from floating devices, and the effect of earthquakes, storms, and other adverse conditions. An appendix contains recommendations for maintenance and use of drilling and well servicing structures. 811-01050 Spec 4F, Specification for Drilling and Well Servicing Structures, Part II, First Edition, May 1985 This specification covers the design, manufacture, and use of steel derricks, portable masts, crown block assemblies, and substructures suitable for drilling and servicing of wells. It includes stipulations for marking, inspection, standard ratings, design loading, and design specifications of the equipment. Definitions of commonly used terms are included in Appendix A.

Tubular Goods 811-01400 Bull. 5A2, Bulletin on Thread Compounds for Casing, Tubing, and Line Pipe, Six Edition, May 1988 Provides material requirements and performance tests for two grades of thread compounds for use on oilfield new casing, tubing and plain end drill pipe. 811-01406

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RP 5A5, Recommended Practice for Field Inspection of New Casing Tubing, and Plain End Drill Pipe, Fourth Edition, May 1989 Provides uniform method for inspecting tubular goods. 811-01500 Spec 5F, Specification for Threading, Gaging, and Thread Inspection of Casing, Tubing, and Line Pipe Threads, Thirteenth Edition, May 31, 1988 Covers threading, gaging, gaging practice, and inspection of thread for casing, tubing, and line pipe made under Specifications 5CT, 5D and 5L. Also covers gage specifications and certification for casing, tubing, and line pipe gages. Supplement to thirteenth edition of Spec 5b, July 1990. 811-01580 RP 5B1, Recommended Practice for Gaging and Inspection of Casing, Tubing, and Pipe Line Threads, Third Edition, June 15, 1988 The purpose of this recommended practice is to provide guidance and instructions on the correct use of thread inspection techniques and equipment. 811-01600 RP 5C1, Recommended Practice for Care and Use of Casing and Tubing, Sixteenth Edition, May 31, 1988 Covers use, transportation, storage, handling, and reconditioning of casing and tubing. 811-01700 Bull. 5C2, Bulletin on Performance Properties of Casing, Tubing, and Drill Pipe, Twentieth Edition, May 1987 Covers collapsing pressures, internal yield pressures, and joint strengths of API easing, tubing, and drill pipe. 811-01800 Bull. 5C3, Bulletin on Formulas and Calculations for Casing, Tubing, Drill Pipe, and Line Pipe Properties, Fifth Edition, July 1, 1989 Provides formulas used in the calculations of various pipe properties, also background information regarding their development and use, combined bending and internal pressure. This information was previously published as Table 4 in the Thirteenth Edition, April 1971, of Bull 5C2. 811-01915 RP 5C5, Recommended Practice for Evaluation Procedures for Casing and Tubing Connections, First Edition, January 1990. Describes test to be performed to determine the galling tendency, sealing performance and structural integrity of tubular connections. NOTE: The first edition of RP 5C5 supersedes RP 37, Recommended Proof-Test Procedure for Evaluation of High-Pressure Casing and Tubing Connection Designs, February 1980. 811-01950 Spec 5Ct, Specification for Casing and Tubing (Combination of Former Specs 5A, 5AC, 5AQ, and 5AX - Casing and Tubing Requirements), Third Edition, December 1, 1990. Covers seamless and welded casing and tubing, couplings, pup joints and connectors in all grades. Process of manufacture, chemical and mechanical property requirements, methods of test and dimensions are included.

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NOTE: Spec 5CT includes the requirements for casing and tubing previously detailed in the last editions of discontinued Specifications 5A, 5AC, 5AQ, and 5AX. 811-01975 Spec 5D, Specification for Drill Pipe (Combination of Specs 5A and 5AX Drill Pipe Requirements), First Edition, March 15, 1988. Covers all grades of seamless drill pipe. Process of manufacture, chemical and mechanical property requirements, methods of test and dimensional tables are included. NOTE: Spec 5D includes the requirements previously detailed in the last editions of discontinued Specifications 5A and 5AX as well as items approved at the 1987 Standardization Conference.

Valves And Wellhead Equipments 811-03100 Spec 6A, Specification for Valves and Wellhead Equipment, Sixteenth Edition, October 1, 1989. This publication covers items of equipment utilized in pressure control systems required during the production life of a well; including end and outlet connections, ring gaskets, valves, wellhead equipment, and Christmas tree equipment. 811-03270 Bull. 6RS, Bulletin on Referenced Standards for Committee 6, Standardization of Valves and Wellhead Equipment, First Edition, July 1, 1990. This bulletin was developed to identify to the industry the applicability of standards, or sections thereof, referenced in publications under the jurisdiction of the API Committee on Standardization of Valves and Wellhead equipment. Other nationally or internationally recognized standards shall be submitted to and approved by the API Committee on Standardization of Valves and Equipment for inclusion in this bulletin prior to their use as equivalent standards.

Drilling Equipment 811-03300 Spec 7, Specification for Rotary Drilling Equipment, Thirty-seventh Edition, August 1, 1990. Covers dimensional requirements on drill-stem members (except drill pipe), including threaded connections, gaging practice, and master gages therefore; dimensional requirements on rotary tables, shafting, slush pumps, rotary hose, and brake blocks. Includes standard bit sizes. 811-03600 Spec 7F, Specification for Oil Field Chain and Sprockets, Fourth Edition, February 1980. Covers standard and heavy series roller chain and sprockets. Also included are recommended practices for installation and maintenance of roller chain drives. 811-03700 RP 7G, Recommended Practice for Drill Stem Design and Operating Limits, Fourteenth Edition, August 1, 1990. Covers recommendations for the design and selection of drill string members and includes considerations of hole angle control, drilling fluids, weight, and rotary speed. Tables and graphs are included that present dimensional, mechanical, and performance properties of new and used drill pipe, new tool joints used with new and used drill pipe, drill collars, and kellys. Recommended standards for inspection of used drill pipe, used tubing work strings and

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used tool joints are included. 811-03750 Spec 7J, Specification for Drill Pipe/Casing Protectors (DP/CP), First Edition, May 1985. Presents test procedures and performance standards for devices which attach to drill pipe and are intended to protect either the drill pipe or the casing from wear during drilling. Such devices are commonly known as drill pipe/ casing protectors and are widely used in the oil drilling industry. Supplement 1 to the first edition of Spec 7J, May 1987.

Hoisting Tools 811-03800 Spec SA, Specification for Drilling and Production Hoisting Equipment, Eleventh Edition, May 1985. Covers material requirements for, and methods of rating and testing, certain hoisting equipment used in drilling and production operations. 811-03900 RP 8B, Recommended Practice for Hoisting Tool Inspection and Maintenance Procedures, Fourth Edition, April 1979, Reaffirmed January 1, 1990. Covers recommended methods of inspection and maintenance of drilling and production hoisting tools to help prevent injury to personnel and irreparable damage to equipment. Supplement 2 to the fourth edition of RP 8B, November 1980. 811-03910 Spec 8C, Specification for Drilling and Production Hoisting Equipment (PSL 1 and PSL 2), First Edition, January 1, 1990. Provides standards for design, manufacture and testing of hoisting equipment suitable for use in drilling and production operations, product specification levels one and two.

Wire Rope 811-04000 Spec 9A, Specification for Wire Rope, Twenty-third Edition, May 1984. Covers wire rope of various grades and construction; also torpedo lines, well-measuring wire, and galvanized wire guy strand. Mooring wire rope is included. Supplement 1 to the twenty-third edition of Spec 9A, June 1, 1988. 811-04100 RP 9B, Recommended Practice on Application Care, and Use of Wire Rope for Oil Field Service, Ninth Edition, May 1986. Covers size and construction, field care and use, field problems and their causes, recommended design features of wire rope, and evaluation of rotary drilling lines.

Oil Well Cements 811-04450 Spec 10, Specification for Materials and Testing for Well Cements, Fifth Edition, July 1, 1990.

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Covers chemical and physical requirements, sampling, test procedures, packing, and marking requirements of well cements. (Replaces Spec 10A and RP 10B). 811-04600 Spec 10D, Specification for Bow-Spring Casing Centralizers, Fourth Edition, January 1991. Covers dimensions and test procedures for standard and close tolerance spring bow casing centralizers. 811-04605 RP 10E, Recommended Practice for Application of Cement Lining to Steel Tubular Goods, Handling Installation and Joining, Second Edition, January 1991. Provides standard procedures for plant application of cement lining to oilfield tubular goods and recommended methods of joining cement lined pipe. 811-04610 RP 10F, Recommended Practice for Performance of Cementing Float Equipment, First Edition, June 1, 1989. Provides recommended procedures for the performance testing of cementing float equipment.

Drilling Fluid Materials 811-07000 Spec 13A, Specification for Oil Well Drilling Fluid Materials, Thirteenth Edition, July 1, 1990. Covers physical requirements and test procedures for barite, bentonite, and saltwater clay for use in oil well drilling fluids. 811-07050 RP 13B-1, Recommended Practice Standard Procedure for Field Testing Water-Based Drilling Fluids, First Edition, June 1, 1990. Covers equipment and standard procedures for field testing drilling fluids. 811-07075 RP 13B-2, Recommended Practice Standard Procedure for Field Testing Oil-Based Drilling Fluids, First Edition, June 1, 1990. Covers equipment and standard procedures for field testing drilling fluids. 811-07114 Bull. 13D, Bulletin on the Rheology of Oil-Well Drilling Fluids, Second Edition, May 1985. Provides information, procedures and example calculations to aid in applying theological principles to liquid oil field drilling fluids. 811-07120 RP 13E, Recommended Practice for Shale Shaker Screen Cloth Designation, Second Edition, May 1985. Provides recommendations for a standard designation of screen cloth used for the screening surface on shale shakers. 811-07130

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RP 13G, Recommended Practice for Drilling Mud Report Form, Second Edition, May 1982 (formerly RP 47, First Edition, August 1969). Format lends itself to application of individual company names and insignias while retaining the overall format of the standardized document. 811-07145 RP 131, Recommended Practice, Standard Procedure for Laboratory Testing Drilling Fluids, Fourth Edition, June 1, 1990. Provides a standard procedure for laboratory testing of drilling fluids. 811-07148 RP 13J, Recommended Practice for Testing Heavy Brines, First Edition, June 1986. Provides standard laboratory methods for brine testing. 811-07149 RP 13K, Recommended Practice for Chemical Analysis of Barite, First Edition, September 1, 1990. Provides comprehensive, detailed description of the chemical analytical procedures for quantitatively determining the mineral and chemical constituents of barite. These procedures are quite elaborate and will normally be carried out in a well equipped laboratory.

Drilling Well Control Systems 811-07240 Spec 16A, Specification for Drill Through Equipment, First Edition, November 1, 1986. Provides requirements for performance, design, materials, tests and inspections, welding, marking, handling, storing and shipping of drill through equipment (BOP's, spools, hubs). 811-07244 RP 16E, Recommended Practice for Design of Control Systems for Drilling Well Control Equipment, First Edition, October 1, 1990. This recommended practice establishes design standards for control systems, subsystems and components used to control BOWs (blowout preventers) and associated choke and kill valves that control well pressure during drilling operations. Although diverters are not considered well control devices, their controls are often incorporated as part of the BOP control system. Control systems for drilling well control equipment typically use stored energy in the form of pressurized hydraulic fluid (power fluid) to operate (open and close) the BOP stack components. Each operation of a BOP or other well control component is referred to as a control function. The control system equipment and circuitry varies generally in accordance with the application and environment. Thus, six control system categories are addressed in this edition of RP 16E.

Drilling And Production Recommended Practices The size of all recommended practices in this group is 8 in. by 10-1/2 in. All are punched to fit stand three-ring binders. 811-09200 RP 48, Recommended Practice for Drill Stem Test Report Form, First Edition, February 1972, Reaffirmed 1990.

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Format lends itself to application of individual service company names and insignias while retaining the overall format of the standardized report form. 811-09210 RP 49, Recommended Practices for Safe Drilling of Well Containing Hydrogen Sulfide, Second Edition, April 1987. Prescribes safety recommendations and outlines safety guidelines and procedures developed within the petroleum industry for conducting inland or offshore drilling operations where hydrogen sulfide gas may be encountered. 811-09250 RP 53, Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells, Second Edition, May 1984. Supersedes API Bulletin D13, Installation and Use of Blowout Preventer Stacks and Accessory Equipment, February 1966. Describes arrangements of the mechanical equipment (surface and subsea installations) recommended for use to confine or control wellbore pressures during drilling and completion operations. Its purpose is to promote general acceptance of a limited number of blowout preventer stack arrangements and accessory equipment installation, both for improved well control and to keep blowout prevention equipment inventories at moderate levels. Recommendations for choke manifold systems, choke manifolds, kill lines, closing units, sealing components, and marine riser systems are included. Also included are recommendations for inspection and testing of blowout preventer modification for hydrogen sulfide service, and pipe stripping arrangements. A glossary of terms for blowout prevention equipment systems is also presented. 811-09285 RP 59, Recommended Practices for Well Control Operations, First Edition, August 1987. Describes guidelines and recommended procedures for safe well control operations and establishes recommended practices for installation and testing of equipment for the anticipated well conditions and service. Recommended operations are presented for retention of well pressure control under pre-kick conditions as well as recommended practices for use during a kick. Seven recommended well control work sheets are included for use in applying sitespecific parameters.

Special Publications 811-10000 Bull. D8, A Tabular Method for Determining the Change of the Overall Angle, and Dog-Leg Severity (for Hole Inclinations up to 70 degrees, September 1964, Reaffirmed January 1990). Tables cover bore hole inclination from vertical up to 70 degrees. For increments of 1/4 degree, updating and extending API Circ D-54 issued in 1961. Sample calculation shows how to use the tables. Spiral bound, 183 page booklet opens flat for maximum utility. Tables were compiled by Pan American Petroleum Corp. (Amoco Production Co.). 811-10200 Bull. D10, Procedure for Selecting Rotary Drilling Equipment, Second Edition, August 1973 (Reissued January 1982) Reaffirmed January 1990. Described a system of analysis to select a rig suitable for drilling a specific well, avoiding use of a rig that is either too large or too small. It is presumed that depth ratings alone are not definitive, because wells in different areas require emphasis on different rig functions. Procedures outlined provide a plan of analysis useful in determining performance capabilities of rig functions required for drilling a specific well and prescribe a means of testing,

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demonstrating, or rating the performance capability of components of a rig. 811-11000 Bull. E1, General Hazardous Chemical Category List and Inventory for the Oil and Gas Exploration and Production Industry, First Edition, October 1, 1989. Under Section 311 and 312 of the Superfund Amendments or Re-authorization Act of 1986, owners and operators of oil and gas exploration and production facilities must provide to state and local emergency response agencies information on hazardous chemicals they produce or use. This bulletin provides a simplified means of compliance of these regulations. 811-10720 Bull. D16, Suggested Procedure for Development of Spill Prevention Control and Countermeasure Plans, (To Assist Conformance to Requirements of Title 40, Code of Federal Regulations, Part 112) Second Edition, August 1, 1989. Presents suggested procedures for producing industry preparation and implementation of spill prevention control and countermeasure plans to comply with the requirements of Title 40, Code of Federal Regulations, Part 112, "Oil Pollution Prevention, Non-transportation Related Onshore and Offshore Facilities." A suggested model SPCC Plan is included which can be used in preparation of plans for non-transportation related onshore and offshore production facilities which could reasonably be expected to discharge oil into navigable waters of the United States. 811-10750 Bull. D19, Summary and Analysis of API Onshore Drilling Mud and Produced Water Environmental Studies, First Edition, November 1983. Summarizes, correlates, and discusses overall significance of four major scientific studies by independent investigators under API sponsorship during a nine-year period (19741982). Includes a strict summary of each principal investigator's research objective, methodology, results and conclusions. The studies, in chronological order, are: * 1974-1978. "Effects of Drilling Fluid Components and Mixtures on Plants and Soils," Dr. Raymond Miller, Utah State University. * 1979-1982. "Plant Uptake and Accumulation of Metals Derived from Drilling Fluids," Dr. Darrell Nelson, Purdue University. * 1980-1982. "Analysis of Hydrologic and Environmental Effects of Drilling Mud Pits and Produced Water Impoundments," Georgia Henderson,Dames & Moore. * 1981. "Water Base Drilling Mud Land Spreading and Use as a Site Reclamation and Re-vegetation Medium," James Whitmore, Forsgren-Perkins Engineering. These studies covered a large geographical area of the United States representing many different soil and climate regimes in a major oil and gas producing regions. Their study scopes addressed a wide range of environmental impacts including effects on soils, plant growth, metal uptake by plants, and ground waters. Adverse and beneficial effects were noted, and in addition, reclamation procedures were evaluated. 811-10850 Environmental Guidance Document: Onshore Solid Waste Management in Exploration and Production Operations, First Edition, January 15, 1989.

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Includes recommendations for the environmentally sound management of solid waste resulting from the exploration and production of oil and gas. Guidance is provided for the management of drilling fluids, produced waters, and other wastes associated with the operation of gas plants, field facilities, drilling, and workover.

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2. Hole and Pipe Data

Capacity Capacity of External Upset, EU, Drill Pipe

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Capacity of Tubing

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Capacity of Hole

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Capacity of Hole - Continued

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Capacity of Hole - Continued

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Capacity of Hole - Continued

Displacement of Hole and Pipe To facilitate making calculations the following table tabulates the displacement of various sizes of drill pipe. This can be subtracted from hole capacity tables (Section U1), using bit size, to determine annular volume per foot. The displacement of various weights of drill pipe have also been calculated on a per foot basis. Subtracting these from hole capacity gives volume of fluids per foot of hole. Multiplying these by depth involved will give the annular volume or total volume respectively.

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Displacement of Hole and Pipe

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Displacement of API Internal Upset,IU, Drill Pipe

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Displacement of API Internal Upset,IU, Drill Pipe - Continued

Displacement of Rotary Tool Joints

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Displacement of API External Upset, EU, Tubing

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Volume and Height between Pipe and Casing: Volume and Height between 2" Nominal (2-3/8" OD) Pipe and Casing

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Volume and Height between 2" Nominal (2-3/8" OD) Pipe and Casing - Continued

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Volume and Height between 2-1/2" Nominal (2-7/8" OD) Pipe and Casing

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Volume and Height between 2-1/2" Nominal (2-7/8" OD) Pipe and Casing - Continued

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Volume and Height between 3" Nominal (2-1/2" OD) Pipe and Casing

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Volume and Height between 3-1/2" Nominal (4" OD) Pipe and Casing

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Volume and Height between 4-1/2 OD" Pipe and Casing

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Volume and Height between 5 OD" Pipe and Casing

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Volume and Height between 5-1/2 OD" Pipe and Casing

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Volume and Height between 6-5/8 OD" Pipe and Casing

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Volume and Height between Pipe and Hole: Volume and Height between 2" Nominal (2-3/8" OD) Pipe and Hole

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Volume and Height between 2-1/2" Nominal (2-7/8" OD) Pipe and Hole

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Volume and Height between 3" Nominal (2-1/2" OD) Pipe and Hole

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Volume and Height between 3-1/2" Nominal (4" OD) Pipe and Hole

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Volume and Height between 4-1/2 OD" Pipe and Hole

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Volume and Height between 5 OD" Pipe and Hole

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Volume and Height between 5-1/2 OD" Pipe and Hole - Continued

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3. Field Gas Lines Pipeline Flow Of Gas Formulae And Conversions The following flow tables are primarily intended for use in lease work. They are based upon the Weymouth Formula, which is probably the most widely accepted because results obtained are very close to metered rates of flow. General Weymouth Formula:

where: Qs = Rate of flow of gas in cubic feet per 24 hours measured at standard conditions. d = Internal diameter of pipe in inches. P1 = Initial Pressure in pounds per square inch -- Absolute. (Upstream gage pressure + atmospheric pressure) P2 = Terminal Pressure in pounds per square inch -- Absolute. (Downstream gage pressure + atmospheric pressure) L = Length of line in miles. S = Specific gravity of flowing gas (Air = 1.0). T = Absolute temperature of flowing gas (°F + 460). Standard Conditions for Measurement: Ts = Standard Absolute Temperature (°F + 460). Ps = Standard Absolute Pressure in Pounds per square inch. Weymouth Formula Adaptation<2>

The following tables have been prepared to give the hourly rate of flow of 0.70 specific gravity gas flowing at 60°F and measured at a standard temperature of 60°F and at a standard pressure base of 14.4 psi + 4 oz gage pressure or 14.65 psi. Therefore, substitution of S = 0.7, Ts = 520°, T = 520° and Ps = 14.65 psi in the above formula was used to prepare the tables. Atmospheric pressure, assumed to be 14.4 psi, has been added to the Upstream and Downstream gage pressures to convert them to P1 and P2 which are absolute pressures.

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CONVERSIONS: Delivery values obtained from the gas flow tables may be adjusted for other than 0.70 sp. gr. (Air = 1.0) and 60°F flowing temperature by the use of multipliers. EXAMPLE: For 0.60 sp. gr. gas flowing at 20°F multiply the value taken from the flow tables by 1.12 selected from the table of multipliers below. Temperature - Specific Gravity Multipliers

To find the volume of gas delivered through any line of length 'L', multiply 1/{(L)0.5} by the volume given in a convenient flow table following, such as that headed 1000 Foot Line, 1 Mile Line or 10 Mile Line. Note: 'L' must be expressed as a multiple of the length heading the table in use. Example To determine the delivery from a 4500 foot line, multiply 1/{(4.5)0.5} by the volume tabulated for a 1000 mile line, or for a 2 mile line multiply 1/{(2)0.5} by the volume tabulated for a 1 mile line, and likewise for a 40 mile line multiply 1/{(4)0.5} by the volume tabulated for a 10 mile line.

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Gas Delivery, Based on 1000 Ft pipeline lengths Volume Of Gas Delivered -- 1000's CF/Hr* 1000 Foot Lines

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Multipliers To Convert 1000 Foot Line Values To Lengths Listed

+ Calculations are based upon listed inside diameters of the Standard Weight Threaded Line Pipe sizes shown. * Calculated from the Weymouth Formula for gas of 0.70 Specific Gravity (Air = 1.0), flowing at 60°F, and measured at a standard of 60°F. and 14.65 psi Absolute (4 oz. Gage). Local Atmospheric pressure is assumed to be 14.4 psi Absolute. For adjustment to other sp. gr. and temperature see sheet 40-110. Multiply the proper factor by the volume listed for a similar sized 1000 foot line. Example: A 3800 foot 2" line at 200 psi Upstream and 50 psi Downstream gage pressures would deliver (.51) (109.5) or 55845 cu. ft. per hour. Gas engines consume 10 to 15 cu. ft. of gas per horsepower hour. Uninsulated boilers consume 50 to 60 cu. ft. of gas per horsepower hour.

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Gas Delivery, Based on 1 Mile pipeline lengths Volume Of Gas Delivered -- 1000's CF/Hr* 1 Mile Lines

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Volume Of Gas Delivered -- 1000's CF/Hr* 2-1/2 Mile Lines

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Multipliers To Convert 1 Mile Line Values To Lengths Listed

+ Calculations are based upon listed inside diameters of the Standard Weight Threaded Line Pipe sizes shown. * Calculated from the Weymouth Formula for gas of 0.70 Specific Gravity (Air = 1.0), flowing at 60°F, and measured at a standard of 6°F and 14.65 psi Absolute (4 oz. Gauge). Local Atmospheric pressure is assumed to be 14.4 psi Absolute. For adjustment to other sp. gr. and temperature see sheet 40-110. Multiply the proper factor by the volume listed for a similar sized 1 mile line. Example: A 4 mile 2-1/2" line at 250 psi Upstream and 100 psi Downstream gauge pressures would deliver (.50) (89.21) or 44605 cu. ft. per hour. Gas engines consume 10 to 15 cu. ft. of gas per horsepower hour. Uninsulated boilers consume 50 to 60 cu. ft. of gas per horsepower hour.

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Gas Delivery, Based on 10 Mile pipeline lengths Volume Of Gas Delivered -- 1000's CF/Hr* 1 Mile Lines

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Multipliers To Convert 10 Mile Line Values To Lengths Listed

+ Calculations are based upon listed inside diameters of the Standard Weight Threaded Line Pipe sizes shown. * Calculated from the Weymouth Formula for gas of 0.70 Specific Gravity (Air = 1.0), flowing at 60°F., and measured at a standard of 60°F and 14.65 psi Absolute (4 oz. Gauge). Local Atmospheric pressure is assumed to be 14.4 psi Absolute. For adjustment to other sp. gr. and temperature see sheet 40-110. Multiply the proper factor by the volume listed for a similar sized 10 mile line. Example: A 6.6 mile 3" line at 100 psi Upstream and 75 psi Downstream gage pressures would deliver (1.23) (15.08) or 18548 cu. ft. per hour. Gas engines consume 10 to 15 cu. ft. of gas per horsepower hour. Uninsulated boilers consume 50 to 60 cu. ft. of gas per horsepower hour.

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4. Waterlines - Line Pipe Capacities APPROXIMATE LINE PIPE CAPACITIES FOR WATER Where inlet and outlet are at different elevations pressure should be added or subtracted, using the factor 0.433 times the difference in height in feet. After determining pressures corrected for elevation convert to Horse Power. Thus: (0.00048 x Pressure x Bbls/hr) = Hydraulic Horse Power, based on 85 % Efficiency. For engine or motor Horse Power add 20 - 25 percent.

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Table - V4-1. Pressure Loss Per 1000 Feet of Line and Horse Power Required

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5. Tank and Pit Capacity Pit Gain or Loss Tables

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Pit Gain or Loss Tables - Continued

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How To Calculate Capacities of Tanks (Pits), Dimensions in Feet 1. Rectangular

Area = L x W

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Cubic Feet= L x W x h Barrels= (L x W x h)/5.61 L = Length W = Width h = height of mud 2. Sloping Ends

Note: Length is measured from bottom at one end to line from top at other end. Cubic Feet= L x W x h Barrels= (L x W x h)/5.61 3. Sloping Ends & Sides

Note: Both length and width are measured from bottom at one hand to line from top at other hand. Cubic Feet= L x W x h Barrels= (L x W x h)/5.61 4. Cylindrical, Flat Ends

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Cubic Feet = .785 x D x D x h Barrels= 0.14 x D x D x h 5. Cylindrical, Dished Ends

Barrels = (0.14 x D x D x L) + (0.019 x D x D) 6. Hexagonal

Cubic Feet = 2.6 x S x S x h Barrels = 0.46 x S x S x h S = Side 7. Octagonal

Cubic Feet = 1.73 x D x D x h Barrels = 0.13 x D x D x h Diagonal = D 8. Spherical

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Cubic Feet = 0.523 x D x D x D Barrels = 0·093 x D x D x D 9. Spherical, Partially Filled

Cubic Feet = 0.000303 x h x h x (3D-2h) Barrels = 0·000054 x h x h x (3D-2h) Gallons = 0.000227 x h x h x (3D-2h) 10. Well Bore Barrels per 1000 feet is approximately equal to inches of wellbore diameter squared.

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6. Conversion Factors The international System of Units (SI for short) is a modernized version of the metric system. It is built upon six base units and two supplementary units. Symbols for units with specific names are given in parentheses. The information in this Data Sheet, adapted from the revised "Metric Practice Guide," Standard E380-68, 1969 Book of ASTM Standards, Part 30, includes a selected list of factors for converting U.S. customary units to SI units.

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Metric Conversion Factors

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Table of Conversion Factors

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Decimal and Metric Equivalents of Inch Fractions - Continued

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Fractions, Inches to Decimals of a Foot

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Flow Rate Conversions

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Flow Rate Conversions - Continued

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7. Density of Oilfield Materials and Wood MATERIAL

DENSITY, PCF

Alcohol

50

Aluminum

168

Babbit Metal

443

Books (Solid Pack)

65

Brass

511-536

Brick

112

Brick (Fire)

140

Cement, Portland (Loose)

94

Coal (Loosely Piled)

40-58

Concrete (Stone & Gravel)

150

Copper

555

Diesel Fuel

55.3

Dry Rubble Rock

1

10-130

Earth (Loose)

80

Earth (Packed)

105

Gasoline

41-43

Gravel

80-120

Ice

57.2

Iron (Cast)

450

Kerosene

51

Lime (Slaked)

103-111

Lye, Soda 66% (Caustic)

106

Mercury

847

Muriatic Acid 40%

75

Oils, Lubricating

58

Petroleum, Crude - 29°API

55

Plaster of Paris

74-80

Rags (Compressed Bales)

19

Salt (Ground in Sacks)

60

Sand

90

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MATERIAL

DENSITY, PCF

Snow (Fresh Fallen)

8

Snow (Loosely Piled)

35

Steel

489

Stones

75-87.4

Water

62.4

Wood

lbs/bd.ft

1. Fir

2.5-3.7

2. Hickory

4.0

3. Oak, Live

4.9

Oak, Seasoned

3.5 - 3.8

4. Pine - Oregon

2.7

Red

2.5

White

2.3

Yellow

3.2-3.7

5. Redwood

2.3

6. Spruce

2.5-2.7

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8. Density of Fluids and Petroleum Products Fluids and Petroleum Products

Density , ppg

Acid - Hydrochloric (Muriatic) 10% Solution

8.7

15% Solution

8.9

20% Solution

9.2

25% Solution

9.4

30% Solution

9.6

40% Solution

10.0

Alcohol

5

Acid - Sulfuric -

66 ° Be - 93 % 15.3

Alcohol - Grain -

95%

6.7

Brines - Calcium Chloride

40%

11.3

Salt (Saturated)

10.0

Caustic Soda (Lye) 10% Solution

9.2

20% Solution

10.2

30% Solution

11.1

40% Solution

11.9

50% Solution

12.7

66% Solution

14.2

Glycerine

10.5

Glycol (Anti-Freeze)

9.3

Petroleum Products

ppg

Burner Fuel, Heavy 15 °API

8.0

Diesel Fuel 29-31 °API

7.3

Gasoline 60-70 °API

5.8-6.1

Kerosene 42-44 °API

6.7

Lube Oils, Light 26-27 °API

7.4

Medium 20-26 °API

7.5

Heavy 20-24 °API

7.7

Water

8.33

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9. Soil Bearing Capacity Kinds of Soil

Safe bearing capacity, tons per sq. ft.

Solid ledge of hard rock

25 to 100

Sound shale and other medium rock,

10 to 15

requiring blasting for removal Hard pan, cemented sand and gravel,

8 to 10

difficult to remove by picking Soft rock, disintegrated ledge; in natural

5 to 10

ledge, difficult to remove by picking Compact sand and gravel, requiring

5 to 6

picking for removal Hard clay, requiring picking for removal

4 to 5

Gravel, coarse sand, in natural thick beds

4 to 5

Loose medium and coarse sand, fine dry sand

3 to 4

Medium clay, stiff but capable of being spaded

2 to 4

Fine wet sand, confined

2 to 3

Soft clay

1

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Chapter Y: Solids Control Removal

Chapter Y Drilling Mud Processing

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Table of Contents - Chapter Y Drilling Mud Processing 1. Introduction - Solids Control Removal Systems ..................................................................................... Y-4 A. Overview ....................................................................................................................................... Y-4 B. Solids Removal Theory ................................................................................................................. Y-5 C. Equipment Arrangement ................................................................................................................. Y-9 II. Solids Control Equipment ................................................................................................................... Y-11 A. Shale Shakers .............................................................................................................................. Y-11 B. Degassers .................................................................................................................................... Y-26 C. Hydrocyclones ............................................................................................................................. Y-30 D. Mud Cleaners .............................................................................................................................. Y-39 E. Centrifuges ............................................................................................................................... Y-50 III. Surface Circulating Equipment ........................................................................................................... Y-55 A. Introduction ................................................................................................................................. Y-55 B. Considerations and Methods for Sizing Surface Mud Systems ....................................................... Y-55 C. Special Considerations ................................................................................................................. Y-56 D. Sizing Steel Pits ............................................................................................................................ Y-57 E. Earthen Pits .................................................................................................................................. Y-58 F. Reserve and/or Waste Pits ............................................................................................................ Y-59 4. System Rig-up Information .................................................................................................................. Y-61 A. Solids Control System Layout Considerations ............................................................................... Y-61 B. Centrifugal Pump Selection and Piping Design ............................................................................... Y-70 C. Mud Troughs After the Shale Shakers .......................................................................................... Y-88 Index - Section Y - Solids Removal Systems ........................................................................................... Y-91

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Chapter Y: Solids Control Removal

Chapter Y Solids Control Removal The IADC Drilling Manual is a series of reference guides for use in field operations covering a variety of subjects related to drilling operations. The contents of this (these) volume (s) are assembled by a wide range of members of the drilling industry interested in providing information to field personnel to encourage proper operations, maintenance and repair of equipment and training and safety of personnel. It is not intended that the contents of this manual replace or take precedence over manufacturer's, operators or individual drilling company recommendations, policies and/or procedures. In those areas where local, state and federal law is in conflict with the contents then it is deemed appropriate to adhere to suer laws. IADC has endeavored to insure the accuracy and reliability of this data, however, we make no warranties or guarantees in connection with these recommendations. As technology continues to develop this manual will be updated. It is important that the user continue to update their knowledge through research and study. The following industry representatives have contributed to the development and updating of this chapter: MEMBERS OF THE TASK GROUP: Robert Bennett - Milpark Drilling Fluids Roger DeSpain - Premier, Inc. Charles Girchar - SWECO Oilfield Services William Halliday - Milpark Drilling Fluids Mike Montgomery - SWECO Oilfield Services Ron Morrison - Derrick Equipment Co. Janice Skalnik - SWECO Oilfield Services SWECO Oilfield Services has permitted IADC the use of its Solids Control Handbook for text development. In addition, the artwork contained in Section III was provided by SWECO Oilfield Services.

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1. Introduction - Solids Control Removal Systems A. Overview 1. History Drilling fluid maintenance costs, as well as overall well costs, can be reduced dramatically when proper solids control techniques are utilized. This fact has been recognized since the mid 1800's when the first recorded oil wells were drilled. Early-steam powered pumps were used to circulate the drilling fluid which when returned to the surface loaded with drilled solids flowed into a ditch and subsequently into a settling pit where the solids settled out. The clean or partially clean mud then flowed into a suction pit to be recirculated downhole. This simple solids control technique is still used in some shallow oil basins today. The next innovation in solids control came when shale shakers were introduced in the early 1930's to help retain weight material or barite in the drilling fluid. This technology was derived from the mining industry where vibrating screens were used for coal classification. The shale shaker remains today the primary piece of solids control equipment on the rig. Another ore classifying machine borrowed from the mining industry in the 1930's was the cone classifier, or hydrocyclone. The basic principle of this device involves the centrifugal forces brought about by the high velocity of the drilling fluid spinning in the cone forcing the larger and heavier solids to settle outward toward the cyclone wall and downward toward the underflow solids discharge. Together with the shale shaker, hydrocyclones have become an integral part of current solid control system. In the early 1950's, the next piece of solids control equipment introduced to the drilling industry was the centrifuge. The centrifuge was used to remove colloidal sized solids from the drilling mud, thus reducing viscosity. Bigger and higher speed centrifuges have subsequently been utilized for processing greater volumes and removal of smaller sized solids.

2. State Of The Art The state of the art in solids control systems includes improved versions of the standard equipment traditionally found on a drilling rig including high performance shakers, hydrocyclones, mud cleaners, and centrifuges. In addition, the increased interest in running closed loop systems has resulted in the introduction of dewatering technology to the industry. This involves taking excess mud from either dilution or effluent from conventional solids control equipment for further processed using chemically enhanced separation technology. State of the art in centrifuges appears to be high speed (3200 rpm) or high volume decanter type centrifuges made of stainless steel with tungsten carbide wear protection. Specialized solids control equipment to remove hydrocarbons from oil based mud include thermal distillation and solvent extraction technologies. Improvements in rig mixing equipment include high shear mixing devices for faster polymer solubilization and hydration.

3. Future The future path of solids control systems will continue to increase the overall removal efficiency of undesirable solids from drilling fluid systems. This will include continued improvements in shale shakers and screen life. Research investigating alternate technology such as using vacuum techniques and different motions may prove more efficient in the future.

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Chapter Y: Solids Control Removal

The continuing trend of more stringent environmental regulations around the world will drive the research for improved methods for cleaning oil based mud cuttings and the improvement of closed loop mud systems to minimize or eliminate haul off of drilling wastes.

B. Solids Removal Theory Drilling fluid maintenance costs can decrease greatly when proper solids control techniques are utilized. From a fluid control standpoint, it would be desirable in most cases to remove all drilled solids. Although this is possible with the use of chemical enhancement prior to separation, it is not always the most economical approach. The goal of a solids control system is to achieve the balance between mechanical solids separation and dilution that will result in drill solids being maintained at an acceptable level with the minimum cost.

1. Particle Sizes And Effects Drilling fluids are classified as water-base or oil-base with most systems utilizing water as the liquid phase. Oilbase muds employ oil as the continuous liquid phase and are generally more expensive than waterbase muds. The solids phase of any drilling mud are two basic types: a) Commercial solids; and b) Drilled solids. Most commercial solids, with the exception of barite and lost circulation material, have a relative particle size of less than one micron (.000039 inches). Barites generally have a size range of 1 to 74 microns with approximately 45% being less than 14 microns in size. API standards require at least 97% by weight of barites pass through a 74 micron opening (200 mesh) and not more than 95 % pass through a 44 micron opening (325 mesh screen). Lost circulation materials are available in a wide range of sizes but are considerably larger than barite. Barite, lost circulation materials and other commercial solids such as bentonite, lignite, and starch are available from the mud companies and are added to the mud system to obtain certain desired properties and perform certain functions. Drilled solids are those particles that enter a mud system in the form of cuttings from the bit; or as formation particles that slough or fall into the annulus. These solids vary in size from less than 1 micron to over 2000 microns and reflect the composition of the formation being drilled and shape of the bit teeth. A bit having large teeth will produce relatively large cuttings whereas button-head bits produce extremely fine particles. NOTE: Rotary speed and weight on bit are also factors which contribute to particle size. Solids in drilling fluids can be separated essentially into two density groups, high and low specific gravities. High specific gravity will refer to those solids with a specific gravity of 4.2 and above. The most commonly used for density increases are barite, which is 4.2, and hematite, which is 5.0. Low specific gravity solids may range from a low of 1.1 for lignite to 2.9 for dense lime. 2.6 is normally used in solids analyses as the average specific gravity of drilled solids. One of the most important objectives in solids control is to remove as many of the larger particles as is practical the first time that these solids are circulated to the surface. This requires properly designed and installed mechanical treating equipment sized to process at least 100-125 % of the mud circulation rate. Solids that are not removed during the first circulation through the surface equipment are subjected to mechanical degradation by the drill bit and mud pump during each circulation cycle until they are too fine for removal by mechanical means. Breaking down a large particle into hundreds of fine particles increases the surface area of the particles and requires adding liquid to the mud system to accommodate the increase. In order to evaluate the removal capabilities of the various pieces of mechanical treating equipment, it is necessary to consider the source of said solids and classify them according to size as follows: (.001 inches = 25.4 microns) 440 microns and larger - large drilled solids (cuttings)

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74 to 440 microns - sand 2 to 74 microns - silt 0.5 to 2 microns - clay 0.5 micron and smaller - colloids All solids in the colloidal range are not detrimental to a mud system: Some finer particles in the colloid range are necessary for building a thin, slick wall cake in the borehole and reduce the possibility of differential pressure sticking of the drill string. However, it is highly important that drilled solids are removed the first time they are circulated to the surface or they would eventually degrade to a colloid size by continuous circulation through the mud pumps, drill pipe, bit jets, bit teeth, etc. As an example, one particle having a diameter of 100 microns will become 125,000 particles with a diameter of 2 microns and require 50 times as much liquid to coat the surface of this same mass of drilled solids without any reduction in solids concentration. This thickening process, occurring without an absolute increase in solids concentration, is referred to as viscosity or the resistance to flow. Adding water or oil to the system reduces the concentration of those solids, thus reducing the viscosity. Removal of drilled solids during the early circulation stages with solids removal equipment at the surface is much more simple and less expensive. Water-soluable chemicals, such as lignites, lignosulfonates, phosphates, quebracho, may be added to the water phase to control the extremely fine clays in the mud. Also, some flocculants are effective in agglomerating many fine solids into one large floc that can be removed by settling in the tanks or by removal equipment.

2. Benefits Of Low Solids Mud 1. Increased drilling penetration rate. 2. Increased bit life. 3. Reduced mud costs. 4. Reduced main mud pump maintenance cost. 5. Reduced differential pressure sticking. 6. Bore-hole is closer to gauge. 7. Reduced water dilution. 8. Increased cementing efficiency. 9. Increased accuracy of geological information retrieved from wellbore. 10. Reduced drill pipe torque. 11. Increased control of mud properties. Obviously, these benefits are the result of planning prior to drilling a well and are accomplished through the use of properly designed, sized and operated solids removal equipment. It is the obligation of the drilling crew to become knowledgeable in the proper use of the equipment; otherwise, its potential benefits may he reduced or nullified.

3. Methods Of Controlling Solids 1. Mechanical treatment. 2. Chemical treatment.

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Chapter Y: Solids Control Removal

3. Dilution of whole mud. 4. Jetting or discarding whole mud. Each of the above methods is effective at the proper time and place; however the last two categories are quite often employed due to lack of planning when mechanical treatment would be more effective and economical; especially during the early phases of the drilling program. 3.A. MECHANICAL TREATMENT This is the method of mechanically removing solids using shale shakers, desanders, desilters, mud cleaners and centrifuges with each piece of equipment generally limited to the following range of particle removal: 1. Standard Shale Shaker - 440 microns and larger. 2. Fine Screen Shaker - 74 microns and larger (weighted muds). 44 microns and larger - (unweighted muds). 3. Mud cleaner - 74 microns and larger (weighted muds). 44 microns and larger(unweighted muds) 4. Desanders - 100 microns and larger. 5. Desilters - 15 microns and larger. 6. Centrifuge - 4 to 8 microns and smaller (weighted muds); 4 to 8 microns and larger (unweighted muds). Each piece of mechanical equipment is effective within a certain particle size range. Utilizing all of the above items throughout a drilling program will produce maximum benefits without overloading any one piece of equipment. None of the above items will take the place of another piece of equipment; however no piece of equipment operating at optimum efficiency should cause downstream equipment becoming overloaded. Removing solids from spud of a drilling program is a first priority in solids control as it is much easier to remove one particle 100 microns in diameter with a fine screen shaker than to attempt to remove 125,000 particles of 2 micron size with a centrifuge. In unweighted water-base muds, the fine screen shaker, desander and desirer are generally used until the point of adding barites. Centrifuges are added to increase drilled solids removal. With weighted waterbase muds and all oil base muds, fine screen shaker, mud cleaner and centrifuge are utilized. B. CHEMICAL TREATMENT Chemical treatment of a water-base mud for solids removal involves adding a "flocculant" to the mud system. This causes extremely fine solids to agglomerate together in order to be removed mechanically or allowed to settle by gravity in the mud tanks. Normally, flocculant is used in conjunction with mechanical treatment. For example, flocculants can be added at the shaker screen to increase apparent particle size. Polymer flocculant may also be injected into the centrifuge feed to improve centrifuge performance. Deflocculants such as lignosulfonates may be added to a water base mud to increase the solids tolerance of the fluid. These "thinners" allow more solids to be incorporated into the mud before viscosity becomes too much of a problem.

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C. DILUTION OF WHOLE MUD Dilution of whole mud requires the addition of water or oil as a means to thin the mud. This increases the volume of whole mud while retaining all of the drilled solids and, in effect, reduces the solids concentration and viscosity to some degree. D. JETTING OR DISCARDING WHOLE MUD This is a simple means of discarding a certain amount of whole mud because of excessive volume in the system, generally caused by severe solids contamination or dilution. Jetting whole mud allows some solids to be discarded with the liquid phase, but only at the same concentration as the liquid/solids ratio of the whole mud. Therefore, jetting is a very expensive method of reducing solids concentration as the removal of 80 barrels of whole mud reduces the solids volume of a 2000 barrel system by only 4 percent.

4. Mechanical Separation - Basics Mechanical separation equipment employs mass differences, size differences, or a combination of both to selectively reject undesirable solids and retain desirable solids in a drilling fluid. The desander, desilter, and centrifuge utilize centrifugal force and mass difference between the solids density and liquid density for solids removal. The shale shakers and mud cleaners employ a vibrating screen of various micron-sized openings to selectively classify particles by size difference. The centrifuge is limited to treating only a portion of the total mud circulating rate while the other equipment is sized to process at least 100-125 percent of the rig circulating rate. A standard rig shaker or a fine screen shaker is vital to solids control and should process all of the mud returning through the flow line since any particles will degrade to such a degree that concentration and viscosity will be difficult and expensive to control. A standard rig shaker performs adequately for small rigs operating at shallow depths with low solids native mud; however, fine screen shale shakers are generally more efficient and represent the latest technique of screen support, screen motion, vibratory design and other desirable features. Located directly downstream from the shale shaker are the desander and desirer solids removing equipment (unweighted water-based muds). These should be sized to process at least 125% of the rig circulation rate while discarding undesirable cuttings and solids down to the 50 micron size range when used in series. The desander removes the majority of the solids down to the 100 micron size range and prevents the desilter from being overloaded. The desilter removes the majority of solids down to the 15 micron range. Liquid loss from desanding and desilting an unweighted water-based mud is relatively insignificant compared to the amount of whole mud jetted to remove the same amount of solids unless you are drilling in an environmentally sensitive area. When drilling with a weighted water-based mud, or an unweighted oil-based system, the desander and desilter cannot be economically utilized because they would tend to discard the valuable barite from a weighted mud and lose the expensive liquid phase in an oil-based system. Therefore, a fine screen shaker or mud cleaner is employed to remove solids down to 74 microns. It is important that all of the mud be processed by a fine screen shaker even though most of the solids smaller than the screen mesh will be returned to the active mud system. This process of screening and allowing some fine particles to return to the active system is desirable when the alternatives are considered: 1. Removing no solids in this range. 2. A significant loss of barite and liquid. Shale shakers and fine screen shakers, operated under optimum conditions, will produce a relatively clean mud; however, a centrifuge may be required in several instances where: 1. A hard formation is being drilled.

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Chapter Y: Solids Control Removal

2. Diamond bits are being used. 3. Used mud, containing drilled solids, is added during the drilling process. 4. Improperly operated and maintained solids removal equipment being used. 5. The shale shaker has been bypassed. 6. The mud has been used for several months and a build-up of fine degraded particles has occurred. 7. Unweighted systems with expensive liquid phase are required. 8. Environmental constraints are a factor.

5. Summary - Effective Solids Control 1. Obtain solids removal equipment from a reputable manufacturer and size it to process mud at the manufacturer's recommended capacity. The process rate should be 100-125% of the maximum rig circulating rate except for the centrifuge. 2. Remove as many drilled cuttings as possible the first time they are circulated to the surface. 3. Do not bypass the shale shaker or other equipment if at all possible. 4. Use of the smallest screen mesh possible on the shale shakers. 5. Maintain an adequate inventory of recommended spare parts. 6. Assign rig personnel on each tour to be responsible for equipment operation and maintenance.

C. Equipment Arrangement Depending on whether the mud system is unweighted or weighted different solids control arrangements will be utilized. In addition, if the situation requires a closed loop mode or oil based system, the solids control arrangement may differ.

1. Unweighted Water Base -- Pit System When using an unweighted water base mud system the ideal solids control arrangement includes fine screen shakers, two 10"-12" cone desanders, sixteen 4" cone desilters, degasser, and centrifuge. If drilling in very high penetration rate area such as offshore Gulf Of Mexico a scalping rig shaker arrangement may be required.

2. Weighted Water Base -- Pit System When using a weighted drilling fluid, the equipment arrangement is similar to the unweighted water base system. However, in a weighted mud situation the desander and desilter normally cannot be economically utilized since they would tend to remove valuable barite from the system. Mud cleaners can be utilized if 150 mesh screens can not be run on the shakers or the API sand content is 0.5% or higher. The centrifuge is arranged opposite of an unweighted system, returning the heavy solids or barite to the active system and discarding the liquid phase containing the fine, colloidal solids.

3. Unweighted Oil Base - Pit System The equipment used is the same as for an unweighted water base mud system except the underflow from the hydrocyclones is routed to a fine screen shaker for further processing.

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4. Weighted Oil Base - Pit System The primary equipment needed for a weighted oil base system includes fine screen shakers, degasser, and two centrifuges. The second centrifuge is used to process the overflow from the barite recovery centrifuge (containing liquid and fine solids) to recirculate liquid containing solids less than two microns and discarding the relatively dry underflow. 5. Unweighted Water Base - Closed Loop Mode In addition to the standard solids control equipment this layout utilizes dewatering equipment which uses chemically enhanced separation technology to further process excess mud. Multiple drying shakers are also used to further process overflow from the primary scalping and high speed shakers as well as underflow from the hydrocyclones. This process results in all solids being removed from the waste drilling mud while the liquid portion is recycled back to the active system. Ideally all other liquid wastes generated on location are processed and also recycled thus negating the need for a reserve pit.

6. Weighted Water Base - Closed Loop Mode The arrangement for a weighted water base system is similar to the unweighted system except the fluid processed by the dewatering equipment originates from the underflow of the barite recovery centrifuge as opposed to active mud or underflow from the hydrocyclones. Ideally all other liquid wastes generated on location are processed and also recycled thus negating the need for a reserve pit. These closed loop modes are normally utilized due to environmental regulations, with small locations, where reserve pit space is limited, where water is in short supply, or where recycling the liquid phase is economically advantageous.

7. Unweighted Oil Base - Closed Loop Mode - Cuttings Wash A closed loop system using cuttings wash technology is used where oil base mud cuttings can be discharged overboard, eg. certain sectors of the North Sea or in other, similar environmentally sensitive areas. Scalping shakers, drying shakers and conventional solids control equipment are utilized. In addition, a cuttings wash system is used to clean the cuttings of hydrocarbons to allow discharge within the required guidelines. These requirements are typically less than 10% by weight hydrocarbon for the North Sea.

8. Weighted Oil Base - Closed Loop Mode - Cuttings Wash A closed loop mode with cuttings wash technology is used with a weighted oil base mud when only washed cuttings are desired for discharge. All liquids are recycled back to their respective active systems. Scalping shakers, drying shakers, a cuttings wash system, and conventional solids control equipment are utilized in this set up.

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Chapter Y: Solids Control Removal

2. Solids Control Equipment A. Shale Shakers 1. Separation By Vibratory Screening One method of removing solids from drilling mud is to pass the mud over the surface of a vibrating screen. Particles smaller than the openings in the screen pass through the holes of the screen along with the liquid phase of the mud. Particles too large to pass through the screen are thereby separated from the mud for disposal. Basically, a screen acts as a "go--no-go" gauge: Either a particle is small enough to pass through the screen opening or it is not. a. Screening Surfaces. Screening surfaces used in solids control equipment are generally made of woven wire screen cloth, in many different sizes and shapes. The following characteristics of screen cloth are important in solids control applications. Screens may be constructed with one or more LAYERS. NON-LAYERED screens have a single screen cloth mounted in a screen panel. These screens will have openings that are regular in size and shape. LAYERED screens have two or more screen cloths, usually of different mesh, mounted in a screen panel. These screens will have openings that vary greatly in size and shape. A comparison of these two screen types is shown in Figure Y2-1.

Figure Y2-1 Comparison of Single and Multi-layer Screens

1. MESH Mesh is defined as the number of openings per linear inch. Mesh can be measured by starting at the center of one wire and counting the number of openings to a point one inch away. Figure Y2-2 shows a sample 8 mesh screen.

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Figure Y2-2 Eight Mesh Screens

2. SIZE OF OPENING Size of opening is the distance between wires in the screen cloth and is usually measured in fractions of an inch or microns. Figure Y2-3 shows a screen with a 1/2 inch opening. Figure Y2-3 One-half Inch Opening

A screen counter (see Figure Y2-4) is useful to determine screen mesh.

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Chapter Y: Solids Control Removal

Figure Y2-4 Screen Mesh Counter and Magnified View of Screen

Screens of the same mesh may have different sized openings depending on the diameter of the wire used to weave the screen cloth, as shown in Figure Y2-5. Figure Y2-5 Opening Size and Percent Open Area

Smaller diameter wire results in larger screen openings larger particles passing through the screen. The larger the diameter of the wire, the smaller the particles that will pass through the screen. Remember: It's the size of the openings in a screen, not the mesh count, that determines the size of the particles separated by the screen. 3. PERCENT OF OPEN AREA Percent of open area is the amount of the screen surface which is not blocked by wire. The greater the wire diameter of a given mesh screen, the less open space between the wires. For example, a 4 mesh screen made of thin wire has a greater percent of open area than a 4 mesh screen made of thick wire (see Figure Y2-5). The open area of a non-layered, square or oblong mesh screen can be calculated by using the formula: P = O x o/(O +D)(o + d) x 100 where: P = percentage of open area O = length of opening in one dimension

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o = length of opening in the other dimension D = diameter of wire perpendicular to the O dimension d = diameter of wire perpendicular to the o dimension The higher the percent of open area of a screen the greater its theoretical throughput. Open area can be increased for a given mesh by using smaller diameter wire, but at the sacrifice of screen life. The choice of any particular screen cloth therefore involves a compromise between throughput and screen life. Calculating the percent open area for layered screens is difficult and inaccurate. This is due to the random and wide variety of openings present. 4. CONDUCTANCE Conductance of a screen is an experimental measure of the flow capacity of a screen that is gaining acceptance in the field. The higher the conductance of a screen, the greater its flow capacity. 5. SHAPE OF OPENING Shape of opening is determined by the screen construction. Screens with the same number of horizontal and vertical wires per inch produce square shaped openings and are referred to as SQUARE MESH screens. Screens with a different number of horizontal and vertical wires per inch produce oblong- or rectangular-shaped openings and are referred to as RECTANGULAR (or OBLONG) MESH screens. This is illustrated in Figure Y2-6. Figure Y2-6 Comparison of Square and Oblong Screens

Use of a single number in reference to a screen usually implies square mesh. For example, "20 mesh" usually identifies a screen with 20 openings per inch in either direction. Oblong mesh screens are generally labeled with two numbers. For example, a 60 x 20 screen has 60 openings per inch in one direction and 20 openings per inch in the other direction. It is common industrial practice to add the two dimensions of an oblong mesh screen and refer to the sum of the two numbers as the mesh of the screen. This practice is confusing and inaccurate. For example, a 60 x 20 mesh screen is often called an "oblong 80" mesh. This screen has oblong openings measuring 1040 x 193 microns, much larger than the square openings of a "square 80" mesh screen (177 x 177 microns). The "oblong 80" will allow much larger, irregularly-shaped particles to pass through its openings than the 80 x 80 square mesh screen.

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In a similar fashion, a layered screen will often be designated by a single number, e.g. "layered 210" mesh. This implies a screen with openings smaller than a "square 200" mesh screen (74 x 74 microns). However, the actual opening size and shape of layered screen is a combination of the multiple screen layers and will produce a wide variety of opening sizes and shapes, as shown in Figure Y2-2. Therefore, the "layered 210" mesh screen will remove some solids smaller than 74 microns, but will also allow many particles larger than 74 microns to pass through the screen openings. There are several types of wire cloth used in the manufacture of oilfield screens. The most common of these are MARKET GRADE and TENSILE BOLTING CLOTH. Both of these are square mesh weaves, differing in the diameter of wire used in their construction. Market grade cloths use larger diameter wires and are more resistant to abrasion and premature wear. Tensile bolting cloths use smaller diameter wire and have a higher conductance. In addition, some manufacturers provide proprietary screen cloths to provide specific separation vs. capacity characteristics. Since screen selection is a compromise between screen life, liquid capacity, and particle separation, all three types may be offered by shaker manufacturers. 6. STANDARDIZATION Standardization of screen cloth designations has been recommended by the API committee on Standardization of Drilling Fluid Materials, in API Bulletin 13C published in 1974. Under the API recommendation, a 30 mesh square opening screen with openings 516 microns wide and 37.1 percent open area would have a designation of 30 (516, 37.1). A rectangular mesh screen with mesh counts of 70 x 30, openings of 160 x 500 microns, and open area of 33.5 percent would have a designation of 70 x 30 (160 x 500, 33.5). Many screen types introduced since 1974 are not adequately described by the standard; it is clear that current screen designations are not acceptable or meaningful to end users. In this regard, an API Work Group is developing a standard method to include these newer screen designs. This work has not been completed, but it appears the information required to meet the standard will include the manufacturer's designation, the cut point (D50, D16, and D84), screen conductance, and total non-blanked screen panel area. b. Vibrating mechanism. The purpose of vibrating the screen in solids control equipment is to tumble the solids particles and increase throughput capacity. This vibrating action causes rapid separation of whole mud from the oversize solids, reducing the amount of mud lost with the solids. For maximum efficiency, the solids on the screen surface must travel in a predetermined pattern. For example, some devices are designed to move solids in a spiral pattern around the screen in order to increase particle separation efficiency and reduce blockage of the screen openings. Others use elliptical, orbital, or linear motion to increase efficiency. The combined effect of the screen and the vibration result in the separation and removal of oversized particles from drilling mud.

2. Shale Shakers The first line of defense for a properly maintained drilling fluid has been, and will continue to be, the shale shaker. Without proper screening of the drilling fluid during this initial removal step, reduced efficiency and effectiveness of all downstream solids control equipment on the rig is virtually assured. The shale shaker, in various forms, has played a prominent role in oilfield solids control schemes for several decades. Shakers have evolved from small, relatively simple devices capable of running only the coarsest screens to the models of today. Modern, high-performance shakers of today are able to use 100 mesh and finer screens at the flowline in most applications.

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This evolutionary process has taken us through three distinct eras of shale shaker technology and performance. These eras of oilfield screening development may be defined by the types of motion produced by the machines: Elliptical, "unbalanced" design Circular, "balanced" design Linear, "straight-line" design The unbalanced, elliptical motion machines have a downward slope as shown in Figure Y2-7A. Figure Y2-7a Elliptical, "unbalanced" design shale shakers

This slope is required to properly transport cuttings across the screen and off the discharge end. However, the downward slope reduces fluid retention time and limits the capacity of this design. Optimum screening with these types of shakers is usually in the 30-40 mesh (400-600 micron) range. The next generation of machine, introduced into the oilfield in the late 1960's and early 1970's, produces a balanced, or circular, motion. The consistent, circular vibration allows adequate solids transport with the basket in a flat, horizontal orientation, as shown in Figure Y2-7B.

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Figure Y2-7B Circular, "balanced" design shale shakers

This design often incorporates multiple decks to split the solids load and to allow freer mesh screens, such as 80100 square mesh (150-180 micron) screens. The newest technology produces linear, or straight-line, motion, Figure Y2-7C. Figure Y2-7c Linear, "straight-line" design shale shakers

This motion is developed by a pair of eccentric shafts rotating in opposite directions. Linear motion provides superior cuttings conveyance and is able to operate at an uphill slope. Better conveyance and longer fluid retention allow the use of 200 square mesh (77 micron) screens. Today, shale shakers are typically separated into two categories: Rig Shakers and Fine Screen Shakers.

3. Rig Shakers The rig shaker is the simpler of two types of shale shakers. A rig shaker (also called "Primary Shale Shaker" or "Coarse Screen Shaker") is the most common type of solids control equipment found on drilling rigs. Unless it is replaced by a fine screen shaker, the rig shaker should be the first piece of solids control equipment that the mud flows through after coming out of the hole. See Figure Y2-8.

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Figure Y2-8 Rig Shakers

It is inexpensive to operate and simple to maintain. Standard rig shakers generally have certain characteristics in common (see Figure Y2-9). Figure Y2-9 Rig Shaker Components

* Single rectangular screening surface - usually about 4' x 5' in size.

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* A low-thrust horizontal vibrator mechanism, using eccentric weights mounted above, or central to, the screen basket. * Vibration supports to isolate the screen basket from its skid. * Skid with built-in mud box (sometimes called a "possum belly") and a bypass mechanism. * Means of tensioning screen sections. Some designs have utilized dual screens, dual decks and dual units in parallel to provide more efficient solids separation and greater throughput. Depending on the particular unit and screen mesh used, capacity of rig shakers can vary from 100 - 1600 gpm or more. Screen sizes commonly used with rig shakers range from 10 to 80 mesh. Figure Y2-10 shows the particle sizes separated by these mesh screens. Figure Y2-10 Particles Removed by Rig Shaker Screens

In this graph, the area to the left of each line represents solids which are smaller than that mesh size. These would pass through the screen and would not be removed. The area to the right of each line represents solids that are larger than the mesh size and would be removed from the mud. In Figure Y2-10, the area to the right of the 10 mesh line is small, because it was cut off. In actual usage, this area is unlimited. This means that a 10 mesh screen will remove all particles larger than 1910 microns -- it doesn't matter if they are the size of BB's, marbles or baseballs -- they will be removed and discarded by a 10 mesh screen. Rig shakers normally require minimum maintenance. Other than periodic greasing, the following should be done while making a trip: * Wash down screens.

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* Check screens for proper tension. * Shut down shaker when not drilling in order to extend screen life. * Dump and clean possum belly. * Clean the tension rails. * Inspect rubber screen supports for wear. MOST IMPORTANT: Install replacement screens properly; square on the deck, with even tension according to the manufacturer's recommendations. Rig shakers are generally adequate for top hole drilling and for shallow and intermediate depth holes when backed up by other solids control equipment. For deeper holes and when using expensive mud systems, fine screen shakers are preferred.

4. Fine Screen Shakers The fine screen shaker is the more complex and versatile of the two types of shale shakers. Fine screen shakers remove cuttings and other larger solids from drilling mud, but are designed for greatly improved vibratory efficiency over simple rig shakers. They are constructed to vibrate in such a way that they can use screens as fine as 150 - 200 mesh and still give reasonable screen life. A fine screen shaker can be installed on the rig in several ways: * Instead of the conventional rig shaker for use from top hole to total depth, if it is of a design capable of using coarse screens as well as fine screens. * Placed in series with the rig shaker by tapping into the flow line with a "Y", thus keeping the rig shaker available as a "scalping shaker". * Replacing the rig shaker after top hole is completed. * Downstream from the rig shaker to accept fluid after it passes through the coarse screen shaker (secondary pump). Because fine screen shakers have a wide variety of designs, they have few characteristics in common. The various designs are differentiated by screen orientation and shape, screen tensioning mechanism, placement and type of vibrator and other special features. See Figure Y2-11.

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Figure Y2-11 Fine Screen Shakers

They are versatile pieces of equipment and can operate on all types of mud. Figure Y2-12 shows the range of particle sizes separated by the screens commonly used with fine screen shakers. Figure Y2-12 Particles Removed by Fine Screen Shakers

a. Screen Orientation and Shape Screen Orientation and Shape refer to the arrangement of the screen or screens in the unit. Screens are usually rectangular (although some designs use round screens) and may be single screens or multiple screens placed in series or a parallel, as shown in Figure Y2-13.

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Figure Y2-13 Shaker Screen Configurations

Single deck, single screens (Figure Y2-13A) are the simplest design, with all mud passing over one screen of uniform mesh. This type of shaker requires very efficient vibrator mechanisms to function properly under all possible drilling conditions and requires high throughput per square foot of screen cloth. Units with screens placed in parallel (Figure Y2-13B) have two or more screen sections acting as one large screen so that no cuttings can fall between them. All screen sections must be the same mesh, since the coarsest mesh section determines the unit's screening ability. Shakers with screen placed in series (Figure Y2-13C) have a coarse screen above a finer screen, with the finer screen being the controlling mesh size. The operating theory is that the top screen will remove some of the cuttings from the mud to take part of the load off the bottom screen and thereby increase overall screening efficiency. b. Screen Tensioning Mechanism Screen Tensioning Mechanism is the mechanical method by which the screen is installed and tightened during installation. Screen tensioning is critical to shaker efficiency and screen life. Early fine screen shaker designs require tensioning by hand. That can cause problems associated with uneven tensioning, over- tensioning, or undertensioning of screens. To increase screen life, especially in the 120-200 mesh range, manufacturers have incorporated two design changes: 1) A coarse backing screen to support fine meshes; and 2) Pre-tensioned screen panels. Today, fine screens are reinforced with a coarse backing screen below. This backing screen protects the fine screen from being damaged and provides additional support for heavy solids loads.

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The most important advance has been the development of pretensioned screen panels. Similar panels have been used on mud cleaners since their introduction, but earlier shakers did not possess the engineering design to allow their use successfully. With the advent of modern, linear-motion shakers, pre-tensioned screen panels have extended screen life and justified the use of 200-mesh screens at the flowline. These panels consist of a fine screen layer and a coarse backing cloth layer bonded to a support grid (Figure Y2-1) The screen cloths are pulled tight, or tensioned, in both directions during the fabrication process. This ensures the beginning of proper tension on every screen. The pre-tensioned panel is then held in place with tension bolts in the bed of the shaker. Most manufacturers limit themselves to one support grid opening size to reduce inventory and production costs. The opening size is typically 1" for maximum mechanical support. Other manufacturers provide screen panels with 1 ", 2", or 3" openings to allow rig personnel to choose the desired mechanical support and total open area, depending on the application. c. Vibrator Mechanisms Vibrator Mechanisms vary widely in design and placement and greatly affect the throughput efficiency of fine screen shakers. Most modem shakers utilize linear motion vibration with the vibrator mechanism mounted above the screen bed. One important advantage of linear motion is positive conveyance of cuttings across the screen surface. This generally allows the use of an uphill sloped screen deck, greatly increasing throughput capacity and cuttings dryness. Most vibrators are electrically operated, although a few are hydraulically operated. In some units the vibration inducing eccentric weights are separated from the drive motor, while in others the eccentric weights and motor form an integral assembly. In some units, the nature of the vibratory motions can be easily modified to take advantage of specific solids conveying characteristics, but most units have a fixed vibratory motion. d. Maintenance. Because of their greater complexity and use of finer mesh screens, fine screen shakers generally require more attention than rig shakers. Nonetheless, their more effective screening capabilities more than justify the higher operating cost. This is especially true when expensive mud systems are used. Besides periodic lubrication, fine screen shakers require the same minimum maintenance as rig shakers while making a trip: * Wash down screens. * Check screens for proper tension. * Shut down shaker when not drilling to extend screen life. * Dump and clean possum belly. In addition, frequent checks must be made for screen plugging or blinding and broken screens. All will occur more frequently on fine screen shakers than on coarse mesh rig shakers. e. Screen Plugging and Blinding Screen Plugging and Blinding, while present to some degree on rig shakers, is most frequent fine with screen shakers. If the mesh openings plug with near-size particles become coated over, the throughput capacity of the screen can be drastically reduced and flooding of the screen may occur.

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Plugging can often be controlled by adjusting the vibratory motion or deck angle, but sometimes requires changing screens to a coarser or freer mesh. A coarser screen should be used only as a temporary solution until the particular formation responsible for near-size particle generation is passed. Changing to a freer mesh screen often presents a better and more permanent solution. Screen blinding caused by sticky particles in viscous mud coating over the screen openings, by the evaporation of water from dissolved solids, or from grease requires a screen wash-down to cure. This wash-down may simply be a high pressure water wash, a solvent (in the ease of grease, pipe dope or asphalt blinding), or a mild acid soak (in the case of blinding caused by hard water). Stiff brushes should not be used to clean fine screens because of the fragile nature of fine mesh screen cloth. f. Screen Life Screen Life of fine mesh screens varies widely from design to design, even under the best of conditions, because of differences in operating characteristics. Screen life can be maximized by following these general precautions: * Keep screens clean. * Handle screen carefully when installing * Keep screens properly tensioned. * Do not overload screens. * Do not operate shakers dry. Screen capacity, or the volume of mud which will pass through a screen without flooding, varies widely depending on shaker model and drilling conditions. Screen mesh, drilling rate, mud type, weight and viscosity, bit type, formation type, -- all affect throughput to some degree. The mesh of the screen in use is also directly related to shaker capacity because (in general but not always) the finer a screen's mesh, the lower its throughput. Drilling rate affects screen capacity because increases in drilled solids loading reuse the effective screen area available for mud throughput. Increased viscosity, usually associated with an increase in percent solids by volume and/or increase in mud weight, has a markedly adverse effect on screen capacity. As a general rule, for every 10% increase in viscosity, there is a 2-5% decrease in throughput capacity. Figure Y2-14 shows the relationship of mud weight, viscosity, and screen mesh on shaker capacity.

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Figure Y2-14 Shaker Capacity vs Mud Weight, Viscosity, Screen Mesh

Mud type also has an effect on screen capacity. Higher viscosities generally associated with oil-base and invert emulsion muds usually result in lower screen throughput than would be possible with a water-base mud of the same mud weight. Some mud components such as synthetic polymers also have an adverse effect on screen capacity. As a result, no fine mesh screen can offer a standard throughput for all operating conditions. Due to the many factors involved in drilling conditions, mud characteristics and features of certain models, capacities on fine screen shakers can range from 50 to 800 gpm. Multiple units, most commonly dual or triple units, can be used for higher throughput requirements. Cascade shaker arrangements, with scalping shakers installed upstream from the fine screen shakers, can also increase throughput. g. General Rules General Rules in operating shale shakers -- whether coarse screen rig shakers or fine screen shakers which have not already been mentioned, include the following: * Use the finest mesh screen capable of handling the full volume from the flow line under the particular drilling conditions. This will reduce solids loading on downstream hydrocyclones and screens, improving their efficiency. Several screen changes, normally to progressively freer mesh screens over the course of the hole, are quite common. * Large cuttings which settle in the mud box (possum belly) of the shaker should never be dumped into the mud system. (Dump them into the sump or waste pit.) * Except in extenuating circumstances (such as the presence of lost circulation material), all mud should be screened. This includes make-up mud hauled in from other locations. * Unless water sprays are absolutely necessary to control screen blinding, water should not be used on the screen surface while drilling. Water sprays tend to wash smaller cuttings through the which would otherwise be removed by their clinging to larger particles (piggyback effect).

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B. Degassers 1. Introduction Normally, drilling fluid should not contain formation gas. Only in applications where a gas is purposely added to the drilling fluid -- such as when drilling with air, mist, or foam -- should gas entrainment be tolerated. When using a conventional drilling fluid, gas may enter the mud as a result of drilling operations and should be removed promptly to maintain proper well control. Gas-cut mud has always been a problem for the drilling industry. Because gas reduces the volumetric efficiency of mud pumps, methods to remove this gas are necessary to allow continued pumping. Simply put: DEGASSERS KEEP THE MUD PUMPS PUMPING MUD WHEN YOU NEED THEM THE MOST. Degassers are the most effective way to remove unwanted gas. They are designed to rapidly bring gas bubbles to the surface of the mud, break them, and remove them to a safe location away from the rig tanks. This section will cover the effects of gas-cut mud in conventional drilling fluids, how to measure gas-cut mud, how to remove unwanted gas using degassers, and how to troubleshoot degasser performance.

2. Effects Of Gas-cut Mud Gas-cut mud has several effects. Some of these are obvious and others are not. Wrong action in a gas-cut mud can cause higher drilling costs, lost circulation, or blowout. It is important to recognize both the source ( gas or air) and effects of "bubbles in the mud". In conventional drilling fluids, air in the mud is usually a result of mud flowing in the flowline and through mud processing equipment. The main damage from air is corrosion. Air in the mud: * Makes foam on the surface of the mud in the pits. * Reduces measured mud weight. * Usually makes larger bubbles than gas. * Corrodes the drill string. * Will not be detected by the mud logger. * May reduce centrifugal pump performance. Gas-cut mud: * Reduces measured mud weight. * Indicates a lower hydrostatic pressure downhole. * Reduces pump flow rate. * Reduces performance of centrifugal pumps, shutting down hydrocyclones, mud guns and superchargers. * May be detected by the mud logger. * Increases rate of returns from the wellbore. Gas-cut mud reduces the mud weight measured with a mud balance. It does not change the true mud weight, but it creates a wrong, urgent feeling to weight up the mud. This can result in great harm. For example:

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The well profile calls for 10.0 ppg mud to hold the formation expected at 10,000 ft. The mud man mixes the right mud to get to 10.0 ppg. While drilling ahead, the mud is gas-cut 0.6 ppg, but this is not realized. So, even though the actual mud weight is 10.0 ppg, the measured mud weight in the mud balance is 9.4 ppg. Barite is added to bring measured weight up to 10.0 ppg, but this causes the true mud weight to be 10.6 ppg. Two things happen. First, the increased mud weight reduces drilling rate and the gas in the mud reduces pump volume. Then, the risk of losing circulation due to greater hydrostatic pressure is increased if the formation is pressure sensitive. At 10,000 feet this increase will be 312 psi. When weighing mud samples: * Use a clean and calibrated mud balance. * Be sure the place the sample is taken is well stirred. * Be sure the sample is the same as the mud being circulated. * Fill the mud balance cup completely. If gas-cut mud is suspected, use a pressurized mud balance (see API RP 10B) or use a hand vacuum pump to degas the sample thoroughly before weighing. Gas bubbles deep in the drill pipe are under so much pressure they remain very small in size; the downhole mud weight is only slightly reduced. The calculated hydrostatic pressured is also reduced only a small amount -- not the large amount measured at the surface. It is only as the bubbles are circulated, with lower hydrostatic pressures closer to the surface, that they become large enough to have much of an effect. If the true mud weight shows a low reading, it still may not be due to gas or air. Oil or water flows will also reduce mud weight. So will weighting material dropping out of poorly agitated mud systems. A degasser cannot restore mud weight caused by these problems. Gas-free drilling fluid is nearly incompressible. That is, it fills virtually the same volume whether it is static or being pumped. When it becomes gas-cut, the volume of the bubbles is compressible -- the gas volume varies inversely with pressure. As the pressure increases, the volume is reduced; as the pressure decreases, the volume expands. Main mud pumps are either single-acting triplex or double-acting duplex types. They are designed to pump gasfree mud with about 95 percent volumetric efficiency. Gas-cut mud reduces pump flow rate because the volumetric efficiency decreases. No mud is discharged during the part of the discharge stroke wasted to compress the gas; no mud is drawn into the pump during the part of the suction stroke wasted to expand the gas. This can cause several things to happen. The mud can become so gas-cut that no mud is pumped at all standpipe pressure will also decrease. Or after all the gas is compressed, the fast-moving piston can slam into the mud, making the pump and rotary hose jump and jerk. This can cause serious damage to the pump, drive train, piping, and rotary hose. In addition to the main mud pumps, gas-cut mud affects centrifugal pumps, causing cavitation, excessive wear, and potential gas-lock, even with flooded suctions. When this happens, no mud will be pumped through the centrifugal pump, causing hydrocyclones, mud guns, and superchargers to shut down.

3. Removing Gas Bubbles Gas bubbles should be removed from the mud promptly and completely to maintain adequate well control and proper operation of surface equipment. Degassers are the most effective types of equipment for this, but other methods also help.

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For example, mud passing over shaker screens will remove some gas; defoamers break out air and large gas bubbles; submerged mud guns can bring bubbles to the mud pit surface; and even a spray of water on the surface of the pits or across a shaker screen may help. Some muds, such as water and clean brine systems, degas themselves and do not require degassers. Other fluids, with added chemicals or high drilled solids content, have higher viscosities and will require mechanical aids to help remove gas. The size of the gas bubble also affects how fast a bubble will rise and float. Gas bubbles must be on the surface before they can break and release the gas. High viscosity or slow-moving mud is too thick for these bubbles to rise to the surface; the depth of the mud layer must be reduced to allow these bubbles to rise to the surface. Degassers are designed to flow the mud in thin layers across a surface. This may be accomplished by impingement, large baffle surface area, centrifugal force, or a combination of these techniques. The turbulent flow in this thin layer causes the gas bubbles to break. Impact against inner surfaces also breaks gas bubbles. Degassers can be divided into three major types: * mud/gas separators, * atmospheric degassers, and * vacuum degassers. Each type is designed to remove specific size bubbles and amounts of gas. Mud/gas separators Mud/gas separators are designed to remove large amounts of large bubbles from the mud. Sometimes called "poor-boy" degassers or "gas-busters", mud/gas separators usually receive severely gas-cut from either the flowline, or rotating head, or choke manifold. Mud/gas separators flow the gas-cut mud in thin sheets over a series of baffles arranged inside a vertical tank. The resulting turbulent flow breaks out large gas bubbles which then rise through a vertical vent line and are released a safe distance from the fig. The return mud flows into the possum belly of the shakers for further processing. In horizontal drilling, mud/gas separators are often used with an oil skimmer system during the lateral section of the well to remove large amounts of gas while drilling ahead. Atmospheric degassers Atmospheric degassers were developed in the early 1970's. They use a special, non-gas-locking pump to pump gas-cut mud into a spray tank in a thin sheet against the wall of the tank. This impact causes the gas and mud to separate. The degassed mud drains from the spray tank through a trough or pipe to the next downstream compartment. The released gas flows with the degassed mud. This gas should be piped away from the rig by covering the trough with a vent hood and flexible disposal hose. If required, a small blower can be mounted on the vent hood to aid with gas removal. Vacuum degassers Vacuum degassers use a combination of turbulent flow and reduced internal tank pressure to move gas-cut mud and release gas bubbles. Several designs are available; the most common types are the horizontal tank/jet pump design, the vertical tank/jet pump design, and the vertical tank/self-priming pump design. The horizontal tank/jet pump design has a long horizontal tank with long down-sloping baffles inside. Mud flows down these baffles in a thin layer, releasing the gas bubbles.

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A vacuum pump is used to remove the gas from the tank and dispose it a safe distance from the rig. The vacuum pump also reduces the internal tank pressure, drawing fluid into the tank and increasing the gas bubble size, improving removal efficiency. Most of the time, the volume of gas removed is small compared to the capacity of the vacuum pump, so a 3-way valve is installed in the gas piping to let air in and prevent too much vacuum in the tank. The fluid level inside the tank and the operation of the 3-way valve is controlled automatically by a float inside the tank. The jet pump discharges the degassed mud from the tank and returns it to the next downstream compartment. There is no re-mixing of released gas and fluid. The jet pump is used because there is still a small amount of gas left in the mud -- but maybe enough to gas-lock a direct feed centrifugal pump. The gas passes easily through the jet pump and floats to the surface of the discharge compartment and breaks out from the mud. The vertical tank/jet pump design has two variations. The first of these is similar to the horizontal/jet pump design. Instead of a long horizontal tank with a single series of baffles, this design has several conical baffles stacked inside a vertical, cylindrical tank. This design increases baffle surface area in a compact footprint. The vacuum pump and jet pump arrangement are the same as for the horizontal design, although some vertical designs have been used with self-priming feed pumps. Another vertical tank/jet pump design also has a short vertical tank with stacked conical baffles. Instead of a vacuum pump, this unit uses the jet pump to create sufficient vacuum to draw gas-cut mud into the tank. Both the released gas and degassed mud flow through the mud outlet into a cyclonic separator. The centrifugal force created in the cyclone separates the gas (discharged out the top of the cyclone) from the mud (discharged out the bottom of the cyclone). Two float control valves prevent too much vacuum or tank over-filling. The vertical tank/self-priming pump design uses a cone and funnel to form thin layers of mud. Gas-cut mud is pulled into the tank by a vacuum pump. As the level rises, a float valve opens to reduce the vacuum and prevent overfilling the tank. As with other vacuum degassers, enough gas can be drawn into the degassed mud to gas-lock an ordinary centrifugal pump. In this design, a self-priming centrifugal pump pumps mud from the tank and returns it to the next downstream compartment. Installation of Degassers. Actual placement of the degasser and related pump will vary with the design of the degasser, but these recommendations may used as a general rule: * Install a screen in the inlet pipe to the degasser to keep large objects from being drawn into the degassing chamber. * Locate the screen about one foot above the pit bottom and be located in a well-agitated spot. * There should be a high equalizer line between the suction and discharge compartment. The equalizer should be kept open to allow backflow of processed mud to the suction side of the degasser. * Route the liquid discharge pipe to enter the next compartment or pit below mud level to prevent aeration. * Install the gas discharge line to safely vent the separated gas to atmosphere or to a flare line. Maintenance of degassers Maintenance of degassers varies considerably depending on make and model. In general, the following guidelines apply: * Check to make sure the suction screen is not plugged. * Routinely lubricate any pumps and other moving parts and check for wear.

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* Keep all discharge lines open and free from restrictions, such as caused by solids buildup around valves. * If the degasser utilizes a vacuum, keep it at the proper operating level, according to the manufacturer's recommended range for the mud weight and process rate. * Check all fittings for air leaks. * If the unit uses a hydraulic system, check it for leaks, proper oil level, and absence of air in the system.

C. Hydrocyclones Hydrocyclones (also referred to as cyclones or cones) are simple mechanical devices, without moving parts, designed to speed up the settling process. Feed pressure is transformed into centrifugal force inside the cyclone to accelerate particle settling in accordance with Stoke's Law. In essence, a cyclone is a miniature settling pit which allows very rapid settling of solids under controlled conditions. Hydrocyclones have become important in solids control systems because of their ability to efficiently remove particles smaller than the finest mesh screens. They are also uncomplicated devices, which make them easy to use and maintain. A hydrocyclone (see Figure Y2-15) consists of a conical shell with a small opening at the bottom for underflow discharge, a larger opening at the top for liquid discharge through an internal "vortex finder", and a feed nozzle on the side of the body near the wide (top) end of the cone. Figure Y2-15 Hydroclone

Drilling mud enters the cyclone under pressure from a centrifugal feed pump. The velocity of the mud causes the particles to rotate rapidly within the main chamber of the cyclone. Light, fine solids and the liquid phase of the mud tend to spiral inward and upward for discharge through the liquid outlet. Heavy, coarse solids and the liquid film around them tend to spiral outward and downward for discharge through the solids outlet.

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Design features of cyclone units vary widely from supplier to supplier, and no two manufacturers' cyclones have identical operating efficiency, capacity or maintenance characteristics. In the past, cyclones were commonly made of cast iron with replaceable liners and other wear parts made of rubber or polyurethane to resist abrasion. Newer designs are made entirely of polyurethane, and are less expensive, last longer, and weigh less. The size of oilfield cyclones commonly varies from 4" to 12". This measurement refers to the inside diameter of the largest, cylindrical section of the cyclone. In general -- but not always -- the larger the cone, the larger its cut point and the greater its throughput. Typical cyclone capacity and feed pressures are listed in Figure Y2-17. Figure Y2-17 Hydroclone Capacities

Manifolding multiple cyclones in parallel can provide sufficient capacity to handle the required circulating volume plus some reserve as necessary. Manifolding may orient the cyclones in a vertical position or nearly horizontal -the choice is one of convenience, as it does not affect cyclone performance. The internal geometry of a cyclone also has a great deal to do with its operating efficiency. The length and angle of the conical section, the size and shape of the feed inlet, the size of the vortex finder, and the size and adjustment means of the underflow opening all play important roles in a cyclone's effective separation of solids particles. Operating efficiencies of cyclones may be measured in several different ways, but since the purpose of a cyclone is to discard maximum abrasive solids with minimum fluid loss, both aspects must be considered. In a cyclone, larger particles have a higher probability of reporting to the bottom (underflow) opening, while smaller particles are more likely to report to the top (overflow) opening. The most common method of illustrating particle separation in cyclones is through a cut point curve. Figure Y2-18 shows the approximate cut point ranges for cyclones used with unweighted water-base muds and operated at standard pressures.

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Figure Y2-18 Hydroclone Cut Points

Particle separation in cyclones can vary considerably depending on such factors as feed pressure, mud weight, percent solids, and properties of the liquid phase of the mud. Generally speaking, increasing any of these factors will shift the cut point curve to the right, increasing the size of solids actually separated by the cyclone. By itself, the cut point does not determine a cyclone's overall efficiency because it ignores the liquid loss rate. The amount of fluid in the cone underflow is important; if the solids are too dry, they can cause "roping" or "dryplugging" of the underflow. In contrast, a cyclone operating with a spray discharge (see Figure Y2-16) gives solids a free path to exit. Figure Y2-16 Spray vs Rope Discharge

A cone operating in spray discharge will remove a significantly greater amount of solids than a cone in "rope" discharge.

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Hydrocyclones should not be operated in rope discharge because it will drastically reduce the cone separating efficiency. In a rope discharge, the solids become crowded at the apex, cannot exit freely from the underflow, and become caught by the inner spiral reporting to the overflow. Solids which otherwise would be separated are forced into the overflow stream and returned to the mud system. This type of discharge can also lead to plugged cones and much higher cyclone wear. While a spraying cyclone will also discharge more fluid, the benefits of more efficient solids removal and less cone wear outweigh the additional fluid loss. In cases where a dry discharge is required, the underflow from hydrocyclones can be screened or centrifuged to recover the free liquid.DESANDERS Desanders are hydrocyclones larger than 5" in diameter (6", 8", 10" or 12" I.D.). Generally, the smaller the cone, the smaller size particles the cone will separate (see Figure Y2-19). Figure Y2-19 Particles Removed by Desanders (vs 200 Mesh Screen) (200 mesh screen included for comparison).

Desanders are primarily used to remove the high volumes of solids associated with extremely fast drilling of a large diameter hole. See Figure Y2-20.

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Figure Y2-20 Desanders

a. Desander installation. Desanders are installed downstream from the shale shaker and degasser. The desander removes sand sized particles and larger drilled solids which have passed through the shaker screen and discards them along with some liquid into a waste pit. The partially clean mud is discharged into the next pit downstream. See Figure Y2-21. Figure Y2-21 Desander Installation

When installing a desander, follow these general recommendations:

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* Size the desander to process 100-125% of the total mud circulation rate. * Keep all lines as short and straight as possible with a minimum of pipe fittings. This will reduce loss of pressure head on the feed line and minimize back-pressure on the overflow discharge line. * Do not reduce the diameter of the overflow line from that of the overflow discharge manifold. * Direct the overflow line downward into the next downstream compartment at an angle of about 45°. The overflow discharge line should never be installed in a vertical position -doing so may cause excessive vacuum on the discharge header and pull solids through the cyclone overflow, reducing the cyclone's efficiency. * Keep the end of the discharge line above the surface of the mud to avoid creating a vacuum in the line. * Position the underflow trough to easily direct solids to the waste pit. * Install a low equalizer line to permit backflow into the desander suction. b. Desander Operation Operating desanders at peak efficiency is a simple matter, since most desanders are relatively uncomplicated devices. Here are a few fundamental principles to keep in mind: * Operate the desander unit at the supplier's recommended feed manifold pressure (usually around 30 psi). Too low a feed pressure decreases efficiency, while too high a pressure shortens the life of cyclone wear parts. * Check cones regularly to ensure the discharge orifice is not plugged. * Run the desander continuously while drilling and shortly after beginning a trip for "catch-up" cleaning. * Operate the desander with a spray rather than a rope discharge to maintain peak efficiency. c. Desander Maintenance Maintenance of desanders normally entails no more than checking all cone parts for excessive wear and flushing out the feed manifold between wells. Large trash may collect in feed manifolds which could cause cone plugging during operation. Preventive maintenance minimizes downtime, and repairs are simpler between wells than during drilling. Use of desanders is normally discontinued when expensive materials such as barite and polymers are added to a drilling mud, because a desander will discard a high proportion of these materials along with the drilled solids. Similarly, desanders are not generally cost effective when an oil-base mud is in use, because the cones also discard a significant amount of the liquid phase.

2. Desilters A desilter uses smaller hydrocyclones (usually 4" or 5" I.D.) than a desander and therefore generally removes smaller particles. See Figure Y2-22.

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Figure Y2-22 Desilters

The smaller cones enable a desilter to make the finest particle size separation of any full flow solids control equipment -- removing solids in the range of 15 microns and larger (Figure Y2-24).

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Figure Y2-24 Particle Removal by Desilters(325 mesh screen included for comparison).

This makes it an important device for reducing average particle size and removing abrasive grit from unweighted muds. The cyclones in desilter units operate on the same principle as the cyclones used on desanders. They simply make a finer cut, and the individual cone throughput capacities are less than desander cones. Multiple cones are usually manifolded in a single desilter unit to meet throughput requirements. Desilters should be sized to process 100-125% of the full rig flow rate. a. Desilter Installation Installation of the desilter is normally downstream from the shale shaker, sand trap, degasser and desander, and should allow ample space for maintenance. See Figure Y2-23.

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Figure Y2-23 Desilter Installation

Here are some fundamentals for installing desilters: * Take the desilter suction from the compartment receiving fluid processed by the desander. * Do NOT use the same pump to feed both the desander and desilter. * If both pieces of equipment are to be operated at the same time, they should be installed in series and each should have its own centrifugal pump. * Keep all lines as short and straight as possible. * Install a guard screen with approximately 1/2" openings at the suction to the desilter to prevent large trash from entering the unit and plugging the cones. * Position the desilter on the pit high enough so the overflow manifold will gravity-feed fluid into the next downstream compartment at an angle of approximately 45°. Remember - no vertical overflow discharge lines. * Keep the end of the discharge line above the surface of the mud to avoid creating a vacuum in the line. * Install a low equalizer line for backflow to the desilter's suction compartment. * Position the underflow trough to easily direct solids to the waste pit. Running a desander ahead of a desilter takes a big load off the desilter and improves its efficiency. If the drilling rate is slow and the amount of solids being drilled is only a few hundred pounds per hour, then the desander may be turned off (to save fuel and maintenance costs) and the desilter may be used to carry the total desanding / desilting load. b. Desilter Operation

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Operating efficiencies of competitive desilters vary widely according to differences in design features. To operate desilters at maximum efficiency, follow these basic guidelines: *Operate the cones with a spray discharge. Never operate the desilter cones with a rope discharge since a rope underflow cuts cone efficiency in half or worse, causes cone plugging, and increases wear on cones. Use enough cones and adjust the cone underflow openings to maintain a spray pattern. * Operate the desilter unit at the supplier's recommended feed manifold pressure. This is generally between 30 and 40 psi (70 - 80 feet of head). Too much pressure will result in excessive cone wear. * As mud weight increases, feed pressure will also increase. Rule of thumb: desilter cones should operate at a feed pressure of 4X mud weight. As mud weight increases, the cone bottoms can be opened slightly to help increase solids removal efficiency. Check cones regularly for bottom plugging or flooding, since a plugged cone allows solids to return to the mud system. If a cone bottom is plugged, unplug it with a welding rod or similar tool. If a cone is flooding, the feed is partially plugged or the bottom of the cone may be worn out. Run the desilter continuously while drilling and also for a short while during a trip. The extra cleaning during the trip can reduce overload conditions during the period of high solids loading immediately after a trip. c. Desilter Maintenance. A desilter's smaller cyclones are more likely than desander cones to become plugged with oversized solids, so it is important inspect them often for wear and plugging. This may generally be done between wells unless a malfunction occurs while drilling. The feed manifold should be flushed between wells to remove trash. Keep the shale shaker well maintained -- never bypass the shaker or allow large pieces of material to get into the active system. A desilter will discard an appreciable amount of barite because most barite particles fall within the silt size range. Desilters are therefore not recommended for use with weighted muds. Similarly, since hydrocyclones discard some liquid along with the drilled solids, desilters are not normally used with oil-base mud, unless another device (centrifuge or mud cleaner) is used to "dewater" the cone underflow.

D. Mud Cleaners In many cases, combinations of vibratory screening and settling centrifugal force are used together to provide an effective separation. The most familiar combination separator is the Mud Cleaner (Figure Y2-25).

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Figure Y2-25 Mud Cleaners

Mud cleaners were developed in the early 1970's to remove fine drilled solids from weighted muds without excessive loss of barite and fluid. They have also proved valuable tools in closed systems and other "dry location" applications. These devices use a combination of desilting hydrocyclones and very fine mesh vibrating screens (120-400 mesh) to remove fine drilled solids while returning valuable mud additives and liquids back to the active mud system. Most modem mud cleaners use multiple 4" or 5" cyclones, yielding a liquid throughput of 400-850 gpm. The liquid throughput is only one measure of mud cleaner capacity; equally important is the capacity of the vibrating screen since the overall performance of the mud cleaner depends on its ability to discard "dry" solids. Figure Y2-26 shows a typical mud cleaner design.

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Figure Y2-26 Mud Cleaner Separation Process

After removal of large cuttings with a shaker, feed mud is pumped into the mud cleaner's hydrocyclones with a centrifugal pump. The overflow from the cyclones is returned to the mud system. Instead of simply discarding the underflow, the solids and liquid exiting the bottom of the cyclones are directed onto a fine screen. Drilled solids larger than the screen openings are discarded; the remaining solids, including most barite in a weighted system, pass through the screen and are returned to the mud system. The cut point and amount of mass solids removed by a mud cleaner depends primarily on the mesh of the fine screen used, Figure Y2-27.

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Figure Y2-27 Particle Removal by Mud Cleaner Screens

Since there are many designs of mud cleaner available, performance and economics will vary with machine and drilling variables. However, one example of field operating data illustrates the principles involved. Figure Y2-28 shows the results of analysis of a mud cleaner processing an 11.2 ppg mud.

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Figure Y2-28 Mud Cleaner Field Test Data

This data indicates the mud cleaner was discarding 46,800 pounds of drilled solids each 24 hours, along with 2,925 pounds (29 sacks) of barite. Utilizing the fine screen under the hydrocyclone salvaged 71,955 pounds (72 sacks) of weighting material per day. From this, it is obvious why mud cleaners should be used in place of desilters alone in weighted drilling mud applications. Comparing the fluid content of the cone underflow (8 bbl/hr) to the fluid content of the mud cleaner discard (1.4 bbl/hr) shows another benefit of mud cleaners over desilters on oil-base muds and other drilling fluids which have an expensive liquid phase. Mud cleaners should be considered in these applications: 1. Whenever the application requires finer screens than the existing shaker can handle; 2. Unweighted oil-base drilling mud; 3. Expensive polymer mud systems; 4. Whenever the cost of water is high; 5. Standard unweighted water-base muds with high disposal costs and/or environmental restrictions; 6. When use of coarse lost circulation material forces bypassing of the shale shaker; and 7. Workover and completion fluid cleanup. Mud cleaners are simply a bank of hydrocyclones mounted over a fine-mesh screen. In many instances (even with modern fine screen shakers), a freer separation is required than existing shakers provide. The question to answer becomes how to achieve the necessary level of screening at the lowest cost. The alternatives are: 1. Add additional, similar shakers to handle the flow rate; 2. Replace the existing shakers with more efficient units; or

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3. Add a mud cleaner downstream from the existing shakers. Any of these may be correct, but a thorough study of the capital cost (the actual cost of new equipment, plus transportation, rig modifications, and installation) and the operating cost (screens and other expendables, plus fuel) is necessary to make the proper choice. Salvage of the liquid phase of an unweighted drilling mud often cost-justifies use of a mud cleaner when the fluid phase of the mud is expensive, such as in polymer systems, oil-base systems, or in water-base systems when water has to be trucked into a drilling location. Compared to desanders and desilters, whose cyclone underflow may be as much as 15 bbl/hr or more, mud cleaners can achieve efficient solids removal while returning most liquid back to the active mud system. Use of ultra-fine screens (200 to 325 mesh) significantly improves solids controlling any high-value fluid system. An increasingly important application of mud cleaners is the removal of drilled solids from unweighted water-base mud in semi-dry form. This system is commonly used in areas where environmental restrictions prohibit the use of earthen reserve pits, and expensive vacuum truck waste disposal from steel pits is the alternative. The mud cleaner is used to discard drilled solids in semi-dry form which is classified as legal landfill in most areas and is subject to economical dry-haul disposal techniques (dump truck or portable waste containers). When used for this purpose, the screen underflow from the mud cleaner is often diverted to separate steel waste pit for vacuum truck disposal. This may seem counterproductive, but a vacuum truck can only carry a limited amount of sand because of the over-the-road weight restrictions. Whenever a vacuum truck must haul normal fullflow desilter waste, the waste must often be diluted with rig water to reduce density. The operator is then billed for the haulage of a vacuum truck load comprised largely of rig water. On the other hand, since most of the solids are removed in semi-dry form by the mud cleaner screen, the remaining solids in the screen underflow are dilute enough to be hauled away without watering them back. Vacuum truck loads often can be reduced to a small fraction of those required with full-flow desilting. This approach to dry-solids disposal can be carried further by using a centrifuge with a mud cleaner to form a "closed" system which eliminates discarding of any fluid. These systems are being used increasingly in areas where liquid mud waste must be hauled a significant distance and is subject to a high disposal fee. In a closed system, underflow from the mud cleaner screen is diverted to a holding tank and then centrifuged, which results in disposal of very fine, semi-dry solids and return of liquid to the active system. Such a system virtually eliminates the need for reserve pits, minimizes dilution, eliminates vacuum truck services for disposal of liquid mud, and meets environmental constraints when drilling within ecologically sensitive areas. Another special mud cleaner application is the use of a double-deck unit for salvage of coarse lost circulation material (LCM). Usually when running LCM, the shale shaker is bypassed and drilled solids build up rapidly in the mud, necessitating high level of dilution and new mud. Use of a two-deck mud cleaner allows salvage of the LCM while minimizing the increase in solids content. Within the mud cleaner, a coarse top screen is used to pre-pre-screen the mud and remove the lost circulation material. This material is discharged back into the active system for recirculation downhole. The drilled solids, mud additives and liquid phase pass through the top screen onto the lower, finer mesh screen, where the drilled solids are separated out and discarded to waste. The cleaned mud then flows back into the mud system and is re-blended with the salvaged lost circulation materials. One additional special mud cleaner application is that of workover and completion fluid cleanup. In order to reduce costs associated with this expensive task, a mud cleaner running one or two ultra-fine screens (200 over 325 mesh) can be used to remove most of the solids before they reach the cartridge type filters. This application can significantly reduce filter replacement costs, reduce downtime in changing falters, and allow larger volumes of fluid to be cleaned at a faster rate.

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a. Mud Cleaner Installation. Installation of the mud cleaner is made downstream of the shale shaker and the degasser. See Figure Y2-29. Figure Y2-29 Mud Cleaner Standard Installation

The same pump used to feed the rig's desander or desilter is often reconnected to feed the mud cleaner when weight material is added. (Most mud cleaners are designed to also function as desilter on unweighted mud by rerouting the cone underflow or by removing or blanking off the screen portion of the unit. The mud cleaner may then be used to replace or augment the rig's desilter during tophole drilling.)

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Figure Y2-30 Mud Cleaner Installation - Unweighted Mud

Figure Y2-31 Closed Loop System - Installation for Unweighted Mud

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Figure Y2-32 Mud Cleaner Installation for LCM Salvage

Figure Y2-33 Mud Cleaner Installation: W/O or Completion Fluid Cleanup

Follow these guidelines when installing mud cleaners to allow peak efficiency:

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* Size the mud cleaner to process 100-125% of the full circulating flow rate. * Take the mud cleaner suction from the compartment receiving fluid processed by the desander. * Keep all lines as short and straight as possible. * Install a guard screen with approximately 1/2" openings at the suction to the desilter to prevent large trash from entering the unit and plugging the cones. * Position the mud cleaner on the pit high enough so the overflow manifold will gravity-feed fluid into the next downstream compartment at an angle of approximately 45°. Remember - no vertical overflow discharge lines. Whether the mud cleaner is placed on top of the surface mud pit or on a separate platform, provide walkways and sufficient space for routine maintenance. * Keep the end of the discharge line above the surface of the mud to avoid creating a vacuum in the line. * Install a low equalizer line for backflow to the mud cleaner suction compartment. * Position the screen underflow trough to easily direct solids to the waste pit. * Return the fluid underflow from the mud cleaner screen in a well-agitated spot. This will prevent concentrated barite from settling in the mud tank. To operate mud cleaners at maximum efficiency, remember these fundamentals: b. Mud Cleaner Operation * Operate mud cleaners continuously on the full circulating volume to achieve maximum drilled solids removal. * Operate mud cleaners within the limits of the screen capacity. A mud cleaner with a cyclone throughput of 800 gpm is of little value if the cone underflow exceeds the screen capacity, resulting in flooding and high mud additive losses. * Feed the cone underflow to the screen at a single point, with minimal use of the available screen area. Capacity and efficiency suffer with multiple feed points on the screening surface. * Screen throughput is reduced by increased solids content and viscosity. The cyclone underflow plays a critical role in overall mud cleaner efficiency. It is often desirable to modify the performance characteristics of the cones to decrease the amount of ultra fines in the cone underflow. This minimizes near-size screen plugging and barite loss due to "piggybacking". * Do NOT use excessive feed pressure. Remember the rule of PSI = 4X mud weight. Excessive pressures will result in reduced screening efficiency, greater barite loss, and severe cyclone wear. * Do NOT judge screen efficiency simply on the basis of cuttings dryness or color. The total amount of drilled solids in the discarded material, along with the ratio of barite to drilled solids, must be determined to evaluate economic performance. A technique for measuring and calculating these values is given inAppendix of the Solids Control and Waste Management by Brandt/Tuboscope. (Note: This technique is also important when using 100-mesh, or finer, screens on shakers since these screens can also remove appreciable amounts of weighting material.) * Select the number of cones to be operated and the particular mesh screen to be used according to drilling conditions. As a general rule, use the finest mesh screen possible (to process the full circulating rate) and size the number of cones accordingly.

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In many instances, a number of cones will have to be blanked off in order for the desired screen mesh to be used. This may involve an experimental determination of the number of cones and screen mesh to optimize performance. In some cases, more than one mud cleaner will be needed. The following example illustrates the point: On a particular well with a 15 lbs/gal mud and a circulating rate of 400 gpm, it is determined a 200-mesh screen is required to successfully maintain the desired level of solids. The mud cleaner in use has ten 4" cyclones. The ten cones will handle the full 400 gpm flow with 20% reserve capacity (50 gpm/cone X 10 cones = 500 gpm; (500 gpm)/(400 gpm) = 120% capacity), but the 200 mesh screen is unable to handle the total underflow of all cones without flooding. Blanking off 4 cones eliminates the flooding, but the remaining cones process only 75 % of the circulating rate (50 gpm/cone X 6 cones = 300 gpm; (300 gpm)/(400 gpm) = 75% capacity). The solids content in the mud begins to increase. The alternatives are to: 1) re-install the cones and run a coarser screen -- 100 or 150 mesh -- and allow the solids level to increase, or 2) add a second mud cleaner, blanking off two cones on each, thereby allowing the use of 200 mesh screens and maintaining the desired solids level. This example shows the correct equipment must be used. Shortcuts such as coarser mesh screens or insufficient processing capacity reduce the effectiveness of the system. It is very important to recognize the need for two mud cleaners and use them -- using just one when two are required is false economy and wasteful operation. Mud cleaner designs with 12 - 16 cones over a single screen bed have not proven to be practical: the ultra-fine mesh screen simply cannot handle the underflow volume from the cones. One exception to this is the use of a linear-motion shaker for the vibrating screen portion of the mud cleaner. Coupling a linear motion, fine screen shaker with a manifold of properly designed hydrocyclones yields a high-performance mud cleaner with sufficient capacity for even the largest drilling rigs. Aside from these fundamentals, follow these general guidelines for correct mud cleaner operation: * Run the mud cleaner continuously while drilling and for a short period of time while making a trip for "catch-up" cleaning. * Start up the shaker portion of the mud cleaner before engaging the feed pump. * Shut down the feed pump before turning off the vibrating screen portion of the mud cleaner. * Permit the screen to clear itself, then rinse the screen with water or oil sprays before shutting down the screen portion of the unit. * For peak efficiency, operate the cones with a spray rather than a rope discharge. This is just as important with a mud cleaner as with desilters and desanders. * Check cones regularly for bottom plugging or flooding, since a plugged cone allows solids to return to the mud system. If a cone bottom is plugged, unplug it with a welding rod or similar tool. If a cone is flooding, the feed is partially plugged or the bottom of the cone may be worn out. * When a significant amount of barite is added to increase mud weight, shut down the mud cleaner for one or two full circulations. This permits the fresh barite to thoroughly mix with the system and reduce losses over the screen. * Use low-volume water (or oil) sprays on the screen surface to reduce "piggy-backing" only if 1) this liquid addition to the mud is permissible, and 2) the resultant reduction in barite discard outweighs the resultant reduction in drilled solids discard. This must be determined experimentally on a case-by-case basis.

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* In some cases, adding a small slipstream of cleaned mud from the hydrocyclone overflow provides the same reduction in "piggy-backing" without reducing the overall efficiency of the unit. c. Mud Cleaner Maintenance Maintenance of mud cleaners generally combines requirements of desilters and fine screen shakers: * Periodic lubrication. * Check screen for proper tension. * Inspect the screen to ensure it is free of tears, holes, and dried mud before start up. * Shut down unit when not drilling to extend screen life. * Check feed manifold for plugging of cyclone feed inlets; clean each as necessary. * Check cyclones for excessive wear and replace parts as necessary.

E. Centrifuges 1. Introduction The use of screens to remove drilled solids from mud makes use of only one characteristic of solids particles -their size. Solids control devices which speed up the settling process of drilled solids by application of centrifugal force take advantage of two factors - particle size and particle density. Hydrocyclones and centrifuges rely on this principle. The full operating characteristics of hydrocyclones have been detailed early in this chapter. This section will cover centrifuges. Centrifuges utilize Stoke's Law in their operation. Stoke's Law is the factors governing the settling velocity of particle in a liquid. This relationship may be stated in its simplest form as: Vs = A (ds2)(Ds - Di)/4.5 KU, where Vs = the terminal settling velocity of the particle A = the acceleration applied to the particle ds = the diameter of the particle Ds = the density of the solid particle Di = the density of the liquid K = a dimensional constant U = the viscosity of the liquid This equation indicates that larger particles (of the same density) will settle more rapidly than smaller ones, that high density solids will settle more quickly than low density ones, and that high acceleration and low viscosity speed up the settling rate.

2. Principles Of Performance The first practical application of centrifuges to process drilling mud came in the early 1950's. Until that time, shaker screens and dilution were the only means of mechanical solids control. The first centrifuges were oilfield adaptations of industrial decanting centrifuges and were utilized to remove ultra-fine solids from weighted muds.

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In the mid-1960's, the perforated cylinder centrifuge was introduced, also to process weighted muds. It wasn't until the mid-1980's that centrifuges were routinely used in unweighted mud applications also. Today, centrifuges are a common piece of equipment in virtually all solids removal systems. The key difference between oilfield centrifuges and previously discussed solids control devices is the operating capacity and duration. Unlike screens, cyclones, and mud cleaners, which operate continuously on the full mud circulation volume, centrifuges operate intermittently on a small fraction of the circulating volume (usually 5 10%). The classic use of centrifuges is to remove colloidal size solids from weighted water-base muds, in order to salvage barite and avoid excessive viscosity which can result from high colloidal content. Both the decanting, solid bowl centrifuge and the perforated cylinder centrifuge are used in this application. a. Decanting centrifuges Decanting centrifuges are so named because they can remove, or "decant", free liquid from the separated solid particles and leave only adsorbed or "bound" water on the surface. The decanting centrifuge is the most common type of centrifuge found in drilling applications. A decanting centrifuge consists of a conveyor screw inside a solid bowl rotated at very high speeds (1500 - 3500 rpm). Mud is usually diluted with water and then pumped into the conveyor. As the conveyor rotates, mud is thrown out the feed ports into the bowl. Centrifugal force pushes the heavy, coarse particles in the rotating mud against the wall of the bowl, where the scraping motion of the conveyor screw moves them toward and out the solids discharge port. The light, fine solids tend to remain in suspension in the pools between the conveyor flutes and are carried out the overflow ports along with the liquid phase of the mud. The operating principle is that of Stoke's Law, but unlike the cyclone, it is not fluid pressure but rather mechanical rotation of the bowl which induces the centrifugal force required to accelerate the settling rate. Bowl sizes in common oilfield applications include 14" x 20", 14" x 22", and 18" x 28". Larger (24" x 38" and larger), high capacity units are also available for special applications. Generally speaking, the larger the bowl, the greater the capacity at comparable efficiency. In field operation, the decanting centrifuge is fired with a housing over the bowl, liquid and solids collection hoppers, skid, feed slurry pump, raw mud and dilution water connections, power source, meters and controls. Feed mud capacity rarely exceeds 25 gpm for the normal weighted mud application (more often 7 - 15 gpm), while total liquid throughput may be as high as 40 gpm (including dilution water). The raw mud feed rate is substantially decreased as mud weight increases. Dilution water is required to compensate for increasing viscosity, generally associated with increasing mud weight, in order to maintain satisfactory separation efficiency. b. Perforated Cylinder Centrifuges Perforated Cylinder Centrifuges operate somewhat differently, but for the same ultimate purpose as decanters. The perforated cylinder centrifuge consists of a perforated cylinder (or rotor) about 3' long, revolving at about 2300 rpm, which is contained in an outer stationary cylindrical ease. A diluted feed of weighted mud is pumped into the stationary case tangential to the rotor. The unit separates the feed slurry into two streams of differing density and particle size distribution. Under centrifugal force, larger solids are concentrated against the annular wall for discharge at an underflow port. Finer solids pass through the multiple 1/2" perforations to exit through the center shaft. Flow into and out of the machine is controlled by positive displacement pumps. Two pumps are located at the feed end - one for raw mud and another for dilution water. A third pump controls the flow split and separation or cut by drawing fluid from the underflow port in the outer cylinder.

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Raw feed mud capacity varies between 10 and 30 gpm, depending on mud weight and the desired separation. Dilution water used to reduce feed viscosity is generally held to about 70% of the raw mud feed rate. Ordinarily a volume equal to 60 - 90% of the total of feed mud and dilution water reports to the underflow containing the coarser particle size distribution. Unlike the decanter which produces one wet and one dry fraction, both slurry streams exiting the perforated cylinder centrifuge are wet and pumpable. For this reason, the perforated cylinder centrifuge has application only on weighted muds.

3. Applications Viscosity can be effectively controlled by discarding a relatively small amount of colloidal size solids. Standard centrifuge applications takes advantage of their ability to make a very fine cut -- on the order of 2 - 6 microns. When treating weighted water-base muds, centrifuges are used intermittently to process a small portion of the volume circulated from the well bore to reduce the amount of colloidals and improve the flow properties of the mud. In order to remove these solids, the liquid fraction from the decanter (or the lighter slurry fraction from the perforated cylinder centrifuge) is discarded. The sand-size and silt-size semi-dry solids fraction from the decanter (or the heavier slurry fraction from the perforated cylinder centrifuge) is returned to the active system. The centrifuge is installed downstream from all other solids control equipment. Ideally, suction for a centrifuge mud feed would be taken from the same pit or compartment which receives the discharge from a mud cleaner or fine screen shaker with 150 - 200 mesh screens. The centrifuge underflow (solids) should be discharged to a well-stirred spot in the pit for thorough mixing with whole mud before the solids have a chance to settle out in the bottom of the pit. This is especially important with a decanter, which discharges damp solids, and of lesser importance with a perforated cylinder centrifuge, which discharges a pumpable slurry. With either type of machine, the underflow discharge should not be too close to the rig pump suction. The overflow (liquid/colloidal solids) gravity-feed down a constantly sloping chute or pipe to waste. Sufficient working space should be provided for routine maintenance and operating adjustments to the centrifuge. In this application, centrifuge operation is intermittent rather than continuous. This relates to the standard purpose of the centrifuge -- to control viscosity by removal of colloidal size particles. Centrifuges should be run when viscosity reaches the operator-established maximum, and the machine's operation should be stopped when viscosity reaches the established minimum. The maximum and minimum limits should be established as part of the overall mud program. Viscosity will normally creep up when centrifuges are shut down due to the size degradation of mud solids, hence the need for restarting the unit. Both over-centrifuging and under-centrifuging should be avoided, as the economics of operation quickly disappear under these circumstances. Prolonged use of a centrifuge, or "over-centrifuging", may cause too great a reduction in viscosity which will contribute to high downhole fluid loss. Bentonite and chemicals must then be added back to the mud system. The amount of replacement bentonite may be calculated exactly from mass balance equations, but a good rule of thumb is to add about one sack of bentonite per hour of centrifuge operation. "Under-centrifuging" simply will not achieve the desired reduction in viscosity. Other popular applications of centrifuges are to reduce overall solids content, reduce average particle size, and to reduce overall waste volume by "dewatering" the discharge from other solids control equipment. Environmental considerations may require special handling of the solid and/or liquid phase. As the disposal cost increases, waste volume becomes a major component of overall well cost. Additional solids removal equipment -- such as a decant-

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ing centrifuge -- is often cost-effective due to minimized waste volume. (In addition, better control of drilling fluid properties is also accomplished, further reducing well cost.) These systems are often called "restricted discharge", or "closed loop" systems. In unweighted applications, the centrifuge discharges the ultra-fine solids and returns the liquid effluent to the mud system. This reduces the fine solids build-up and dilution requirements. The centrifuge should be operated as needed to maintain desired LGS concentration, continuously if needed. Large, high capacity (100 - 250 gpm) decanting centrifuges are preferred for these applications because they can process larger volumes of both solids and liquid. One system uses a decanting centrifuge to process the underflow from hydrocyclones. This variation dewaters the cone underflow, recovering the liquid phase and reducing disposal volume. Other variations on this system include screening the underflow from the cones before feeding it to the centrifuge and installing two centrifuges. Each of these options increases the removal efficiency of the system. The goal of closed loop systems is to limit waste discharge to disposable solids and clear water. These systems combine high performance shakers, hydrocyclones or mud cleaners, and centrifuges with enhanced solids removal and solids handling techniques. Enhanced solids removal is accomplished with chemical addition to "pre-treat" the fluid prior to screening or centrifugation. Pre-treatment can include pH adjustment, flocculation / coagulation, or similar treatment. Solids handling techniques include cuttings washing to remove excess chlorides or residual oil, conveyors to discharge cuttings into sealable containers, transport to approved waste facilities, and incineration of waste products. In addition to their primary goal, closed loop systems minimize drilled solids remaining in the drilling fluid. This reduces dilution requirements, waste volume, and drilling problems. Therefore, closed loop systems have many applications other than environmental ones -- with KCl or other expensive muds, for example. In each of the special applications listed above, multiple centrifuges may be used in parallel to increase flow capacity and mass solids removal. Other applications, such as weighted oil-base muds also use multiple centrifuges, usually two, operated in series. In this application, the first centrifuge processes the drilling fluid in the classic weighted mud operation -- discarding the effluent and colloidal solids, returning the oversize solids to the active system. The effluent (normally discarded) is processed through a second centrifuge prior to discard. The second centrifuge removes the majority of the remaining solids from the effluent and discards them. The effluent is then recovered and returned to the system. From a solids removal efficiency standpoint, results have been inconclusive. The main reason to process weighted fluids through a centrifuge is to reduce viscosity by removing a portion of the ultra-fine solids. The second centrifuge returns some of these solids to the mud system with the effluent, thereby reducing the overall efficiency. The benefit of this system comes from reduced discharge volume with weighted fluids. This has proven extremely effective in environmentally sensitive areas or whenever cuttings and liquid mud must be hauled from the location prior to disposal.

4. Operating Tips Centrifuges are relatively easy to operate, but they require special skills for repair and maintenance. Rig maintenance of centrifuges is limited to routine lubrication of the unit. Although operating procedures will vary in detail from model to model, a few universal principles apply to virtually all centrifuges:

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* If the solids underflow is to return to the system, locate the centrifuge so the underflow falls into a well-stirred spot. * If the solids underflow is to be discarded, locate the machine so the underflow can be removed periodically. Direct the liquid overflow to a well-stirred spot. * Do not locate the machine solids or liquid returns too close to the rig pump suction. * Allow time and space for adequate mixing. * Liquid effluent lines should have a constant downward slope.

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3. Surface Circulating Equipment A. Introduction A Surface Circulating System includes the equipment and vessels a drilling mud passes through after it emerges from the flow line and before it is delivered to the main rig pumps. It is the surface portion of the active, lowpressure mud system. The operational details of each piece of mud equipment are covered in other sections of this manual. Mud system performance is critical to maintaining a good mud and, therefore, to drilling an acceptable hole. The surface mud system type, size and arrangement are all essential to the mud and drilling performance. All surface circulating systems should be designed to receive the mud returning from the hole through the flow line and restore the mud to the required properties. On occasion, such as during lost circulation or in a kick situation, the mud system must be utilized to mix special materials into the mud very rapidly. Good equipment arrangement and utilization are necessary. If excellent equipment is improperly arranged, the equipment will not be as effective. Depending on the arrangement, the equipment may even be useless. Minor (inexpensive) modifications can frequently change a poor system into a good one. With poor solids control equipment or arrangement, solids will build up in the mud, requiring dilution and/or excessive chemical treatment that results in unnecessarily high mud costs and hole problems. Surface system size (volume) requirements must be considered .prior to the design of a mud system. The required surface volume for rigs with steel tanks is considerably different from the volume required for earthen pits. Furthermore, volumes required for land rigs are different than requirements for offshore rigs; however, all offshore rigs will have steel tanks. All of these items will be discussed in this text.

B. Considerations and Methods for Sizing Surface Mud Systems Surface mud system size partially determines mud costs. The larger the volume of mud (made up and maintained), the higher the cost. Turnkey contractors usually maintain a minimum volume mud system. At the same time, maintenance of good mud properties is critical to filtration control, hole cleaning, and penetration rate. Obviously, the two requirements can be met simultaneously. There are various ways of sizing surface circulating systems. Several factors must be taken into consideration, such as depth capacity of the rig and the area in which it will be working. Obviously, rigs capable of drilling deep wells will require larger mud systems. Conversely, rigs that specialize in drilling shallow wells might want to have a small, one tank mud system that facilitates quick rig moves. Also, rigs drilling wells with high bottom hole temperatures will need larger surface systems to give the drilling fluid longer to cool down before being recirculated. Over the years, rules-of-thumb have been applied to sizing surface systems. Two of these are the PLUGGED BIT METHOD and the CASED HOLE METHOD. As will be illustrated in the examples, each method yields similar results.

1. Plugged Bit Method The plugged bit method determines the minimum-size mud system based on the volume required to fill the hole when pulling a plugged bit. It assumes no mud savers will be used -- all mud inside the drill pipe will be lost. For example, consider a mud system for a rig rated to 20,000 feet, capable of handling 5-inch pipe and 80,000 pounds of drill collars to that depth.

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The total displaced volume is: 20,000' of 5-inch x 0.0243 bbl/ft = 486 bbl 80,000 lbs / 2718 lbs/bbl = 29 bbl Total volume required = 515 bbl This method gives a close approximation of the maximum volume required to fill the hole when tripping a plugged string. Add 20 percent, or 100 bbl, to the 515 bbl as a safety factor. Note that no extra is allowed for a kick or for lost circulation. This method indicates that the minimum-size active mud system should be 615 bbls, plus a reserve to allow for kicks or lost circulation. Usually, the volume of the reserve system should be similar to that of the active system. Total system volume using the plugged bit method is approximately 1230 bbls.

2. Cased Hole Method The cased hole method simply doubles the volume contained in the final string of casing as a guideline for sizing a surface mud system. For example, consider a rig capable of rated to 15,000 feet, with 7-inch casing as the final string. The total eased volume is: 15,000' of 7-in. casing x .0390 bbl/ft = 585 bbl Doubling this volume give a total surface volume (active plus reserve) of approximately 1200 bbl. In land drilling practice, the total volume, minus a small slugging and trip volume, is circulated as the active system. While this may increase the amount of drilled solids which can be tolerated in the mud, it greatly increases the overall mud cost and time required to change mud properties, especially in lost circulation or kick situations.

C. Special Considerations 1. Lost Circulation Zones or Kick Conditions For either of these conditions, special materials must be mixed, and a larger system only slows this operation and makes it more expensive both in mud cost and lost time. Sufficient mud materials and liquid volume should be available to accommodate kick or lost circulation situations. An efficient method of rapidly mixing mud materials should be available. Where lost circulation is common, it may be advantageous to maintain a volume of water and prehydrated gel separate from the active system.

2. Offshore Locations Offshore rigs can be sized using some of the same rules-of-thumb as used for the land rigs, especially jackups. More often than in land operations, offshore installations will incorporate a reserve system with an equal amount of mud as the active circulating system. For example, a jackup rated to 15,000 ft might have an active system of 800 barrels and a reserve system of 800 barrels for 1600 barrels total. Floating rigs, such as semi-submersibles and drill ships, are equipped with a riser system which extends from the BOP stack on the sea floor to the rig on the ocean surface. If the riser must be disconnected in an emergency, the mud inside it will be lost. Many deepwater rigs have adequate reserve capacity to refill the riser if necessary. Since this is a rare occurrence, some rig companies feel this added capacity is not necessary.

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3. Remote Locations Remote drilling locations require adequate onsite storage to reduce transportation costs and operational delays. This will often include bulk storage and additional tanks for water, base oil, and/or completion fluids. It is important these tanks be separate from the active system and kept free from contaminated fluid. In conclusion, pit sizing is largely based on rules-of-thumb combined with the experience and personal preference of the engineers building the rig. The large differences in hole requirements, overall rig size, and operator preferences make it difficult to apply hard, inflexible rules.

D. Sizing Steel Pits Once the volume of the system is determined, the general layout and individual tank size may be considered. There should be sufficient space for solids removal equipment, pit agitators, and fluid transfer pumps. Other considerations are placement of equalizer lines, mud ditches, compartments, pump suction and discharge lines, water lines, and additional operator-specified equipment. Using the earlier example of a 615 bbl system, this system requires approximately: 615 bbl x 5.61 cu ft/bbl = 3,450 cu ft of usable tank volume Assume the rig pumps cannot effectively pick up the bottom 18 inches of mud and most crews run the mud system about one foot below the top of the tank. This means that 2.5 feet of the inside tank height is unusable. For a mud tank height of 8 feet, the usable height is 5.5 feet. With a tank width of 8 feet, each lineal foot of tank length contains: 8' x 5.5' = 44 cu ft In this example, overall tank length should be: 3,450 cu ft / 44 cu ft/ft = 78 ft This length, excluding the sand trap, will be adequate to fill the final string of casing or when tripping with a plugged drill string, if the system is well stirred. The sand trap is not included because it is a settling compartment and is not available to fill the hole. The surface system, excluding the sand trap, must be stirred. Otherwise, solids will settle in the surface pits and the actual mud volume will be reduced. In other words, tank volume without stirring is practically meaningless -- it cannot be estimated or predicted. After the volume of mud necessary is determined and some rough estimates of width, height, and total length (plus sand trap) have been made, each section can be planned. This subject is covered in detail later in this chapter. As noted earlier, the bottom 18 inches of the mud in typical tanks in unavailable for use to fill the hole because the pumps cannot draw adequate suction. This reduces the available volume in the tanks and increases overall mud requirements and overall cost. An innovative tank suction arrangement places the suction at the very bottom of the tank, placing a large flat plate above the suction as a vortex breaker. With this arrangement, it is often possible to draw mud down almost to the plate height before the pump begins to suck air. This increases effective tank volume. Another tank suction arrangement uses a small sump with the pump suction line drawing from this sump. This further increases tank drawdown and maximizes usable tank volume. With either arrangement, well-stirred compartments are required to prevent solids from settling around the tank suction. Common sense should be used to prevent drawdown to extremely low levels.

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E. Earthen Pits Earthen pits are much like the sand trap found in steel tanks - drilling fluids enters at one end of the pit, solids settle throughout its length, and pit suction is taken at the opposite end. In this case, the earthen pit becomes the solids control equipment. The solids and mud from the settling trap are periodically discarded to a waste pit. This form of solids control is called DILUTION, or DUMP/DILUTION, since whole mud and solids are thrown away and replaced by water and other mud materials. The volume requirement for earthen pits is similar to that as for steel tanks. However, the volume available must be increased by the volume of the settled solids that will accumulate prior to jetting. Earthen pits may also be utilized simply as settling areas where the solids are left in the pit under the circulating mud. The earthen pits must contain enough free-flowing slurry to fill the hole and take care of downhole filtration during a trip. the difficult question is, "What percentage of hole cuttings will settle out in the bottom and remain there?" For example, consider a typical 6000 foot well, as shown in Table Y3-1. the amount of cuttings is shown, as well as the total for each section allowing 20% hole enlargement. Table Y3-1 Typical Volume for 6000-Ft Well

Since the cuttings will occupy more space in the pit than the actual hole volume, the earthen pit must be somewhat larger. If all removed cuttings were allowed to settle in the pit and remain there, the pit would need to be contain at least 537 bbl, or 3010 cubic feet of cuttings PLUS volume for loose packing of the cuttings. At a minimum, allow 20 percent additional volume for this loose packing. In this example, the total volume will be: 537 bbl x 1.2 safety factor = 644 bbl With earthen pits, also increase the safety factor for mud volume. Using the plugged bit method, and a 4-1/2 inch drill string with 40,000 lbs of drill collars, the mud volume necessary to fill the hole will be: 6000' x .0205 bbl/ft = 125 bbl 40,000 lbs / 2718 lbs/bbl = 15 bbl Sub-total = 140 bbl Added 40% safety volume = 56 bbl Total = 196 bbl Therefore, a minimum of 196 bbl of mud should be available to the rig pump suction. This well requires earthen pits with 840 bbl available space, not necessarily full or in use at spud. The available volume will gradually decrease as cuttings settle out and fill the pit. At the finish of the drilling operation, the earthen pits will be nearly full of settled solids, but there should be about 200 bbl of mud available to the rig pump.

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There are ways to reduce the size of earthen pits. On method is to use a shale shaker to discard solids outside the earthen pit. If the shaker screens can separate 50% of the solids removed for the hole, the earthen pit mud system can be reduced by that amount. However, the volume placed in a waste pit, or hauled from the location, will be increased by the same amount. Using the previous example, the minimum pit volume needed will be: (640 bbls X 50%) + 200 bbl = 520 bbl (2,640 cu ft) the remaining 320 bbl of sludge discarded by the shaker must be contained in a waste pit or hauled from the location. The advantage of this option is fewer solids in the circulating mud, with less wear and tear on the pumps and bits, and lower overall costs. The previous discussion addresses only the volume requirements of earthen pits. As the well gets deeper, the limitations of earthen pits become readily apparent. Under no circumstances should a weighted mud program be attempted with earthen pits. Solids will settle in an earthen pit system. It is almost impossible to prevent or control. Since the earthen pit is not stirred, this settling removes a most of the weighting material also. This fills the pits prematurely with settled barite particles and makes it difficult and expensive to maintain mud weight. In summary, earthen pits must be sized to hold not only the required amount of drilling mud, but also the drilled solids. They should be used only with unweighted muds with few anticipated hole problems. They should not be used in applications where problems are anticipated overpressured formations requiring weight muds, lost circulation areas, directional wells -- or control of drilling fluid properties must be tightly controlled.

F. Reserve and/or Waste Pits Solids removed from mud system must be disposed of properly. Options include burial, land-farming, and disposal in an approved landfill. While the well is drilled, these solids are stored in a waste pit (sometimes called a reserve pit in land operations since it may also provide a source of make-up fluid.) A typical 20,000 foot well will generate over 4,250 barrels (about 24,000 cubic feet) of drilled solids. In most waste pit situations, these solids will expand to approximately three times the original volume, with liquid filling the additional space. Therefore, approximately 72,000 cu ft of volume must be accommodated. For solids settled 7 ft deep, the waste pit must be 100 ft X 100 ft on the surface. In addition to solids, waste pits must be sized to accommodate the waste liquids in a drilling operation. Depending on the amount of liquid introduced -- wash water or rainfall, type and volume of drilling fluid, and the solids control equipment, the waste pit must be further increased in size. In this example, the waste pit should be approximately 10 ft X 100 ft X 100 ft. Operations involving mud displacement, such as cementing, may require additional waste pit volume. In many cases, reserve or waste pits are not allowed. This requires all the solids and liquids generated must be discharged into steel catch tanks and then hauled away. Waste management, the proper control of solids and liquid discharges, becomes an important consideration. Usually, the solids discharge form the rig solids control equipment, along with wash water, cellar fluids, and sometimes rain water, are collected in steel catch tanks. The sludge is hauled away as the tanks fill. It is important to properly size all equipment: Solids catch tanks, front end loader or track hoe, and trucks. Transportation time, hauling volume per load, cuttings discharge rates, and location size must also be considered. During operation, careful attention should be given to ensure only minimal fluid volume goes into the catch tanks. Frac tanks or other tanks accessible by vacuum truck are available for liquid storage prior to haul-off.

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When oil-based or invert emulsion drilling fluids are used, the rig crews should be guard against contaminated mud or cuttings reaching the ground or sea. Special cuttings-handling systems -- such as conveyors and roll-on, rolloff boxes - are available for these applications. Usually, these systems are furnished by an outside contractor.

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4. System Rig-up Information A. Solids Control System Layout Considerations Other than the drill floor itself, the mud system requires more attention than any other single rig system whether onshore or offshore. For that reason, it is most important that the solids control system is designed to be as efficient and as maintenance free as possible. This section will discuss that pan of the mud system extending from the bell nipple (or diverter housing outlet) to the mud pump suction piping. Other pans of the mud circulating system are discussed in other sections of this manual. Flowline from the bell nipple (or diverter housing) to the shale shakers This flowline is generally a closed pipe ranging from 12 to 24 inches in diameter or a large open trough. The flowline should slope as much as possible to prevent cuttings from accumulating in the line. A slope of one inch or more per running foot is recommended to ensure that the flowline does not plug. The larger size lines are used on rigs having greater circulating rates and/or drilling soft reactive shales called gumbos. These gumbos drill fast, absorb water, swell, and emerge from the bell nipple in large clay-like masses. This gumbo can plug even a properly sloped flowline causing the mud to spill over the top of the bell nipple or trough. Often, roughnecks must continuously clean out the gumbo with shovels and high pressure hoses until this section of hole is completed. The only means to reduce the gumbo problem is to reduce the drilling rate or use an oil base mud. Either of these means may be unacceptable. Many rigs which drill gumbos frequently have installed a separating device called a gumbo box in the flowline close to the bell nipple. The open top of this steel box has parallel steel bars which catch the gumbo balls while letting the liquid mud fall through the bars and continue down the flowline. Roughnecks man the gumbo box and rake the gumbo off the bars continuously while gumbo sections are being drilled. Figure Y4-1 and Figure Y4-2 show the typical location and detail of a gumbo box.

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Figure Y4-1. Typical mud system layout

Most of the gumbo must be removed before the shale shakers to prevent the back tanks and screens from being plugged.

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Figure Y4-2a. Gumbo box - elevation

Figure Y4-2b. Gumbo box - plan view

Shale Shakers Adequate access should be provided around all sides for ease of operation and repair. Additional space may be required at the screen end of the shaker to allow for screen removal. Manufacturer's information should give the required screen removal clearance. Valves or gates should be fitted in the flowline so that the back tank of any shaker may be isolated temporarily for cleaning or repair.

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Degassers The degasser should be located directly over the degasser tank to minimize the elbows and length of suction piping. Manufacturers information should be consulted to determine the optimum height of the degasser above the mud level to optimize the degasser's efficiency.

Desanders, desilters, mud cleaners Adequate access should be provided around all sides to maintain the equipment. This equipment should be close to and on the same level as the shale shakers, if possible, so the roughneck can watch the shakers while he is working on these items.

Centrifuges Again, adequate access should be provided. A clean water source should be provided. The centrifuge must be located on a stiff sub-foundation to prevent vibration and on its dedicated tank top for ease of returning the liquid phase or solids phase to the active mud system. Thought should be given on how solids will be discarded. Operators may require as many as three centrifuges with a tank under each. Special motor starters may be required to prevent a small or heavily loaded power system from blacking out on start up. The inrush current of four or five times running amps may last for 20 seconds or more. A qualified electrical technician or engineer should evaluate each installation to avoid blackout problems.

Sand trap and mud processing tanks The first mud processing tank at, er the shale shakers is typically named the sand trap. Mud enters high in the tank and leaves high in the tank via a weir. Some sand settles by gravity and the tank is periodically bypassed and dumped. This inefficient method of separating some sand (and barite) is becoming less and less popular because of the loss of valuable mud and the problem of direct disposal to the environment. Today's sand trap is often no more than the first mud processing tank having a bottom suction to the first mud processing pump. All mud processing tanks should have V-bottoms with the pump suction being at or very near to bottom. The tank bottom will stay very clean with this configuration. The tanks should be interconnected via high level weirs or low level equalizers so a tank cannot be pumped dry or overflow if a pump fails. Individual mud processing tank capacity ranges from 15 to 75 barrels on today's rigs. Tanks on the order of 30 to 50 barrels each are most common. A tank should contain enough mud to supply its pump for at least one minute with no makeup entering the tank.

Mud processing and mixing pumps These pumps should be located as close to their respective tanks as possible. The pumps should be located several feet below the liquid level in the tank, but in all cases have a flooded suction. No valve, elbow, or tee should be fitted within two pipe diameters of the suction flange (and, if possible, the discharge flange) of any centrifugal pump. Anti-vortex spools are a prudent addition at the pump suction. Only pumps designed to pump abrasive fluids should be used in this service. The shaft sealing system should also be for use with abrasive fluids rather than just clear water. Several shaft sealing techniques are being used successfully in mud service which greatly surpass the life of chevron packing sealing on a steel shaft. If pipe misalignment or flexing is possible, flex joints should be installed between the pump flanges and the pipe flanges. The pump base should be sufficiently rigid to prevent flexing or torquing while the pump is being used. Otherwise, bearing failures will occur in the pump pedestal or drive motor. To minimize the possibility of pump suction lines from clogging up with sand, silt, and barite use the following recommendations: * Suction lines should be kept as short and straight as possible.

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* Avoid large, complicated suction manifolds. * Slope the suction lines at least 1/4 inch per foot from the tank suction to the pump. * Avoid barite traps.

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Figure Y4-3a. Main mud tanks (jack-up arrangement) - Plan view

Figure Y4-3b. Main mud tanks (jack-up arrangement) - Section view

Size the suction piping so that the fluid velocity is at least 4 ft./sec., but no more than 8 ft/sec. (larger diameter pipe may be 10 ft/sec).

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Note the suction line entrance details given on Figure Y4-3. A suction at the V-bottom looking up is best, but a trash guard over the entrance is recommended. A bell mouth entrance looking down is good. A pipe suction flush with the tank wall is fair. A pipe suction extending some distance into the tank is poor.

Active mud pits (or tanks) At least two active pits, two reserve pits, and a slugging pit are typically provided after the mud processing system. The mud weight and chemistry are modified at this part of the mud system. Proper mud pit design and agitator selection and placement are required to keep the solid phase of the mud in suspension. Several tons of barite can settle to the bottom in poorly designed mud pit systems. Long suction pipes should not run through mud pits, but under or beside them. Chamfered corners (deflector plates) in mud pits promote mud agitator efficiency and prevent quiescent areas in the corners that allow barite to settle to bottom. The optimum size and placement of deflector plates will depend on the number and type of agitators and the size of the mud pits. Refer to Figure Y4-4.

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Figure Y4-4. Mud processing pump suction detail - POOR

Figure Y4-4. Mud processing pump suction detail - FAIR

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Figure Y4-4. Mud processing pump suction detail - GOOD

Figure Y4-4. Mud processing pump suction detail - BEST

A loosely fit bottom bearing is recommended on longer agitator shafts to prevent the shaft from whipping and bending on start up. Mud guns are relatively expensive devices to operate from the standpoint of pump maintenance and barite degradation. Good mud tank design and good agitation are a more cost effective means of keeping barite in suspension.

Notes on Safety Design mud processing and mud pit areas to be safe. Mud residue on a steel deck presents an extreme slip hazard. Use serrated steel grating or fiberglass grating with a non-slip surface wherever possible. Non-slip stairway treads are a must. Use properly built handrails with toe plates along all walkways, stairs, and pit tops. Maintain a safe lighting level around all equipment, stairs, and walkways. Wash equipment and clean up mud spills as soon as possible. Eye wash stations should be provided throughout the surface mud system areas. Proper protective clothing in good condition should always be readily available to those mixing mud. Some combination of goggles, dust masks, face shields, rubber gloves and rubber aprons are required depending on the particular chemicals being mixed.

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Spilled chemicals and bags should be cleaned up quickly and disposed of in a proper manner according to company policy and/or environmental regulations. A responsible qualified person should periodically inspect all electrical devices, electric cable and fittings for physical damage or excessive corrosion. A shock hazard or explosion hazard can exist if this special equipment is not maintained in a proper state. Always use an approved Classified Area electrical device or fitting in an area requiring Division I / Zone I or Division II / Zone II explosion proof or vapor tight electrical devices and fittings.

B. Centrifugal Pump Selection and Piping Design The purpose of this section is to present some guidelines and simplified techniques to size pumps and piping typically used in mud systems. If unusual circumstances exist such as unusually long or complicated pipe runs or if very heavy or viscous drilling muds are used, a qualified engineer should analyze the system in detail and calculate an exact solution.

Definitions Total Head To write about pumps, one must use words that are known and well understood. For example, the label on the lefthand side of any centrifugal pump curve is Total Head Feet. What does this mean? The simplest way to flow water is to lay a length of pipe on the level ground and connect it to a standpipe (Figure Y4-5). Water from the standpipe will flow steadily through the pipe. It flows faster when there is greater depth of water in the standpipe. The depth of water measured down the standpipe to the pipe connection centerline is the Total Head. Total Head remains constant for a particular pump operated at a constant speed regardless of the fluid being pumped. However, a pump's pressure will increase as the fluid density (mud weight) increases according to the following relationship: PMUD(PSIG) = PWATER(PSIG) x {FLUID DENSITY(LBS/GAL)}/8.34 If a pump produces 200 ft-hd, then it follows that the pressure developed when pumping water will be: PWATER = 200 FT-HD x 0.433 (PSIG/FT) x {FLUID DENSITY(LBS/GAL)}/8.34 PWATER = 200 FT-HD x 0.433 X 8.34/8.34 = 86.6 PSIG NOTE: Fresh water weighs 8.34 lbs/gal. The pressure developed when pumping 16 lb mud will be: PMUD = 200 FT-HD x 0.433(PSIG/FT) x (16/8.34)LBS/GAL = 166.1 PSIG Note that the pump pressure almost doubled. It follows that the required pump horsepower has increased by the same percentage. If the pump required 50 HP for water service, it will require the following horsepower for 16 lb/ gal mud: HP2 = HPWATER x (16/8.34) LBS/GAL = 50 x 1.92 = 95.9 HP To summarize, a pump's Total Head remains constant for any fluid pumped, only the pump pressure and pump horsepower will change. Therefore, a pump motor must be sized according to the heaviest weight mud to be pumped. Pressure Head

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Pressure Head is simply the distance in feet that water will rise up a sight tube connected anywhere to a pipe with liquid in it (see Figure Y4-5). Figure Y4-5. Water flow in a pipe

In our example problem, the required desilter pressure head is 75 ft. for any mud weight. However, the pressure would be 30.3 PSIG for water or 43.6 PSIG for 12 lb mud or 58.1 PSIG for 16 lb mud. A good rule of thumb is that the required pressure (PSIG) equals 4 times the mud weight (12 LB/GAL x 4 = 48 PSIG). Fluid Fluid is a general term meaning water, brine, mud, oil or any other liquid being pumped. Flow Rate Flow Rate will be expressed in gallons per minute, barrels per minute or cubic feet per second. Velocity (V) Velocity of the fluid down the pipe is the average velocity across the inside diameter and is expressed in FT/SEC. Velocity head Velocity Head is an expression of the energy required to accelerate the fluid from 0 FT/SEC in the suction tank up to the velocity of the fluid in the pipe. VELOCITY HEAD = {(V)2}/(2G) G = (GRAVITATIONAL CONSTANT) = 32.2 FT/SEC/SEC The following charts may be used for velocity head ranges of our design fluid velocities. Velocity (V)

Velocity Head

(VH)

5 FT/SEC

0.39

FT-HD

10 FT/SEC

1.55

FT-HD

15 FT/SEC

3.49

FT-HD

20 FT/SEC

6.21

FT-HD

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Velocity head is generally not a large number but should be included in pump calculations. Example Problem We will size a pump and piping for desilter service. the desilter is a typical 16 cone unit equipped with 4" diameter hydrocyclones. Figure Y4-6. Typical desilter piping arrangement

STEP ONE Determine the required pressure head and flow rate. If the pump is to supply a device such as a mud mixing hopper or a desilter, consult the manufacturer's information or sales representative to determine the optimum flow rate and pressure head required at the device. (On devices like desilters the pressure head losses downstream of the device are considered negligible and are usually disregarded.) Our desilter cones require 50 GPM each at an inlet pressure head of 75 FT-HD. therefore, the total capacity will become: 16 CONES x 50 GPM = 800 GPM AT 75 FT-HD STEP TWO Select the basic pump to pump the desired flow rate. Its best to refer to a manufacturer's pump curve for your particular pump. (See example - Figure Y4-7).

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Figure Y4-7. Water Capacity - US gallons per minute

If a curve is not available, this chart below gives reasonably accurate values for typical centrifugal pumps used for mud service. The values in Table Y4-1 represent the approximate maximum capacity and pressure head (FT-HD) for a given pump and speed.

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Table Y4-1. Capacity and Pressure for Various Pump Sizes

The pump's impeller may be machined to a smaller diameter to reduce its pressure for a given application. Refer to the manufacturer's pump curves or manufacturer's representative to determine the proper impeller diameter. Excessive pressure and flow should be avoided for the following reasons: 1. Pump wears at a faster rate. 2. Equipment such as hydrocyclones wear at a faster rate. 3. Hydrocyclones do not operate effectively at a higher or lower pressure than specified. 4. A larger electric motor, electric cable, and starter may be required unnecessarily. 5. Energy cost to operate the pump will be greater. The pump must produce more than 75 FT-HD at the pump if 75 FT-HD is to be available at the desilter inlet and the pump's capacity must be at least 800 GPM. Therefore, we should consider using one of the following pumps from the above list: 4" x 5" Pump 1750 RPM - 1000 GPM at 160 FT-HD; or 5" x 6" Pump 1750 RPM - 1200 GPM at 160 FT-HD STEP THREE Size the piping. The pump suction and discharge piping is generally the same diameter as the pump flange diameters. The resulting fluid velocities will then be within the recommended ranges of 4 to 10 FT/SEC for suction lines and 4 to 12 FT/ SEC for discharge lines. Circumstances may dictate that other pipe diameters be used, but remember to try to stay within the above velocity guidelines. Smaller pump discharge piping will create larger pressure drops in the piping and the pump may not be able to pump the required amount of fluid. (For example, don't use a 4" discharge pipe on a 6" x 8" pump and expect the pump's full fluid flow.) Find the proposed pipe diameter and flow rate in the attached tables (Figure Y4-8) and confirm that the velocities are reasonable.

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FIGURE Y4-8. Friction loss for water or mud in feet head per 100 feet of pipe (f = 0.03) with or without pipe fittings

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Note the Velocity Head, Friction Loss per 100 FT pipe and Friction Loss per 100 FT Pipe with Fittings.

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For our desilter flow of 800 GPM, note from the attached tables: For 4" pipe Velocity = 20.2 FT/SEC Velocity Head = 6.32 FT Friction Loss per 100 FT Pipe = 32.4 FT For 5" pipe Velocity = 12.8 FT/SEC Velocity Head = 2.56 FT Friction Loss per 100 FT Pipe = 10.22 FT For 6" pipe Velocity = 8.88 FT/SEC Velocity Head = 1.23 FT Friction Loss per 100 FT Pipe = 4.03 FT For 8" pipe Velocity = 5.13 FT/SEC Velocity Head = 0.41 FT Friction Loss per 100 FT Pipe = 1.02 We may conclude from the above data that: * 4" pipe should not be used for either suction or discharge piping. The velocity and pressure drop are too high. * 5" pipe should not be used for suction pipe (Vmax = 8 to 10 FT/SEC) but could be used for discharge pipe (Vmax = 10-12 FT/SEC) since V = 12.88 FT/SEC. * 6" pipe may be used for the suction pipe since it is relatively short and straight and the pump suction is always flooded. 6" pipe is fully acceptable for the discharge pipe and is a good choice since the desired header is probably 6" pipe. * 8" pipe may be used for the suction pipe (V = 5.13 FT/SEC) since V is still greater than 4 FT/SEC. 8" pipe would be preferred if the suction is long or the suction pit fluid level is low with respect to the pump. We will use 6" pipe for both the suction and discharge piping and will use the 5" x 6" Pump -1750 RPM. STEP FOUR We now determine the total pressure head requirement of our piping system: Total Pressure Head = Velocity Head + Pipe Losses + Vertical Head + Head Requirement of Desilter Velocity Head VEL-HD = 1.23 FT for 6" pipe and velocity = 8.88 FT/SEC (Step Three) Vertical Head From Figure Y4-6 we see that the vertical distance from the pump to the desilter inlet is 7 FT.

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Therefore, the vertical head requirement = 7 FT. Pipe Losses We will assume that we have 60 FT of pipe, four elbows and one butterfly valve in the system. You may use Figure Y4-8 alone for a simplified solution. FIGURE Y4-8. Friction loss for water or mud in feet head per 100 feet of pipe (f = 0.03) with or without pipe fittings Find the chart for 6" pipe and look up the velocity closest to 8.88 FT/SEC. 8.88 does appear on the chart. The friction loss per 100 FT of pipe with fittings is 11.01 FT. Since we only have 60 ft of pipe, our friction loss is: 11.01 FT x (60/100) = 6.6 FT-HD If a more exact solution is required, the loss from pipe fittings can be determined from Figure Y4-9.

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Figure Y4-9. Friction loss in pipe fittings in equivalent feet of straight pipe

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Notes on Figure Y4-9 <4> Most of this data was taken by permission from page 49, Cameron Hydraulic Data, Ingersoll-Rand Company, Washington, N.J. 1962. <5> The butterfly valve data was furnished by TRW Mission Mfg. Co., Houston, TX.

So, 4 elbows x 10 = 40 FT of pipe 1 butterfly valve (open) = 11 FT of pipe Total = 51 FT of pipe Then 60 ft (straight pipe) + 51 FT (equivalent length) = 111 total feet pipe. The "Friction Loss per 100 ft of Straight Pipe" from Figure Y4-7: is 7.32 FT for (6" pipe and V = 8.88). Then the total pressure drop is: 7.32 FT x (111/100) = 8.3 FT The first solution of 6.6 FT is reasonably close to 8.3 FT, although 8.3 FT is more accurate. We will use 8.3 FT. Head Requirement of Desilter We know from Step One that the desilter requires 75 FT-HD at its inlet. Therefore, Total Pressure Head = 1.23 FT + 7FT + 8.3FT + 75FT = 91.53 FT Our 5 x 6 - 1750 RPM pump will supply more than enough mud to the desilter. However, the pump's impeller must be machined to a smaller diameter for economical operation. See Step Five. STEP FIVE - Size Impeller and Electric Motor Refer to Figure Y4-7. Note that this pump curve is for the pump we selected. * Find 92 total head feet on the vertical axis. * Find 800 GPM on the horizontal axis. * Find the intersection on the graph of these two values. Note that the impeller diameter should be 9-1/2 inches and the actual pump horsepower using water is about 26. Recall from the previous definition of Total Head, that the pump horsepower required for 16 LB/GAL mud will be: HPMUD = HPWATER x (16/8.34) ppg = 26 x 1.92 = 49.9 HP If the mud weight could increase above 16 LB/GAL then the 60 HP motor should be selected. Also, note that if the pump will also be used to transfer mud through an open-ended pipe, a flow rate of 1600 GPM could be achieved. At this flow rate,

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HPMUD = 44 x (16/8.34) = 84.4 HP A larger motor must be specified or the pump flow must choked to prevent overloading the electric motor when transferring mud.

C. Mud Troughs After the Shale Shakers Mud troughs (or ditches) are the next most common means of moving mud throughout the surface system after pipes. They are simple, effective, easy to follow and easy to clean. The only real problem with troughs is the tendency of barite and cuttings to settle and clog the troughs. Troughs should be sized so that the average velocity of the mud is no less than 4 FT/SEC and no more than 8 FT/ SEC. Frequent clogging will occur if the velocity is less than 4 FT/SEC. Excessive slopes and messy splashing will occur if the velocity exceeds 8 FT/SEC. Troughs should always have at least 1/4 inch per foot slope so they will tend to be selfcleaning. (If a trough is used between the bell nipple and the shakers, its slope may need to be 1 inch or more per foot.) The following chart may be used to size troughs on rigs that remain level (land, platform, bottom resting and jack-ups). Floating rigs may require additional slope to offset the effects of roll and pitch.

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Table Y4-2a. Mud Trough Sizing, 8" wide x 8" high

Table Y4-2b. Mud Trough Sizing, 12" wide x 12" high

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Table Y4-2c. Mud Trough Sizing, 15" wide x 15" high

Table Y4-2d. Mud Trough Sizing, 18" wide x 18" high

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Chapter Z Glossary

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Table of Contents - Chapter Z Glossary IADC Glossary - A ............................................................................................................................ Z-3 IADC Glossary - B ............................................................................................................................ Z-4 IADC Glossary - C ............................................................................................................................ Z-7 IADC Glossary - D .......................................................................................................................... Z-10 IADC Glossary - E ........................................................................................................................... Z-13 IADC Glossary - F ........................................................................................................................... Z-13 IADC Glossary - G .......................................................................................................................... Z-15 IADC Glossary - H .......................................................................................................................... Z-17 IADC Glossary - I ............................................................................................................................ Z-18 IADC Glossary - J ........................................................................................................................... Z-19 IADC Glossary - K .......................................................................................................................... Z-20 IADC Glossary - L ........................................................................................................................... Z-20 IADC Glossary - M ......................................................................................................................... Z-21 IADC Glossary - N .......................................................................................................................... Z-23 IADC Glossary - O .......................................................................................................................... Z-23 IADC Glossary - P ........................................................................................................................... Z-24 IADC Glossary - Q .......................................................................................................................... Z-26 IADC Glossary - R .......................................................................................................................... Z-26 IADC Glossary - S ........................................................................................................................... Z-30 IADC Glossary - T ........................................................................................................................... Z-34 IADC Glossary - U .......................................................................................................................... Z-36 IADC Glossary - V .......................................................................................................................... Z-36 IADC Glossary - W ......................................................................................................................... Z-36 IADC Glossary - X .......................................................................................................................... Z-38 IADC Glossary - Y .......................................................................................................................... Z-38 IADC Glossary - Z ........................................................................................................................... Z-38

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Chapter Z IADC Drilling Manual 11th Edition - Glossary of Terms IADC Glossary - A abandon v: to cease producing oil and gas from a well when it becomes unprofitable or to cease further work on a newly drilled well when it proves not to contain profitable quantities of oil or gas. Several steps are involved: part of the casing may be removed and salvaged; one or more cement plugs are placed in the borehole to prevent migration of fluids between the different formations penetrated by the borehole; and the well is abandoned. In most oil-producing states, it is necessary to secure permission from official agencies before a well may be abandoned. absolute permeability n: a measure of the ability of a single fluid (such as water, gas, or oil) to flow through a rock formation when the formation is totally fried (saturated) with that fluid. The permeability measure of a rock filled with a single fluid is different from the permeability measure of the same rock filled with two or more fluids. Compare effective permeability. absolute porosity n: the percentage of the total bulk volume of a rock sample that is composed of pore spaces or voids. See porosity. acid fracture v: to part or open fracture in production hard limestone formations by using a combination of oil and acid or water and acid under high pressure. See formation fracturing. acidize v: to treat oil-bearing limestone or other formations with acid for the purpose of increasing production. Hydrochloric or other acid is injected into the formation under pressure. The acid etches the rock, enlarging the pore spaces and passages through which the reservoir fluids flow. Acid also removes formation damage by dissolving material plugging the rock surrounding the wellbore. The acid is held under pressure for a period of time and then pumped out, after which the well is swabbed and put back into production. Chemical inhibitors combined with the acid prevent corrosion of the pipe. acoustic log n: a record of the measurement of porosity, done by comparing depth to the time it takes for a sonic impulse to travel through a given length of formation. The rate of travel of the sound wave through a rock depends on the composition of the formation and the fluids it contains. Because the type of formation can be ascertained by other logs, and because sonic transit time varies with relative amounts of rock and fluid, porosity can usually be determined in this way. adjustable choke n: a choke in which the position of a conical needle, sleeve, or plate may be changed with respect to their seat to vary the rate of flow; may be manual or automatic. See choke. air-actuated adj: powered by compressed air, as are the clutch and the brake system in drilling equipment. air drilling n: a method of rotary drilling that uses compressed air as the circulation medium. The conventional method of removing cuttings from the wellbore is to use a flow of water or drilling mud. Compressed air removes the cuttings with equal or greater efficiency. The rate of penetration is usually increased considerably when air drilling is used; however, a principal problem in air drilling is the penetration of formations containing water, since the entry of water into the system reduces the ability of the air to remove the cuttings. American Petroleum Institute (API) n: oil trade organization (founded in 1920) that is the leading standardizing organization for oilfield drilling and producing equipment. Its official publications are Petroleum Today and Washington Report. Address: 1220 L St., N.W.; Washington, DC 20005; (202) 6828000. anchor deadline n: means of holding the deadline to the derrick or substructure. Usually this is the primary element of the weight indicator.

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angle of deflection n: in directional drilling, the angle, expressed in degrees, at which a well is deflected from the vertical by a whipstock or other deflection tool. annular blowout preventer n: a large valve, usually installed above the ram preventers, that forms a seal in the annular space between the pipe and the wellbore or, if no pipe is present, in the wellbore itself. Compare ram blowout preventer. annular space n: 1. the space surrounding a cylindrical object within a cylinder. annular space n: 2. the space around a pipe in a wellbore, the other wall of which may be the wall of either the borehole or the casing; sometimes termed the annulus. anticline n: an arched, inverted-trough configuration of folded rock layers. Compare syncline. API abbr: American Petroleum Institute API gravity n: the measure of the density of gravity of liquid petroleum products in the United States; derived from relative density in accordance with the following equation: API gravity at 60 degrees F = (141.5 + relative density 60/60 degrees F ) - 131.5 API gravity is expressed in degrees, 10 degrees API being equivalent to 1.0, the relative density of water. automatic driller n: Mechanism to automatically control weight on the bit.

IADC Glossary - B back off v: to unscrew one threaded piece (such as a section of pipe) from another. back up v: to hold one section of an object such as pipe while another section is being screwed into or out of it. back-up tong n: A tong suspended in the derrick, normally on the drillers right, used to hold box end of the joint (lower half) while the pin end (upper half) is loosened and unscrewed. Also called makeup tong, as it is moved to pin end to tighten the joint to recommended torque after joint is spun in when going in the hole. ball n: a cylindrical steel bar (similar in form to the handle or bail of a bucket, but much larger) that supports the swivel and connects it to the hook. Sometimes, the two cylindrical bars that support the elevators and attach them to the hook are also called bails or links. v: to recover bottomhole fluids, samples,mud, sand, or drill cuttings by lowering a cylindrical vessel called a bailer to the bottom of a well, filling it, and retrieving it. bailer n: a long, cylindrical container fitted with a valve at is lower end, used to remove water, sand, mud, drilling cuttings, or oil from a well in cable-tool drilling. bailing line n: the cable attached to a bailer, passed over a sheave at the top of the derrick, and spooled on a reel. barge n: any one of may types of flat-decked, shallow draft vessels, usually towed by a boat. A complete drilling rig may be assembled on a drilling barge, which usually is submersible; that is, it has a submersible hull or base that is flooded at the drilling site. Drilling equipment and crew quarters are mounted on a superstructure above the water level. barite or baryte n: barium sulfate, BaSO4; a mineral frequently used to increase the weight or density of drilling mud. Its relative density is 4.2 (i.e., it is 4.2 times denser than water). See barium sulfate, mud. barium sulfate n: a chemical compound of barium, sulfur, and oxygen (BaSO4), which may form a tenacious seale that is very difficult to remove. Also called barite. barrel (bbl) n: 1. a measure of volume for petroleum products in the United States. One barrel is the equivalent of 42 U.S. gallons or 0.15899 cubic metres (9702 cubic inches). On cubic metre equals 6.2897 barrels.

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barrel (bbl) n: 2. the cylindrical part of a sucker rod pump in which the pistonlike plunger moves up and down. Operating as a piston inside a cylinder, the plunger and barrel create pressure energy to lift well fluids to the surface. basket sub n: a fishing accessory run above a bit or a mill to recover small, non-drillable pieces of metal or junk in a well. bed n: a specific layer of earth or rock that presents a contrast to other layers of different material lying above, below, or adjacent to it. bell nipple n: A short piece of pipe, expanded, or belled, at the top to guide tools into the hole. Usually has side connections for the fill-up and mud return lines. belt n: a flexible band or cord connecting and wrapping around each of two or more pulleys to transmit power or impart motion. bentonite n: A finely powdered gray material used in preparing drilling mud. Usually referred to on the rig as "gel". bit n: the cutting or boring element used in drilling oil and gas wells. The bit consists of a cutting element and a circulating element. The circulating element permits the passage of drilling fluid and utilized the hydraulic source of the fluid stream to improve drilling rates. Most bits used in rotary drilling are roller cone bits. bit breaker n: a heavy plate that fits in the rotary table and holds the drill bit while it is being made up in or broken out of the drill stem. See bit. bit record n: a report that lists each bit used during a drilling operation, giving the type, the footage it drilled, the formation it penetrated, its condition, and so on. blind ram n: an integral part of a blowout preventer, which serves as the closing element on an open hole. Its ends do not fit around the drill pipe but seal against each other and shut off the space below completely. block n: any assembly of pulleys on a common framework; in mechanics, one or more pulleys, or sheaves, mounted to rotate on a common axis. The crown block is an assembly of sheaves mounted on beams at the top of the derrick or mast. The drilling line is reeved over the sheaves of the crown block alternately with the sheaves of the traveling block, which is raised and lowered in the derrick or mast by the drilling line. When elevators are attached to a hook on the traveling block and drill pipe is latched in the elevators, the pipe can be raised or lowered. See crown block, drilling block, elevators, hook, reeve, sheave, and traveling block. blooey line n: the discharge pipe from a well being drilled by air drilling. The blooey line is used to conduct the air or gas used for circulation away from the rig to reduce the fire hazard as well as to transport the cuttings a suitable distance from the well. See air drilling. blowout n: an uncontrolled flow of gas, oil, or other well fluids into the atmosphere. A kick warns of the possibility of a blowout. blowout preventer n: one of several valves installed at the wellhead to prevent the escape of pressure either in the annular space between the easing and drill pipe or in open hole (i.e. hole with no drill pipe) during drilling or completion operations. Blowout preventers on land rigs are located beneath the rig at the land's surface; on jackup or platform rigs, at the water's surface; and on floating offshore rigs, on the sea floor. See annular blowout preventer, inside blowout preventer, ram blowout preventer. boll weevil n: (slang) an inexperienced rig or oilfield worker; sometimes shortened to weevil. bomb n: a thick-walled container, usually steel, used to hold devices that determine and record pressure or temperature in a wellbore. See bottomhole pressure. bond n: the adhering or joining together of two materials (as cement to formation). v. to adhere or to join to another material.

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BOP abbr: blowout preventer. borehole n: a hole made by drilling or boring. See wellbore. bottomhole n: the lowest or deepest part of a well. adj: pertaining to the bottom of the wellbore. bottomhole choke n: a device with a restricted opening placed in the lower end of the tubing to control the rate of flow. See choke. bottomhole pressure n: 1. the pressure at the bottom of a borehole. It is caused by the hydrostatic pressure of the wellbore fluid and, sometimes, by any back-pressure held at the surface, as when the well is shut in with blowout preventers. bottomhole pressure n: 2. the pressure in a well at a point opposite the producing formation. bottom-supported offshore drilling rig n: a type of mobile offshore drilling unit (MODU) that has a part of its structure in contact with the sea floor when it is on site and drilling a well. The remainder of the rig is supported above the water. The rig can float, however, allowing it to be moved from one drill site to another. Bottom supported units include submersible rigs and jackup rigs. See mobile offshore drilling unit. box n: the female section of a connection. See tool joint. brake n: a device for arresting the motion of a mechanism, usually by means of friction, as in the drawworks brake. Compare electrodynamic brake, hydromatic brake. breaking down v: Usually means unscrewing the drill stem into single joints and placing them on the pipe rack. This operation takes place at the completion of the well when the drill pipe will no longer be used. It also takes place when changing from one size drill pipe to another during drilling operations. break out v: 1. to unscrew one section of pipe from another section, especially drill pipe while it is being withdrawn from the wellbore. During this operation, the tongs are used to start the unscrewing operation. See tongs. break out v: 2. to separate, as gas from a liquid or water from an emulsion. breakout cathead n: a device attached to the catshaft of the drawworks that is used as a power source for unscrewing drill pipe; usually located opposite the driller's side of the drawworks. See cathead. breakout tongs n: tongs that are used to start unscrewing one section of pipe from another section, especially drill pipe coming out of the hole. See tongs. bridge n: An obstruction in the drill hole. A bridge is usually formed by caving of the wall of the wellbore or by the intrusion of a large boulder. bring in a well v: to complete a well and put it on producing status. buck up v: to tighten up a threaded connection (such as two joints of drill pipe). bug blowers n: A large fan installed on a drilling rig to blow insects away from the work area. bullet perforator n: a tubular device that, when lowered to a selected depth within a well, fires bullets through the casing to provide holes through which the formation fluids may enter the wellbore. by heads n: a term applied to a flowing well when the flow is made intermittently. by-pass n: usually refers to a pipe connection around a valve or other control mechanism. A by-pass is installed in such cases to permit passage of fluid through the line while adjustments or repairs are made on the control which is by-passed.

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IADC Glossary - C cable n: a rope of wire, hemp, or other strong fibers. See wire rope. cable-tool drilling n: a drilling method in which the hole is drilled by dropping a sharply pointed bit on bottom. The bit is attached to a cable, and the cable is repeatedly dropped as the hole is drilled. caprock n: 1. a disk-like plate of anhydrite, gypsum, limestone, or sulfur overlying most salt domes in the Gulf Coast region. caprock n: 2. impermeable rock overlying an oil or gas reservoir that tends to prevent migration of oil or gas out of the reservoir. cased adj: pertaining to a wellbore in which casing has been run and cemented. See casing. casing n: steel pipe placed in an oil or gas well as drilling progresses to prevent the wall of the hole from caving in during drilling, to prevent seepage of fluids, and to provide a means of extracting petroleum if the well is productive. casing centralizer n: a device secured around the casing at regular intervals to center it in the hole. Casing that is centralized allows a more uniform cement sheath to form around the pipe. casing coupling n: a tubular section of pipe that is threaded inside and used to connect two joints of casing. casing elevator n: See elevators. casinghead n: a heavy, flanged steel fitting connected to the first string of casing. It provides a housing for slips and packing assemblies, allows suspension of intermediate and production strings of casing, and supplies the means for the annulus to be sealed off. Also called a spool. casing shoe n: see guide shoe. casing string n: the entire length of all the joints of casing run in a well. Casing is manufactured in lengths of about 30 feet (9 metres), and each length or joint is joined to another as casing is run in a well. catwalk n: elongated platform adjacent to the rig floor where pipe is laid out and lifted into the derrick. The catwalk is connected to the rig floor by a pipe ramp. catch samples v: to obtain cuttings for geological information as formations are penetrated by the bit. The samples are obtained from drilling fluid as it emerges from the wellbore or, in cable-tool drilling, from the bailer. See bailer, cable-tool drilling, cuttings. cathead catshaft, wound. cathead, n: a spool shaped attachment on the end of the around which rope for hoisting and pulling is Also called automatic cathead. See breakout makeup cathead. catline n: a hoisting or pulling line powered by the cathead and used to lift heavy equipment on the rig. See cathead. caving n: the collapse of the walls of the wellbore; also called sloughing. cellar n: a pit in the ground, usually lined with concrete or steel pipe, that provides additional height between the rig floor and the wellhead to accommodate the installation of blowout preventers, rathole, mousehole, and so forth. It also collects drainage water and other fluids for subsequent disposal. cement case v: to fill the annulus between the casing and wall of the hole with cement to support the casing and prevent fluid migration between permeable zones.

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cement channeling n: when casing is being cemented in a borehole, the cement slurry can fail to rise uniformly between the casing and the borehole wall, leaving spaces devoid of cement. Ideally, the cement should completely and uniformly surround the easing and form a strong bond to the borehole wall. cementing n: the application of a liquid slurry of cement and water to various points inside or outside the easing. See primary cementing, secondary cementing, squeeze cementing. centralizers n: Spring steel guides which are attached to casing and which serve to keep it centered in the hole. chain drive n: a mechanical drive using a driving chain and chain gears to transmit power. Power transmissions use a roller chain, in which each link is made of side bars, transverse pins, and rollers on the pins. A double roller chain is made of two connected rows of links, a triple roller chain of three, and so forth. chain tongs n pl: a tool consisting of a handle and releasable chain used for turning pipe or fittings of a diameter larger than that which a pipe wrench would fit. The chain is looped and tightened around the pipe or fitting, and the handle is used to turn the tool so that the pipe or fitting can be tightened or loosened. changing rams n: Rams are the flexible elements which accomplish the sealing effect of the blowout preventer. It is necessary to change the rams when drill pipe of a different size than that previously used is put in service. check valve n: a valve that permits flow in one direction only. If the gas or liquid starts to reverse, the valve automatically closes, preventing reverse movement. Commonly referred to as a one-way valve. choke n: a device with an orifice installed in a line to restrict the flow of fluids. Chokes are also used to control the rate of flow of the drilling mud out of the hole when the well is closed in with the blowout preventer and a Kick is being circulated out of the hole. See adjustable choke, blowout preventer, bottomhole choke, Christmas tree, Kick, nipple, positive choke. choke line n: a pipe attached to the blowout preventer stack out of which kick fluids and mud can be pumped to the choke manifold when a blowout preventer is closed in on a kick. choke manifold n: an arrangement of piping and special valves, called chokes. In drilling, mud is circulated through a choke manifold when the blowout preventers are closed; a choke manifold is also used to control the pressures encountered during a Kick. In well testing, a choke manifold attached to the wellhead allows flow and pressure control for test components downstream. See choke, blowout preventer. circulate v: to pass from one point throughout a system and back to the starting point. For example, drilling fluid is circulated out of the suction pit, down the drill pipe and drill collars, out the bit, up the annulus, and back to the pits while drilling proceeds. circulation n: the movement of drilling fluid out of the mud pits, down the drill stem, up the annulus, and back to the mud pits. circulating fluid - drilling fluid, mud n: A fluid consisting of water, oil or other liquid and containing clay, weighting materials and/or chemicals which is circulated through the drill pipe and wellbore during rotary drilling and workover operations. CMC n: Sodium Carboxymethylcellulose. A nonfermenting cellulose product used in drilling fluids to combat contamination from anhydrite (gyp) and lower the water loss from the drilling fluid to the formation. Water with more than 20,000 ppm of salt (sodium chloride), reduces its effectiveness as a treating agent. combination string n: a casing string with joints of various collapse resistance, internal yield strength and tensile strength, designed for various depths in a specific well to best withstand the conditions of that well. come out of the hole v: to pull the drill stem out of the wellbore to change the bit, to change from a core barrel to the bit, to run electric logs, to prepare for a drill stem test, to run casing, and so on. Also called trip out. company man n: see company representative.

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company representative n: an employee of an operating company whose job is to represent the company's interest at the drilling location. complete a well v: to finish work on a well and bring it to productive status. See well completion. compound n: 1. a mechanism used to transmit power from the engines to the pump, the drawworks, and other machinery on a drilling rig. It is composed of clutches, chains and sprockets, belts and pulleys, and a number of shafts, both driven and driving. compound n: 2. a substance formed by the chemical union of two or more elements in definite proportions, the smallest particle of a chemical compound is a molecule. v: to connect two or more power-producing devices, such as engines, to run driven equipment, such as the drawworks. conductor pipe n: 1. a short string of large-diameter casing used to keep the wellbore open and to provide a means of conveying the up-flowing drilling fluid from the wellbore to the mud pit. conductor pipe n: 2. a boot. contract depth n: the depth of the wellbore at which a drilling contract is fulfilled. core n: a cylindrical sample taken from a formation for geological analysis. Usually a conventional core barrel is substituted for the bit and procures a sample as it penetrates the formation. See also sidewall coring. v: to obtain a formation sample for analysis. core analysis n: laboratory analysis of a core sample to determine porosity, permeability, lithology, fluid content, angle of dip, geological age, and probable productivity of the formation. core barrel n: a tubular device, usually from 10 to 60 feet (3 to 18 metres) long, run at the bottom of the drill pipe in place of a bit and used to cut a core sample. core catcher n: the part of the core barrel that holds the formation sample. core cutterhead n: the cutting element of the core barrel assembly. In design it corresponds to one of the three main types of bits; drag bits with blades for cutting soft formations; roller bits with rotating cutters for cutting medium-hard formations; and diamond bits for cutting very hard formations. coupling n: 1. in piping, a metal collar with internal threads used to join two sections of threaded pipe. coupling n: 2. In power transmission, a connection extending longitudinally between a driving shaft and driven shaft. Most such couplings are flexible and compensate for minor misalignment of the two shafts. crater v: term meaning the hole is caving in. To crater refers to the results that sometime accompany a violent blowout during which the surface surrounding the wellbore falls into a large hole blown in the earth by the force of escaping gas, oil, and water. To crater also refers in oilfield slang to any mishap which may occur to the men or the equipment. crooked hole n: a wellbore that has been unintentionally drilled in a direction other than vertical. It usually occurs where there is a section of alternating hard and soft strata steeply inclined from the horizontal. crown block n: an assembly of sheaves mounted on beams at the top of the derrick and over which the drilling line is reeved. See block, reeve, sheave. cuttings n pl: the fragments of rock dislodged by the bit and brought to the surface in the drilling mud. Washed and dried cuttings samples are analyzed by geologists to obtain information about the formations drilled.

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IADC Glossary - D daylight tour (pronounced "tower") n: in areas where three 8-hour tours are worked, the shift of duty on a drilling rig that starts at or about daylight. Compare evening tour and graveyard tour. day work v: the basis for payment in which contractor is paid by the operator at an agreed upon daily rate. This is in lieu of a footage rate and covers drilling at extreme depths ,many offshore drilling operations, drilling hazardous conditions, and other instances where normal drilling operations are suspended at the request of the operator. deadline n: the drilling line from the crown block sheave to the anchor, so called because it does not move. Compare fastline. deadline tie-down anchor n: a device to which the deadline is attached, securely fastened to the mast or derrick substructure. Also called a dead-line anchor. dead man n: a buried anchor to which guy-wires are tied to steadily the derrick, boiler stacks, etc. degasser n: the device used to remove unwanted gas from a liquid, especially from drilling fluid. density n: the mass or weight of a substance per unit volume. Specific gravity, relative density, and API gravity are other units of density. See API gravity, specific gravity. derrick n: a large load-bearing structure, usually of bolted construction. In drilling, the standard derrick has four legs standing at the corners of the substructure and reaching to the crown block. The substructure is an assembly of heavy beams used to elevate the derrick and provide space to install blowout preventers, casingheads, and so forth. derrickman n: the crew member who handles the upper end of the drill string as it is being hoisted out of or lowered into the hole. He or she is also responsible for the circulating machinery and the conditioning of the drilling fluid. desander n: a centrifugal device for removing sand from drilling fluid to prevent abrasion of the pumps. It may be operated mechanically or by a fast-moving stream of fluid inside a special cone-shaped vessel, in which ease it is sometimes called a hydrocyclone. desilter n: a centrifugal device for removing very free particles, or silt, from drilling fluid to keep the amount of solids in the fluid at the lowest possible point. Usually the lower the solids content of mud, the faster is the rate of penetration. The desilter works on the same principle as a desander. development well n: 1. a well drilled in proven territory in a field to complete a pattern of production. development well n: 2. an exploitation well. deviation n: departure of the wellbore from the vertical, measured by the horizontal distance from the rotary table to the target. The amount of deviation is a function of the drift angle and hole depth. The term is sometimes used to indicate the angle from which a bit has deviated from the vertical during drilling. See deviation survey. deviation survey n: an operation made to determine the angle from which a bit has deviated from the vertical during drilling. There are two basic deviation-survey, or drift-survey, instruments; one reveals the drift angle; the other indicates both the angle and the direction of deviation. diamond bit n: a drilling bit that has a steel body surfaced with a matrix and industrial diamonds. Cutting is performed by the rotation of the very hard diamonds over the rock surface. diesel-electric power n: the power supplied to a drilling rig by diesel engines driving electric generators; used widely. diesel engine n: a high-compression, internal-combustion engine used extensively for powering drilling rigs.

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directional drilling n: intentional deviation of a wellbore from the vertical. Although wellbores are normally drilled vertically, it is sometimes necessary or advantageous to drill at an angle from the vertical. Controlled directional drilling makes it possible to reach subsurface areas laterally remote from the point where the bit enters the earth. It often involves the use of turbodrills, whipstocks or other reflecting tools. See Dyna-Drills, whipstocks. discovery well n: the first oil or gas well drilled in a new field that reveals the presence of a hydrocarbon-bearing reservoir. Subsequent wells are development wells. Compare development well. displacement fluid n: in oilwell cementing, the fluid, usually drilling mud or salt water, that is pumped into the well after the cement is pumped into it to force the cement out of the casing and into the annulus. doghouse n: 1. a small enclosure on the rig floor used as an office for the driller and as a storehouse for small objects. doghouse n:2. any small building used as an office, a change house, or a place for storage. dogleg n: a term applied to a sharp change in direction of the wellbore, usually resulting in abnormal fatigue to the drill stem and frequently resulting in key seats. dope n: A generic term applied to all types of thread lubricants. double n: a length of drill pipe, casing, or tubing consisting of two joints screwed together. Compare fourble, thribble. See joint. double board n: the name used for the working platform of the derrickman, or monkeyboard, when it is located at a height in the derrick or mast equal to two lengths of pipe joined together. Compare fourble board, thribble board. See monkeyboard. drawworks n: the hoisting mechanism on a drilling rig. It is essentially a large winch that spools off or takes in the drilling line and thus raises or lowers the drill stem and bit. drill bit n: the cutting or boring element used for drilling. See bit. drill collar n: a heavy, thick-walled tube, usually steel, used between the drill pipe and the bit in the drill stem to provide a pendulum effect to the drill stem and to provide weight on the bit. driller n: the employee directly in charge of a drilling or workover rig and crew. His or her main duty is operation of the drilling and hoisting equipment, but he or she is also responsible for downhole condition of the well, operation of downhole tools, and pipe measurements. driller's log n: a record that describes each formation encountered and lists the drilling time relative to depth, usually in 5- to 10-ft (1.5- to 3- m) intervals. drilling block n: a lease or a number of leases of adjoining tracts of land that constitute a unit of acreage sufficient to justify the expense of drilling a wildcat. drilling contractor n: an individual or group that owns a drilling rig or rigs and contracts services for drilling wells. drilling crew n: a driller, a derrickman, and two or more helpers who operate a drilling or workover rig for one tour each day. drilling fluid n: circulating fluid, one function of which is to lift cuttings out of the wellbore and to the surface. Other functions are to cool the bit and to counteract downhole formation pressure. Also called circulating fluid. See mud. drilling foreman n: the supervisor of drilling or workover operations on a rig. Also called a rig manager, rig supervisor, rig superintendent, or toolpusher. drilling line n: a wire rope used to support the drilling tools. Also called the rotary line.

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drilling rate n: the speed with which the bit drills the formation; usually called the rate of penetration. drilling rig n: see rig drill pipe n: heavily seamless tubing used to rotate the bit and circulate the drilling fluid. Joints of pipe approximately 30 feet (9 metres) long are coupled together by means of tool joints. drill ship n: a ship constructed to permit a well to be drilled from it at an offshore location. Although not as stable as other floating structures, such as semisubmersibles, drill ships, or shipshapes, are capable of drilling exploratory wells in deep, remote waters. See semisubmersible drilling rig. drill stem n: all members in the assembly used for rotary drilling from the swivel to the bit, including the kelly, drill pipe and tool joints, drill collars, stabilizers, and various specialty items. drill stem test n: a method of gathering data on the potential productivity of a formation before installing casing in a well. See formation testing. drilling in v: The process of drilling into the oil or gas reservoir. drilling out v: Refers to drilling out of the residual cement which normally remains in the lower section of casing and the wellbore after the casing has been cemented. drilling under pressure v: carrying on drilling operations while maintaining a seal at the top of the wellbore to prevent the well fluids from blowing out. drive bushing n: device used to transmit torque from the rotary table to the kelly but allow vertical movement of the kelly while drilling. It may have pins fitting into holes or may be square or octagonal to fit opening in the rotary table or busing. drill string n: the column, or string, of drill pipe with attached tool joints that transmit fluid and rotational power from the kelly to the drill collars and bit. Often, especially in the oil patch, the term is loosely applied to both drill pipe and drill collars. Compare drill stem. drum n: 1. a cylinder around which wire rope is wound in the drawworks. The drawworks drum is that part of the hoist on which the drilling line is wound. drum n: 2. a steel container of general cylindrical form. Some refined products are shipped in steel drums with capacities of about 50 to 55 U.S. gallons or about 200 litres. dry hole n: somewhat loosely used in oil work, but in general any well that does not produce oil or gas in commercial quantities. A dry hole may flow water, or gas, or may even yield some oil to the pump, but not in commercial quantities. DST abbr: drill stem test dutchman n: The portion of a stud or screw which remains in place after the head has been twisted off in an effort to remove the entire stud or screw. Also used to refer to a tool joint pin broken off in the drill-pipe of drill collar box. Dyna-Drill n: trade name for a downhole motor driven by drilling fluid that imparts rotary motion to a drilling bit connected to the tool, thus eliminating the need to turn the entire drill stem to make hole. Used in straight and directional drilling. dynamic positioning n: a method by which a floating offshore drilling rig is maintained in position over an offshore well location without the use of mooring anchors. Generally, several propulsion units, called thrusters, are located on the hulls of the structure and are actuated by a sensing system. A computer to which the system feeds signals directs the thrusters to maintain the rig on location.

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IADC Glossary - E effective permeability n: a measure of the ability of a single fluid to flow through a rock when another fluid is also present in the pore spaces. Compare absolute permeability, relative permeability. effective porosity n: the percentage of the bulk volume of a rock sample that is composed of interconnected pore spaces that allow the passage of fluid through the sample. See porosity. electric well log n: a record of certain electrical characteristics (such as resistivity and conductivity) of formations traversed by the borehole. It is made to identify the formations, determine the nature and amount of fluids they contain, and estimate their depth. Also called an electric log or electric survey. electrodynamic brake n: a device mounted on the end of the drawworks shaft of a drilling rig. The electrodynamic brake (sometimes called a magnetic brake) serves as an auxiliary to the mechanical brake when pipe is lowered into a well. The braking effect in an electrodynamic brake is achieved by means of the interaction of electric currents with magnets, with other currents, or with themselves. elevators n pl: clamps that grip a stand of casing, tubing, drill pipe, or sucker rods so that the stand can be raised from or lowered into the hole. engine horsepower n: An internal combustion engine can, temporarily, develop at any speed a maximum usable horsepower; also, can temporarily, run at much higher speeds than economically feasible with regard to dependability and repairs for industrial or drilling service. Also there are accepted procedures for measuring the horsepower or an engine that is not pulling its own water pump, fan, or take off beating. It is therefore customary for the manufacturer to specify a recommended maximum speed for a given service and a recommended conservative maximum temporary horsepower for intermittent loads, such as hoisting, and a still more conservative maximum continuous horsepower for steady loads, such as driving a pump. In most instances these properly involve also the allowance having been made for water pump, radiator fan, power take off beating, and generator. evening tour (pronounced "tower") n: the shift of duty on a drilling rig that starts in the afternoon and runs through the evening. Sometimes called afternoon tour. Compare daylight tour, graveyard tour. exploitation well n: a well drilled to permit more effective extraction of oil from a reservoir. Sometimes called a development well. exploration well n: a well drilled either in search of an as yet undiscovered pool of oil or gas (a wildcat well) or to extend greatly the limits of a known pool. It involves a relatively high degree of risk. Exploratory wells may be classified as (1) wildcat, drilled in an unproven area; (2) field extension or step-out, drilled in an unproven area to extend the proved limits of a field; or (3) deep test, drilled within a field area but to unproven deeper zones. explosive fracturing n: when explosives are used to fracture a formation. At the moment of detonation, the explosion furnishes a source of high-pressure gas to force fluid into the formation. The rubble prevents fracture healing, making the use of proppants unnecessary. Compare hydraulic fracturing.

IADC Glossary - F fastline n: the end of the drilling line that is affixed to the drum or reel of the drawworks, so called because it travels with greater velocity than any other portion of the line. Compare deadline. fault n: a break in the earth's crust along which rocks on one side have been displaced (upward, downward, or laterally), relative to those on the other side. feed-off v: the act of unwinding a cable from a drum. Also a device on a drilling rig that keeps the weight on the bit constant, and lowers the drilling line automatically. Known as the "automatic driller".

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field n: 1. a geographical area in which a number of oil or gas wells produce from a continuous reservoir. A field may refer to surface area only or to underground productive formations as well. A single field may have several separate reservoirs at varying depths. field n: 2. the magnetic field in a motor or generator, or that part of a motor or generator that produces a magnetic field; the magnetic field about any current-carrying electrical conductor. fill the hole v: to pump drilling fluid into the wellbore while the pipe is being withdrawn to ensure that the wellbore remains full of fluid even though the pipe is withdrawn. Filling the hole lessens the danger of a kick or of caving of the wall of the wellbore. filter cake n: 1. compacted solid or semisolid material remaining on a filter after pressure filtration of mud with a standard filter press. Thickness of the cake is reported in thirty-seconds of an inch or in millimetres. filter cake n: 2. the layer of concentrated solids from the drilling mud or cement slurry that forms on the walls of the borehole opposite permeable formations; also called wall cake or mud cake. fingerboard n: a rack that supports the tops of the stands of pipe being stacked in the derrick or mast. It has several steel finger-like projections that form a series of slots into which the derrickman can place a stand of drill pipe after it is pulled out of the hole and removed from the drill sting. fish n: an object that is left in the wellbore during drilling or workover operations and that must be recovered before work can proceed. It can be anything from a piece of scrap metal to a part of the drill stem. fish v: 1. to recover from a well any equipment left there during drilling operations, such as a lost bit or drill collar or part of the drill string. fish v: 2. to remove from an older well certain pieces of equipment (such as packers, liners, or screen liner) to allow reconditioning of the well. fishing n: operations on the rig for the purpose of retrieving from the wellbore sections of pipe, casing or other items which may have become stuck or inadvertently dropped in the hole. fishing tool n: a tool designed to recover equipment lost in a well. flag n: to tie a piece of cloth or other marker on a bailing or swabbing line to enable the operator to know the depth at which the swab or bailer is operating in the hole. flange up n: the act of making the final connection on the piping system. Also in oilfield slang it refers to the completion of any operation. Frequently refers to quitting a job. flare n: an open flame used to dispose of unwanted gas around a completed well. floating collar n: a special coupling device inserted one or two joints above the bottom of the casing string that contains a check valve to permit fluid to pass downward but not upward through the easing. The float collar prevents drilling mud from entering the easing while it is being lowered, allowing the casing to float during its descent and thus decreasing the load on the derrick or mast. A float collar also prevents backflow of cement during a cementing operation. floating offshore drilling rig n: a type of mobile offshore drilling unit that floats and is not in contact with the seafloor (except with anchors) when it is in the drilling mode. Floating units include barge rigs, drill ships, and semisubmersibles. See mobile offshore drilling unit. flocculation n: Abnormal thickening of drilling fluid due to chemical and physical reaction. flooding v: the process of drowning out a well with water; also the process by which oil is driven through the sand into the well by water introduced under pressure into an offset well.

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floorman n: see rotary helper. flowing well n: a well from which oil or water flows without pumping or artificial lifting. fluid n: a substance that flows and yields to any force tending to change its shape. Liquids and gases are fluids. formation n: a bed or deposit composed throughout of substantially the same kind of rock; often a lithologic unit. Each formation is given a name, frequently as a result of the study of the formation outcrop at the surface and sometimes based on fossils found in the formation. formation fracturing n: a method of stimulating production by opening new flow channels in the rock surrounding a production well. Often called a frac job. Under extremely high hydraulic pressure, a fluid (such as distillate, diesel fuel, crude oil, dilute hydrochloric acid, water, or kerosene) is pumped downward through production tubing or drill pipe and forced out below a packer or between two packers. The pressure causes cracks to open in the formation, and the fluid penetrates the formation through the cracks. Sand grains, aluminum pellets, walnut shells, or similar materials (propping agents) are carried in suspension by the fluid into the cracks. When the pressure is released at the surface, the fracturing fluid returns to the well. The cracks partially close on the pellets, leaving channels for oil to flow around them to the well. See explosive fracturing, hydraulic fracturing. formation pressure n: the force exerted by fluids in a formation, recorded in the hole at the level of the formation with the well shut in. Also called reservoir pressure or shut-in bottomhole pressure. formation testing n: the gathering of pressure data on a formation to determine its potential productivity before installing casing in a well. The conventional method is the drill stem test. Incorporated in the drill stem testing tool are a packer, valves or ports that may be opened and closed from the surface, and a pressure-recording device. The tool is lowered to bottom on a string of drill pipe and packer set, isolating the formation to be tested from the formations above and supporting the fluid column above the packer. A port on the tool is opened to allow the trapped pressure below the packer to bleed off into the drill pipe, gradually exposing the formation to atmospheric pressure and allowing the well to produce to the surface, where the well fluids may be sampled and inspected. From a record of the pressure readings, a number of facts about the formation may be inferred. fourble n: a section of drill pipe, casing, or tubing consisting of four joints screwed together. Compare double, single, thribble. See joint. fourble board n: the name used for the working platform of the derrickman, or the monkeyboard, when it is located at a height in the derrick equal to approximately four lengths of pipe joined together. Compare double board, thribble board. See monkeyboard. fracturing n: shortened form of formation fracturing. See formation fracturing.

IADC Glossary - G gas-cut mud n: a drilling mud that has entrained formation gas, giving the mud a characteristically fluffy texture. When entrained gas is not released before the fluid returns to the well, the weight or density of the fluid column is reduced. Because a large amount of gas in mud lowers its density, gas-cut mud must be treated to reduce the chance of a kick. gas sand n: a stratum of sand or porous sandstone from which natural gas is obtained. gas show n: the gas that appears in drilling fluid returns, indicating the presence of a gas zone. gas-oil ratio n: a measure of gas produced with the oil. It is expressed in cubic feet per barrel. geologist n: a scientist who gathers and interprets data pertaining to the rocks of the earth's crust. geolograph n: patented device which records the rate of penetration during drilling operations. Sometimes referred to as a "tattletale."

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geology n: the science of the physical history of the earth and its life, especially as recorded in the rocks of the crust. going in the hole v: lowering the drill stem into the wellbore. graveyard tour (pronounced "tower") n: the shift of duty on a drilling rig that starts at midnight. Sometimes called the morning tour. gravity n: 1. the attraction exerted by the earth's mass on objects at its surface. gravity n: 2. the weight of a body. See API gravity, specific gravity. guide shoe n: 1. a short, heavy, cylindrical section of steel fried with concrete and rounded at the bottom, which is place at the end of the casing string. It prevents the casing from snagging on irregularities in the borehole as it is lowered. A passage through the center of the shoe allows drilling fluid to pass up into the casing while it is being lowered and allows cement to pass out during cementing operations. Also called casing shoe. guide shoe n: 2. a device, similar to a casing shoe, placed at the end of other tubular goods. gun, perforate v: to create holes in easing and cement set through a productive formation. A common method of completing a well is to set casing through the oil-bearing formation and cement it. A perforating gun is then lowered into the hole and fired to detonate high-powered jets or shoot steel projectiles (bullets) through the casing and cement and into the pay zone. The formation fluids flow out of the reservoir through the perforations and into the wellbore. See jet-perforate, perforating gun. gusher n: an oilwell that has come in with such great pressure that the oil jets out of the well like a geyser. In reality, a gusher is a blowout and is extremely wasteful of reservoir fluids and drive energy. In the early days of the oil industry, gushers were common and many times were the only indication that a large reservoir of oil and gas had been struck. See blowout. IADC Glossary - G gas-cut mud n: a drilling mud that has entrained formation gas, giving the mud a characteristically fluffy texture. When entrained gas is not released before the fluid returns to the well, the weight or density of the fluid column is reduced. Because a large amount of gas in mud lowers its density, gas-cut mud must be treated to reduce the chance of a kick. gas sand n: a stratum of sand or porous sandstone from which natural gas is obtained. gas show n: the gas that appears in drilling fluid returns, indicating the presence of a gas zone. gas-oil ratio n: a measure of gas produced with the oil. It is expressed in cubic feet per barrel. geologist n: a scientist who gathers and interprets data pertaining to the rocks of the earth's crust. geolograph n: patented device which records the rate of penetration during drilling operations. Sometimes referred to as a "tattletale." geology n: the science of the physical history of the earth and its life, especially as recorded in the rocks of the crust. going in the hole v: lowering the drill stem into the wellbore. graveyard tour (pronounced "tower") n: the shift of duty on a drilling rig that starts at midnight. Sometimes called the morning tour. gravity n: 1. the attraction exerted by the earth's mass on objects at its surface. gravity n: 2. the weight of a body. See API gravity, specific gravity.

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guide shoe n: 1. a short, heavy, cylindrical section of steel fried with concrete and rounded at the bottom, which is place at the end of the casing string. It prevents the casing from snagging on irregularities in the borehole as it is lowered. A passage through the center of the shoe allows drilling fluid to pass up into the casing while it is being lowered and allows cement to pass out during cementing operations. Also called casing shoe. guide shoe n: 2. a device, similar to a casing shoe, placed at the end of other tubular goods. gun, perforate v: to create holes in easing and cement set through a productive formation. A common method of completing a well is to set casing through the oil-bearing formation and cement it. A perforating gun is then lowered into the hole and fired to detonate high-powered jets or shoot steel projectiles (bullets) through the casing and cement and into the pay zone. The formation fluids flow out of the reservoir through the perforations and into the wellbore. See jet-perforate, perforating gun. gusher n: an oilwell that has come in with such great pressure that the oil jets out of the well like a geyser. In reality, a gusher is a blowout and is extremely wasteful of reservoir fluids and drive energy. In the early days of the oil industry, gushers were common and many times were the only indication that a large reservoir of oil and gas had been struck. See blowout.

IADC Glossary - H heads, flowing by v: when a well flows intermittently rather than continuously, it is said to be flowing by heads. hoist n: 1. an arrangement of pulleys and wire rope or chain used for lifting heavy objects; a winch or similar device. hoist n: 2. the drawworks. hoist v:. to raise or lift. hoisting drum n: the large flanged spool in the drawworks on which the hoisting cable is wound. See drawworks. hole n: usually refers to the wellbore. hook n: a large, hook-shaped device from which the swivel is suspended. It is designed to carry maximum loads ranging from 100 to 650 tons (90 to 590 tons) and turns on bearings in its supporting housing. A strong spring within the assembly cushions the weight of a stand (90 feet, about 27 metres) of drill pipe, thus permitting the pipe to be made up and broken out with less damage to the tool joint threads. Smaller hooks without the spring are used for handling tubing and sucker rods. See stand, swivel. hook load n: the weight on the hook of the drill stem and/or casing expressed in pounds. hook horsepower n: the horsepower equivalent for any given hook load and hoisting speed. hopper n: a large funnel- or cone-shaped device into which dry components (such as powered clay or cement) can be poured to mix uniformly with water or other liquids. The liquid is injected through a nozzle at the bottom of the hopper. The resulting mixture may be drilling mud to be used as the circulating fluid in a rotary drilling operation, or it may be cement slurry to be used in bonding casing to the borehole. horsepower (hp) n: is a rate of doing work (transferring energy) equivalent to lifting 33,000 pounds 1 foot per minute (33,000 ft. lb./min.). This is a course also 550 ft lb./sec. horsepower, bit (mech) hydraulic HP bit n: can mean either the horsepower required to rotate the bit (which for many conditions is virtually negligible as the power required to rotate the drill pipe overshadows it) or the hydraulic horsepower at the bit is the simple calculation of gpm and psi (pressure drop across the nozzles) divided by 1715.

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horsepower, brake (bhp) n: is the horsepower output of an engine or motor actually measurable by various means, most simply a special type of brake having an arm counterbalanced by a known weight applied at a known distance from the center of rotation. Input horsepower may be said to be the brake horsepower supplied by the driver. horsepower, rotary and torque n: torque may be expressed as tangential force (pounds) and lever arm (feet) or lbft. (It may also be expressed as pound inches). For any one revolution the torque-tangential force travels the circumference of a circle (whose radius is the torque arm) or 2 feet. Thus Torque (Ib-ft) x 2 x rpm = Horsepower (totaling) 33,000. The upper limit of torque or rotating hp or "horsepower per rpm" is related to the torque capacity of the pipe or tool joints, especially with regard to breaking out tool joints after inevitable shock loads have been superimposed on the average operating torque involved. hydraulics n: that branch of engineering which treats of liquids in motion, or its action. It is the know-how about the effects of fluid velocities and pressures and the power involved. hydrocarbons n pl: organic compounds of hydrogen and carbon whose densities, boiling points, and freezing points increase as their molecular weights increase. Although composed of only two elements, hydrocarbons exist in a variety of compounds, because of the strong affinity of the carbon atom for other atoms and for itself. The smallest molecules of hydrocarbons are gaseous; the largest are solids. Petroleum is a mixture of many different hydrocarbons. hydromatic brake n: a device mounted on the end of the drawworks shaft of a drilling rig. The hydromatic brake (often simply called the hydromatic) serves as an auxiliary to the mechanical brake when pipe is lowered into the well. The braking effect in a hydromatic brake is achieved by means of a runner or impeller turning in a housing filled with water. hydraulic fracturing n: an operation in which a specially blended liquid is pumped down a well and into a formation under pressure high enough to cause the formation to crack open, forming passages through which oil can flow into the wellbore. Sand grains, aluminum pellets, glass beads, or similar materials are carried in suspension into the fractures. When the pressure is released at the surface, the fractures partially close on the proppants, leaving channels for oil to flow through to the well. Compare explosive fracturing. hydraulic horsepower (hhp) n: gpm x psi = horsepower (hydraulic) 1715 is the horsepower equivalent of "lifting" a continuous volume rate of fluid to the height in feet represented by the pressure involved (as if a tall open overflowing stand-pipe were connected to measure the pressure. The weight of fluid directly controls the pressure in a stand-pipe, 520 pounds per square inch (psi) is the bottom pressure of a 1000' column of 10 pounds per gallon (ppg) fluid. To pump in a gallon at the bottom and move a gallon out the top is the same as lifting 10 pounds through 1000', or 10,000 ft-lb. A volume of 3.3 gallons per minute (gpm) at these conditions is 33,000 ft-lb per minute or one horsepower. Because it is the calculation of fluid relations, it is referred to as hydraulic horsepower. It can be calculated for any part of the system according to the pressure relations for that part of the system. Thus, 3.3 gpm and 520 psi, or 1715 gpm and one psi means one horsepower. For any other properties of fluid pumped, 520 psi represents a different height but always the same ft-lb per gallon pumped.

IADC Glossary - I IADC n: International Association of Drilling Contractors. The successor to A.A.O.D.C. as of November 24, 1971. The organization concerns itself with any items of general interest, internationally, to its contractor and/or operator and associate members. It also publishes the Drilling Contractor magazine, the Drilling Manual, training and safety materials, and many forms in general use by the drilling industry.

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inclinometer n: the trade name of an instrument used to determine whether or not the well bore is proceeding in a vertical orientation at any point. In most drilling operations either regulations of government bodies or contract stipulations, or both, provide a maximum deviation of the wellbore from the vertical; commonly this maximum is three degrees. When deviation is in excess of the allowable, it is necessary to modify drilling procedure to bring it back in line. idler n: in machinery and idler pulley or sprocket is used in connection with belt drive and chain drive respectively to maintain desired tension on the belt or chain. Such a pulley or sprocket has no other purpose. impermeable adj: preventing the passage of fluid. A formation may be porous yet impermeable if there is an absence of connecting passages between the voids within it. See permeability. inhibitor n: according to Webster, any agent which inhibits or prevents. In drilling and producing operations, it usually refers to corrosion inhibitor. Corrosion inhibitors are used widely in drilling and producing operations to prevent corrosion of metal equipment exposed to hydrogen sulphide gas and salt water. In some drilling operations corrosion inhibitor is added to the drilling fluid to protect drill pipe. inland barge rig n: a floating offshore drilling structure consisting of a barge on which the drilling equipment is constructed. When moved from one location to another, the barge floats. When stationed on the drill site, the barge can be anchored in the floating mode or submerged to rest on the bottom. Typically, inland barge rigs are used to drill wells in marshes, shallow inland bays, and areas where the water is not too deep. Also called swamp barge. See floating offshore drilling rig. input horsepower n: the power that is put into a usable unit, operating system, or piece of equipment. inside blowout preventer n: any one of several types of valve installed in the drill stem to prevent a blowout through the stem. Flow is possible only downward, allowing mud to be pumped in but preventing any flow back up the stem. Also called an internal blowout preventer. instrumentation n: a device or assembly of devices designed for one or more of the following functions; to measure operating variables (such as pressure, temperature, rate of flow, and speed of rotation): to indicate these phenomena with visible or audible signals; to record them; to control them within a predetermined range; and to stop operations if the control fails. Simple instrumentation might consist of an indicating pressure gauge only. In a completely automatic system, desired ranges of pressure, temperature, and so on are predetermined and preset. intermediate casing string n: the string of casing set in a well after the surface easing but before production easing is set to keep the hole from caving and to seal off troublesome formations. Sometimes called protection casing.

IADC Glossary - J jackup drilling rig n: a mobile bottom-supported offshore drilling structure with columnar or open-truss legs that support the deck and hull. When positioned over the drilling site, the bottoms of the legs rest on the seafloor. A jackup rig is towed or propelled to a location with its legs up. Once the legs are firmly positioned on the bottom, the deck and hull height are adjusted and leveled. Also called self-elevating drilling unit. jet n: the directed, rapid flow of fluid from a nozzle. Besides jets from bit nozzles, jets are also involved in pumps for removing fluid and trash from pits and in mixing mud and cement. jet bit n: a drilling bit having replaceable nozzles through which the drilling fluid is directed in a high-velocity stream to the bottom of the hole to improve the efficiency of the bit. See bit. jetting out n: operation using the jet to clean out the cellar, slush pit, etc. jet gun n: an assembly, including a carrier and shaped charges, that is used in jet perforating.

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jet-perforate v: to create a hole through the casing with a shaped charge of high explosives instead of a gun that fires projectiles. The loaded charges are lowered into the hole to the desired depth. Once detonated, the charges emit short, penetrating jets of high-velocity gases that cut holes in the casing and cement and some distance into the formation. Formation fluids then flow into the wellbore through these perforations. See bullet perforator, gun perforator. joint n: in drilling, a single length (from 16 feet to 45 feet, or 5 metres to 14.5 metres, depending on its range length) of drill pipe, drill collar, easing, or tubing that has threaded connections at both ends. Several joints screwed together constitute a stand of pipe. junk n: metal debris lost in a hole. Junk may be a lost bit, pieces of a bit, milled pieces of pipe, wrenches, or any relatively small object that impedes drilling or completion and must be fished out of the hole. junk v: to abandon (as a nonproductive well).

IADC Glossary - K kelly n: the heavy steel member, three-, four-, six-, or eight-sided, suspended from the swivel through the rotary table and connected to the topmost joint o f drill pipe to turn the drill stem as the rotary table turns. It has a bored passageway that permits fluid to be circulated into the drill stem and up the annulus, or vice versa. See drill stem, rotary table, and swivel. kelly bushing (KB) n: special device that, when fitted into the master bushing, transmits torque to the kelly and simultaneously permits vertical movement of the kelly to make hole. It may be shaped to fit the rotary opening or have pins for transmitting torque. Also called the drive bushing. See kelly and master bushing. kelly spinner n: a pneumatically operated device mounted on top of the kelly that, when actuated, causes the kelly to turn or spin. It is useful when the kelly or a joint of pipe attached to it must be spun up, that is, rotated rapidly for being made up. key seat n: in drilling a well, a channel or groove cut in the side of the hole, parallel to the axis of the hole. Key seating takes place as a result of dragging action of pipe on a dog-leg. In machine work, a groove cut in a shaft of pulley bore parallel with the axis. key seat wiper n: a short joint on which are fixed either spiral or straight blades that are approximately 1/2 inch larger in diameter than the largest drill collar in the string and is attached to the top drill collar. The wiper can be rotated or jarred through a key seat, enlarging it sufficiently to allow the passage of the drill collars. kick n: an entry of water, gas, oil, or other formation fluid into the wellbore during drilling. It occurs because the pressure exerted by the column of drilling fluid is not great enough to overcome the pressure exerted by the fluids in the formation drilled. If prompt action is not taken to control the kick or kill the well, a blowout may occur. See blowout. kill line n: a high pressure line, connecting the mud pump and the well, through which drilling fluid can be pumped into the well to control a threatened blowout. killing a well v: the act of bringing under control a well which is blowing out; also applied to the procedure of circulating water and mud into a completed well before starting well operations. knowledge box n: a cupboard or desk in which the driller keeps the

IADC Glossary - L LACT unit n: an automated system for measuring, sampling, and transferring oil from a lease gathering system into a pipeline. See lease automatic custody transfer.

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latch on v: to attach elevators to a section of pipe to pull it out of or run it into the hole. lead tongs n pl: the pipe tongs suspended in the derrick or mast and operated by a wireline connected to the breakout cathead. In coming out of the hole, they are used on the pin end of the joint for breaking out. In going into the hole, they are used on the box end as backup to the makeup tongs. Also called breakout tongs. lease n: 1. a legal document executed between a landowner, as lessor, and a company or individual, as lessee, that grants the right to exploit the premises for minerals or other products; the instrument that creates a leasehold or working interest in minerals. lease n: 2. the area where production wells, stock tanks, separators, LACT units, and other production equipment are located. lease automatic custody transfer (LACT) n: the measurement, sampling, and transfer of oil from the producer's tanks to the connected pipeline on an automatic basis without a representative of either the producer or the gathering company having to be present. See LACT unit. liner n: any string of casing whose top is situated at any point below the surface. location n: the place where a well is drilled. log n: a systematic recording of data, such as a driller's log, mud log, electrical well log, or radioactivity log. Many different logs are run in wells to discern various characteristics of downhole formation. v: to record data. lose returns or lost circulation v: to encounter an interruption in the circulation of drilling fluid due to the fact that the fluid is entering into a porous or fractured formation underground rather than returning to the surface.

IADC Glossary - M magnetic brake n: see electrodynamic brake. make a connection v: to attach a joint of drill pipe onto the drill stem suspended in the wellbore to permit deepening the wellbore by the length of the joint added (about 30 feet or 9 metres). make a trip v: to hoist the drill stem out of the wellbore to perform one of a number of operations such as changing bits or taking a core and then to return the drill stem to the wellbore. make hole v: to deepen the hole made by the bit, i.e., to drill ahead. make up v: 1. to assemble and join pans to form a complete unit (e.g., to make up a string of casing). make up v: 2. to screw together two threaded pieces. make up v: 3. to mix or prepare (e.g., to make up a tank of mud). make up v: 4. to compensate for (e.g., to make up for lost time) make up a joint v: to screw a length of pipe into another length of pipe. makeup cathead n: a device that is attached to the shall of the drawworks and used as a power source for screwing together joints of pipe. It is usually located on the driller's side of the drawworks. Also called spinning cathead. See cathead. marsh funnel n: a calibrated funnel commonly used in field tests to determine the viscosity of drilling mud. mast n: a portable derrick that is capable of being raised as a unit, as distinguished from a standard derrick, which cannot be raised to a working position as a unit. For transporting by land, the mast can be divided into two or more sections to avoid excessive length extending from truck beds on the highway. Compare derrick.

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master bushing n: a device that fits into the rotary table to accommodate the slips and drive the kelly bushing so that the rotating motion of the rotary table can be transmitted to the kelly. Also called rotary bushing. mechanical rig n: a drilling rig in which the source of power is one or more internal-combustion engines and in which the power is distributed to rig components through mechanical devices (such as chains, sprockets, clutches, and shafts). Also called a power rig. mill n: a downhole tool with rough, sharp, extremely hard cutting surfaces for removing metal by grinding or cutting. Mills are run on drill pipe or tubing to grind up debris in the hole, remove stuck portions of drill stem or sections of casing for sidetracking, and ream out tight spots in the casing. They are also called junk mills, reaming mills and so forth, depending on what use they have. v: to use a mill to cut or grind metal objects that must be removed from a well. mix mud v: to prepare drilling fluids from a mixture of water or other liquids and any one or more of the various dry mud making materials (such as clay, weighting materials, and chemicals). monkeyboard n: the derrickman's working platform. As pipe or tubing is run into or out of the hole, the derrickman must handle the top end of the pipe, which may be as high as 90 feet (27 metres) in the derrick or mast. The monkeyboard provides a small platform to raise him or her to the proper height for handling the top of the pipe. See double board, fourble board, and thribble board. morning tour (pronounced "tower") n: see graveyard tour. motorman n: the crew member on a rotary drilling rig, usually the most experienced rotary helper, who is responsible for the care and operation of drilling engines. Compare fireman. mouse hole n: a shallow cased hole close to the rotary table through the derrick floor in which a joint of drill string can be suspended to facilitate connecting the joint to the kelly. mousehole connection n: the procedure of adding a length of drill pipe or tubing to the active string. The length to be added is placed in the mousehole, made up to the kelly, then pulled out of the mousehole, and subsequently made up into the string. mud n: the liquid circulated through the wellbore during rotary drilling and workover operations. In addition to its function of bringing cuttings to the surface, drilling mud cools and lubricates the bit and drill stem, protects against blowouts by holding back subsurface pressures, and deposits a mud cake on the wall of the borehole to prevent loss of fluids to the formation. mud analysis n: examination and testing of drilling mud to determine its physical and chemical properties. mud balance n: an instrument consisting of a cup and a graduated arm with a sliding weight and resting on a fulcrum, used to measure weight of the mud. mud cake n: the sheath of mud solids that forms on the wall of the hole when liquid from mud filters into the formation. Also called filter cake or wall cake. mud circulation n: the process of pumping mud downward to the bit and back up to the surface in a drilling or workover operation. See normal circulation, reverse circulation. mud conditioning n: the treatment and control of drilling mud to ensure that it has the correct properties. Conditioning may include the use of additives, the removal of sand or other solids, the removal of gas, the addition of water, and other measures to prepare the mud for conditions encountered in a specific well. mud engineer n: an employee of a drilling fluid supply company whose duty it is to test and maintain the drilling mud properties that are specified by the operator. mud gun n: a device that shoots a jet of drilling mud under high pressure into the mud pit to mix additives with the mud or to agitate the mud.

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mud logging n: the recording of information derived from examination and analysis of formation cuttings made by the bit and of mud circulated out of the hole. A portion of the mud is diverted through a gas-detecting device. Cuttings brought up by the mud are examined under ultraviolet light to detect the presence of oil or gas. Mud logging is often carried out in a portable laboratory set up at the well. mud man n: see mud engineer. mud-off v: in drilling, to seal the hole off from the formation water or oil by using mud. Applies especially to the undesirable blocking off of the flow of oil from the formation into the wellbore. Special care is given to the treatment of drilling fluid to avoid this. mud pit n: originally, an open pit dug in the ground to hold drilling fluid or waste materials discarded after the treatment of drilling mud. For some drilling operations, mud pits are used for suction to the mud pumps, settling of mud sediments, and storage of reserve mud. Steel tanks are much more commonly used for these purposes now, but they are still usually referred to as pits, except offshore, where "mud tanks" is preferred. mud pump n: a large, high-pressure reciprocating pump used to circulate the mud on a drilling rig. A typical mud pump is a two-cylinder, double-acting or a three-cylinder, single-acting piston pump whose pistons travel in replaceable liners and are driven by a crankshaft actuated by an engine or a motor. Also called a slush pump. mud return line n: a trough or pipe that is placed between the surface connections at the wellbore and the shale shaker and through which drilling mud flows on its return to the surface from the hole. Also called flow line. mud screen n: see shale shaker.

IADC Glossary - N natural gas n: highly compressible, highly expansible mixture of hydrocarbons with low specific gravity and occurring naturally in gaseous form. Besides hydrocarbon gases, natural gas may contain appreciable quantities of nitrogen, helium, carbon dioxide, hydrogen sulfide, and water vapor. Although gaseous at normal temperatures and pressures, gases making up the mixture that is natural gas vary in form and may be found either as gases or as liquids under suitable conditions of temperature and pressure. needle valve n: a globe valve that incorporates a needlepoint disk to produce extremely fine regulation of flow. nipple n: a tubular pipe fitting threaded on both ends and less than 12 inches long. nipple chaser n: a material-man whose duty it is to procure and deliver to the drilling rig the necessary tools and equipment to carry on the work. nipple up v: in drilling, to assemble the blowout preventer stack on the wellhead at the surface. normal circulation n: the smooth, uninterrupted circulation of drilling fluid down the drill stem, out the bit, up the annular space between the pipe and the hole, and back to the surface. nozzle n: a small spout to direct the flow of fluid efficiently.

IADC Glossary - O offshore drilling n: drilling for oil in an ocean, gulf, or sea, usually. on the Outer continental Shelf. A drilling unit for offshore operations may be a mobile floating vessel with a ship or barge hull, a semisubmersible or submersible base, a self-propelled or towed structure with jacking legs (jackup drilling rig), or a permanent structure used as a production platform when drilling is completed. In general, wildcat wells are drilled from mobile floating vessels or from jackups, while development wells are drilled from platforms or jackups. oilfield n: the surface area overlying an oil reservoir or reservoirs. The term usually includes not only the surface area, but also the reservoir, the wells, and the production equipment.

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oil sand n: 1. a sandstone that yields oil. oil sand n: 2. (by extension) any reservoir that yields oil, whether or not it is sandstone. oil string n: the final string of casing set and cemented in the hole to prevent caving of the hole, the flow of fluid into the hole from other formations and serves as the pipe through which oil and gas is produced. Also called long or production casing. oil zone n: a formation or horizon of a well from which oil may be produced. The oil zone is usually immediately under the gas zone and on top of the water zone if all three fluids are present and segregated. open adj: 1. of a wellbore, having no casing. open adj: 2. of a hole, having no drill pipe or tubing suspended in it. open hole n: 1. any wellbore in which casing has not been set. open hole n: 2. open or cased hole in which no drill pipe or tubing is suspended. open hole n: 3. the portion of the wellbore that has no casing. operator n: the person or company, either proprietor or lessee, actually operating an oilwell or lease, generally the oil company by which the drilling contractor is engaged. Compare unit operator. orifice n: an opening of a measured diameter that is used for measuring the flow of fluid through a pipe or for delivering a given amount of fluid through a fuel nozzle. In measuring the flow of fluid through a pipe, the orifice must be of smaller diameter than the pipe diameter. It is drilled into an orifice plate held by an orifice fitting. output horsepower n: the power that is put out by a unit, operating system, or piece of equipment. overshot n: a fishing tool that is attached to tubing or drill pipe and lowered over the outside wall of pipe or sucker rods lost or stuck in the wellbore. A friction device in the overshot, usually either a basket or a spiral grapple, firmly grips the pipe, allowing the fish to be pulled from the hole.

IADC Glossary - P P&A abbr: plug and abandon. pay sand n: the producing formation, often one that is not even sandstone. It is also called pay, pay zone, and producing zone. penetration, rate of adj: the rate at which the drill proceeds in the deepening of the wellbore. It is usually expressed in terms of feet per hour. perforate v: to pierce the casing wall and cement of a wellbore to provide holes through which formation fluids may enter or to provide holes in the casing so that materials may be introduced into the annulus between the casing and the wall of the borehole. Perforating is accomplished by lowering into the well a perforating gun, or perforator, which fires electrically detonated bullets or shaped charges. See perforating gun. perforating gun n: a device fitted with shaped charges or bullets that is lowered to the desired depth in a well and fired to create penetrating holes in casing, cement and formation. permeability n: 1. a measure of the ease with which a fluid flows through the connecting pore spaces of rock or cement. The unit of measurement is the millidarcy. permeability n: 2. fluid conductivity of a porous medium. permeability n: 3. ability of a fluid to flow within the interconnected pore network of a porous medium. See absolute permeability, effective permeability, relative permeability.

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petroleum n: oil or gas obtained from the rocks of the earth. See hydrocarbons. pin n: the male section of a tool joint. See tool joint. pipe ram n: a sealing component for a blowout preventer that closes the annular space between the pipe and the blowout preventer or wellhead. See annular space and blowout preventer. platform n: an immobile, offshore structure constructed on pilings from which wells are drilled, produced, or both. plug and abandon (P&A) v: to place cement plugs into a dry hole and abandon it. plug back v: to seal off the bottom section of a wellbore to prevent the inflow of fluid from that portion of the hole. pore n: an opening or space within a rock or mass of rocks, usually small and often filled with some fluid (water, oil, gas, or all three). Compare vug. porosity n: 1. the condition of being porous (such as a rock formation).. porosity n: 2. the ratio of the volume of empty space to the volume of solid rock in a formation, indicating how much fluid a rock can hold. See absolute porosity, effective porosity, pore. positive choke n: a choke in which the orifice size must be changed to change the rate of flow through the choke. See choke and orifice. pressure n: the force that a fluid (liquid or gas) exerts uniformly in all directions within a vessel, pipe, hole in the ground, and so forth, such as that exerted against the inner wall of a tank or that exerted on the bottom of the wellbore by a fluid. Pressure is expressed in terms of force exerted per unit of area, as pounds per square inch, or in kilopascals. pressure gauge n: an instrument that measures fluid pressure and usually registers the difference between atmospheric pressure and the pressure of the fluid by indicating the effect of such pressures on a measuring element (e.g., a column of liquid, pressure in a Bourdon tube, a weighted piston or a diaphragm). pressure gradient n: a scale of pressure differences in which there is a uniform variation of pressure from point to point. For example, the pressure gradient of a column of water is about 0.433 pounds per square inch per foot (9.794 kilopascals per metre) of vertical elevation. The normal pressure gradient in a formation is equivalent to the pressure exerted at any given depth by a column of 10 percent salt water extending from that depth to the surface 0.465 pounds per square inch per foot or 10.518 kilopascals per metre). pressure relief valve n: a valve that opens at a preset pressure to relieve excessive pressures within a vessel or line. Also called a pop valve, relief valve, safety valve, or safety relief valve. preventer n: shortened form of blowout preventer. See blowout preventer. primary cementing n: the cementing operation that takes place immediately after the casing has been run into the hole. It provides a protective sheath around the casing, segregates the producing formation, and prevents the undesirable migration of fluids. See secondary cementing and squeeze cementing. prime mover n: an internal-combustion engine or a turbine that is the source of power for driving a machine or machines. production n: 1. the phase of the petroleum industry that deals with bringing the well fluids to the surface and separating them and with storing, gauging, and otherwise preparing the product for the pipeline. production n: 2. the amount of oil or gas produced in a given period. proppant n: see propping agent.

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propping agent n: a granular substance (sand grains, aluminum pellets, or other material) that is carded in suspension by the fracturing fluid and that serves to keep the cracks open when fracturing fluid is withdrawn after a fracture treatment. protection casing n: a string of casing set to protect a section of the hole and to permit drilling to continue to a greater depth. Sometimes called "protection string" and "intermediate string." psi abbr: pounds per square inch. pump n: a device that increases the pressure on a fluid or raises it to a higher level. Various types of pumps include the bottomhole pump, centrifugal pump, hydraulic pump, jet pump, mud pump, reciprocating pump, rotary pump, sucker rod pump, and submersible pump.

IADC Glossary - Q quebracho n: a South American tree whose name in Spanish means "axe breaker." Crystalline extract from the fiber of the quebracho tree is extensively used as a thinning agent for drilling mud. quicklime n: calcium oxide, CaO, used in certain oil-base muds to neutralize the organic acid. quiescence n: the state of being quiet or at rest (being still). Static.

IADC Glossary - R racking pipe n: the act of placing stands of pipe in orderly arrangement in the derrick after hoisting pipe from the wellbore. radioactivity log n: a record of the natural or induced radioactive characteristics of subsurface formations. See radioactivity well logging. radioactivity well logging n: the recording of the natural or induced radioactive characteristics of subsurface formations. A radioactivity log, also known as a radiation log, normally consists of two recorded curves: a gamma ray curve and a neutron curve. Both help to determine the types of rocks in the formation and the types of fluids contained in the rocks. The two logs may be run simultaneously in conjunction with a collar locator in a cased or uncased hole. ram n: the closing and sealing component on a blowout preventer. One of three types - blind, pipe, or shear - may be installed in several preventers mounted in a stack on top of the wellbore. Blind rams, when closed, form a seal on a hole that has no drill pipe in it; pipe rams, when closed, seal around the pipe; shear rams cut through drill pipe and then form a seal. ram blowout preventer n: a blowout preventer that uses rams to seal off pressure on a hole that is with or without pipe. Also called a ram preventer. rathole n: 1. a hole in the rig floor, 30 to 35 feet (9 to 11 metres) deep, which is lined with casing that projects above the floor and into which the kelly and swivel are placed when hoisting operations are in progress. rathole n: 2. a hole of a diameter smaller than the main hole and drilled in the bottom of the main hole. rathole v: to reduce the size of the wellbore and drill ahead. reaming v: the operations of smoothing the wellbore, enlarging the hole to the desired size, straightening dog legs and assist in directional drilling. reeve v: to pass (as a rope) through a hole or opening in a block or similar device.

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relative permeability n: the ratio of effective permeability to absolute permeability. The relative permeability of rock to a single fluid is 1.0 when only that fluid is present, and 0.0 when the presence of another fluid prevents all flow of the given fluid. Compare absolute permeability, effective permeability. reserve pit n: 1 (obsolete) a mud pit in which a supply of drilling fluid is stored. reserve pit n: 2. a waste pit, usually an excavated earthen-walled pit. It may be lined with plastic or other material to prevent soil contamination. reservoir n: a subsurface, porous, permeable rock body in which oil and/or gas has accumulated. Most reservoir rocks are limestones, dolomites, sandstones, or a combination. The three basic types of hydrocarbon reservoirs are oil, gas, and condensate. An oil reservoir generally contains three fluids - gas, oil, and water - with oil the dominant product. In the typical oil reservoir, these fluids become vertically segregated because of their different densities. Gas, the lightest, occupies the upper part of the reservoir rocks; water, the lower part; and oil, the intermediate section. In addition to its occurrence as a cap or in solution, gas may accumulate independently of the oil; if so, the reservoir is called a gas reservoir. Associated with the gas, in most instances, are salt water and some oil. In a condensate reservoir, the hydrocarbons may exist as a gas, but, when brought to the surface, some of the heavier ones condense to a liquid. reservoir pressure n: the average pressure within the reservoir at any given time. Determination of this value is best made by bottomhole pressure measurements with adequate shut-in time. If a shut-in period long enough for the reservoir pressure to stabilize is impractical, then various techniques of analysis by pressure buildup or drawdown tests are available to determine static reservoir pressure. reverse circulation n: the course of drilling fluid downward through the annulus and upward through the drill stem, in contrast to normal circulation in which the course is downward through the drill stem and upward through the annulus. Seldom used in open hole, but frequently used in workover operations. Also referred to as "circulating the short way," since returns from bottom can be obtained more quickly than in normal circulation. rig n: the derrick or mast, drawworks, and attendant surface equipment of a drilling or workover unit. rig breaking capacity (performance) n: the capacity to hold the hook-load and retard the continuous movement of the hook load within reasonable specified limits compatible with specific requirements. rig, jackknife or folding mast n: the type mast that can be folded for moving as contrasted with the standard derrick, which has to be completely dismantled and re-erected. rig up v: to prepare the drilling rig for making hole, that is, to install tools and machinery before drilling is started. rock pressure adj: a term used for the initial pressure of gas in a well. roller cone bit n: a drilling bit made of two, three, or four cones, or cutters, that are mounted on extremely rugged bearings. The surface of each cone is made of rows of steel teeth or rows of tungsten carbide inserts. Also called rock bits. rotary bushing n: see master bushing. rotary drilling n: a drilling method in which a hole is drilled by a rotating bit to which a downward force is applied. The bit is fastened to and rotated by the drill stem, which also provides a passageway through which the drilling fluid is circulated. Additional joints of drill pipe are added as drilling progresses. rotary drilling rig n: basically hoisting equipment, prime movers and auxiliary equipment necessary to well drilling. Includes: Rotary table, draw-works, kelly, swivel, hook, blocks, line, engines, mud pumps and piping. (steel mud pits, if used) utilities unit, dog house, tool house, mud house, etc., and electric generators, motors, and wiring if used.

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rotary helper n: a worker on a drilling or workover rig. subordinate to the driller, whose primary work station is on the rig floor. On rotary drilling rigs, there are at least two and usually three or more rotary helpers on each crew. Sometimes called floorhand, floorman, rig crewman, or roughneck. rotary hose n: a reinforced flexible tube on a rotary drilling rig that conducts the drilling fluid from the standpipe to the swivel and kelly. Also called the mud hose or the kelly hose. rotary table n: the principal component of a rotary, or rotary machine, used to turn the drill stem and support the drilling assembly. It has a beveled gear arrangement to create the rotational motion and opening into which bushings are fitted to drive and support the drilling assembly. roughneck n: see rotary helper. round trip n: see making a trip. roustabout n: 1. a worker on an offshore rig who handles the equipment and supplies that are sent to the rig from the shore base. The head roustabout is very often the crane operator. roustabout n: 2. a worker who assists the foreman in the general work around a producing oilwell, usually on the property of the oil company. roustabout n: 3. a helper on a well servicing unit. run in v: to go into the hole with tubing, drill pipe, and so forth. IADC Glossary - R racking pipe n: the act of placing stands of pipe in orderly arrangement in the derrick after hoisting pipe from the wellbore. radioactivity log n: a record of the natural or induced radioactive characteristics of subsurface formations. See radioactivity well logging. radioactivity well logging n: the recording of the natural or induced radioactive characteristics of subsurface formations. A radioactivity log, also known as a radiation log, normally consists of two recorded curves: a gamma ray curve and a neutron curve. Both help to determine the types of rocks in the formation and the types of fluids contained in the rocks. The two logs may be run simultaneously in conjunction with a collar locator in a cased or uncased hole. ram n: the closing and sealing component on a blowout preventer. One of three types - blind, pipe, or shear - may be installed in several preventers mounted in a stack on top of the wellbore. Blind rams, when closed, form a seal on a hole that has no drill pipe in it; pipe rams, when closed, seal around the pipe; shear rams cut through drill pipe and then form a seal. ram blowout preventer n: a blowout preventer that uses rams to seal off pressure on a hole that is with or without pipe. Also called a ram preventer. rathole n: 1. a hole in the rig floor, 30 to 35 feet (9 to 11 metres) deep, which is lined with casing that projects above the floor and into which the kelly and swivel are placed when hoisting operations are in progress. rathole n: 2. a hole of a diameter smaller than the main hole and drilled in the bottom of the main hole. rathole v: to reduce the size of the wellbore and drill ahead. reaming v: the operations of smoothing the wellbore, enlarging the hole to the desired size, straightening dog legs and assist in directional drilling. reeve v: to pass (as a rope) through a hole or opening in a block or similar device.

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relative permeability n: the ratio of effective permeability to absolute permeability. The relative permeability of rock to a single fluid is 1.0 when only that fluid is present, and 0.0 when the presence of another fluid prevents all flow of the given fluid. Compare absolute permeability, effective permeability. reserve pit n: 1 (obsolete) a mud pit in which a supply of drilling fluid is stored. reserve pit n: 2. a waste pit, usually an excavated earthen-walled pit. It may be lined with plastic or other material to prevent soil contamination. reservoir n: a subsurface, porous, permeable rock body in which oil and/or gas has accumulated. Most reservoir rocks are limestones, dolomites, sandstones, or a combination. The three basic types of hydrocarbon reservoirs are oil, gas, and condensate. An oil reservoir generally contains three fluids - gas, oil, and water - with oil the dominant product. In the typical oil reservoir, these fluids become vertically segregated because of their different densities. Gas, the lightest, occupies the upper part of the reservoir rocks; water, the lower part; and oil, the intermediate section. In addition to its occurrence as a cap or in solution, gas may accumulate independently of the oil; if so, the reservoir is called a gas reservoir. Associated with the gas, in most instances, are salt water and some oil. In a condensate reservoir, the hydrocarbons may exist as a gas, but, when brought to the surface, some of the heavier ones condense to a liquid. reservoir pressure n: the average pressure within the reservoir at any given time. Determination of this value is best made by bottomhole pressure measurements with adequate shut-in time. If a shut-in period long enough for the reservoir pressure to stabilize is impractical, then various techniques of analysis by pressure buildup or drawdown tests are available to determine static reservoir pressure. reverse circulation n: the course of drilling fluid downward through the annulus and upward through the drill stem, in contrast to normal circulation in which the course is downward through the drill stem and upward through the annulus. Seldom used in open hole, but frequently used in workover operations. Also referred to as "circulating the short way," since returns from bottom can be obtained more quickly than in normal circulation. rig n: the derrick or mast, drawworks, and attendant surface equipment of a drilling or workover unit. rig breaking capacity (performance) n: the capacity to hold the hook-load and retard the continuous movement of the hook load within reasonable specified limits compatible with specific requirements. rig, jackknife or folding mast n: the type mast that can be folded for moving as contrasted with the standard derrick, which has to be completely dismantled and re-erected. rig up v: to prepare the drilling rig for making hole, that is, to install tools and machinery before drilling is started. rock pressure adj: a term used for the initial pressure of gas in a well. roller cone bit n: a drilling bit made of two, three, or four cones, or cutters, that are mounted on extremely rugged bearings. The surface of each cone is made of rows of steel teeth or rows of tungsten carbide inserts. Also called rock bits. rotary bushing n: see master bushing. rotary drilling n: a drilling method in which a hole is drilled by a rotating bit to which a downward force is applied. The bit is fastened to and rotated by the drill stem, which also provides a passageway through which the drilling fluid is circulated. Additional joints of drill pipe are added as drilling progresses. rotary drilling rig n: basically hoisting equipment, prime movers and auxiliary equipment necessary to well drilling. Includes: Rotary table, draw-works, kelly, swivel, hook, blocks, line, engines, mud pumps and piping. (steel mud pits, if used) utilities unit, dog house, tool house, mud house, etc., and electric generators, motors, and wiring if used.

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rotary helper n: a worker on a drilling or workover rig. subordinate to the driller, whose primary work station is on the rig floor. On rotary drilling rigs, there are at least two and usually three or more rotary helpers on each crew. Sometimes called floorhand, floorman, rig crewman, or roughneck. rotary hose n: a reinforced flexible tube on a rotary drilling rig that conducts the drilling fluid from the standpipe to the swivel and kelly. Also called the mud hose or the kelly hose. rotary table n: the principal component of a rotary, or rotary machine, used to turn the drill stem and support the drilling assembly. It has a beveled gear arrangement to create the rotational motion and opening into which bushings are fitted to drive and support the drilling assembly. roughneck n: see rotary helper. round trip n: see making a trip. roustabout n: 1. a worker on an offshore rig who handles the equipment and supplies that are sent to the rig from the shore base. The head roustabout is very often the crane operator. roustabout n: 2. a worker who assists the foreman in the general work around a producing oilwell, usually on the property of the oil company. roustabout n: 3. a helper on a well servicing unit. run in v: to go into the hole with tubing, drill pipe, and so forth.

IADC Glossary - S safety joint n: a special joint used in drilling which can be unscrewed should the tool become stuck in the hole. samples n pl: 1. the well cuttings obtained at designated footage intervals during drilling. From an examination of these cuttings, the geologist determines the type of rock and formations being drilled and estimates oil and gas content. samples n pl: 2. small quantities of well fluids obtained for analysis. sand n: 1. an abrasive material composed of small quartz grains formed from the disintegration of preexisting rocks. Sand consists of particles less than 2 millimeters and greater than 1/16 millimeter in diameter. sand n: 2. sandstone. scratcher n: a device that is fastened to the outside of casing to remove mud cake from the wall of a hole to condition the hole for cementing. By rotating or moving the easing string up and down as it is being run into the hole, the scratcher, formed of stiff wire, removes the cake so that the cement can bond solidly to the formation. secondary cementing n: any cementing operation after the primary cementing operation. Secondary cementing includes a plug-back job, in which a plug of cement is positioned at a specific point in the well and allowed to set. Wells are plugged to shut off bottom water or to reduce the depth of the well for other reasons. seismograph n: a device that detects vibrations in the earth. It is used in studying the earth's interior and in prospecting for probable oil-bearing structures. Vibrations are created by discharging explosives in shallow boreholes, by striking the surface with a heavy blow, or by vibrating a heavy plate in contact with the ground. The type and velocity of the vibrations as recorded by the seismograph indicate the general characteristics of the section of earth through which the vibrations pass. semisubmersible drilling rig n: a floating offshore drilling unit that has pontoons and columns that, when flooded, cause the unit to submerge to a predetermined depth. Living quarters, storage space, and so forth are assembled on the deck. Semisubmersible rigs are self-propelled or towed to a drilling site and either anchored or dynamically positioned over the site, or both. In shallow water, some semisubmersibles can be ballasted to rest on the seabed.

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Semisubmersibles are more stable than drill ships and shipshape barges and are used extensively to drill wildcat wells in rough waters such as the North Sea. Two types of semisubmersible rigs are the bottle-type and the column stabilized. See floating offshore drilling rig. set casing v: to run and cement casing at a certain depth in the wellbore. Sometimes called set pipe. settling pit n: a pit that is dug in the earth for the purpose of receiving mud returned from the well and allowing the solids in the mud to settle out. Steel mud tanks are more often used today, along with various auxiliary equipment for controlling solids quickly and efficiently. shaker n: shortened form of shale shaker. See shale shaker. shaker pit n: see shaker tank. shaker tank n: the mud tank adjacent to the shale shaker, usually the first tank into which mud flows alter returning from the hole. Also called a shaker pit. shale n: a fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock. shale shaker n: a vibrating screen used to remove cuttings from the circulating fluid in rotary drilling operations. The size of the openings in the screen should be carefully selected to be the smallest size possible to allow 100 percent flow of the fluid. Also called a shaker. shaped charge n: a relatively small container of high explosive that is loaded into a perforating gun. On detonation, the charge releases a small, high-velocity stream of particles (a jet) that penetrates the casing, cement, and formation. See perforating gun. shear ram n: the component in a blowout preventer that cuts, or shears, through drill pipe and forms a seal against well pressure. Shear rams are used in floating offshore drilling operations to provide a quick method of moving the rig away from the hole when there is no time to trip the drill stem out of the hole. sheave (pronounced "shiv") n: 1. a grooved pulley. sheave (pronounced "shiv") n: 2. support wheel over which tape, wire, or cable rides. show n: the appearance of oil or gas in cuttings, samples, or cores from a drilling well. shut down v: to stop work temporarily or to stop a machine or operation. shut-in bottomhole pressure (SIBHP) n: the pressure at the bottom of a well when the surface valves on the well are completely closed. It is caused by formation fluids at the bottom of the well. sidetrack v: using a whipstock, turbodrill, or other mud motor to drill around broken drill pipe or casing that has become lodged permanently in the hole. sidewall coring n: a coring technique in which core samples are obtained from the hole wall in a zone that has already been drilled. A hollow bullet is fired into the formation wall to capture the core and then retrieved on a flexible steel cable. Core samples of this type usually range from 3/4 to 1-3/16 inches (20 to 30 millimeters) in diameter and from 3/4 to 4 inches (20 to 100 millimeters) in length. This method is especially useful in soft-rock areas. single n: a joint of drill pipe. Compare double, thribble, and fourble. skidding the rig v: moving a rig from the location of a lost or completed hole preparatory to starting a new one. In skidding the rig, the move is accomplished with little or no dismantling of equipment.

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slips n pl: wedge shaped pieces of metal with teeth or other gripping elements that are used to prevent pipe from slipping down into the hole or to hold pipe' in place. Rotary slips fit around the drill pipe and wedge against the master bushing to support the pipe. Power slips are pneumatically or hydraulically actuated devices that allow the crew to dispense with the manual handling of slips when making a connection. Packers and other downhole equipment are secured in position by slips that engage the inner surface of easing. slug the pipe v: before hoisting the drill stem from the hole, it is desirable to pump in to the top of the drill stem a quantity of very heavy mud which will cause the level of the fluid in the drill stem to fall as the drill stem is hoisted. Thus, when a stand of the drill stem has been unscrewed, the fluid will have been evacuated from it. This prevents the crew members and tools from becoming covered with drilling fluid. slurry n: 1. in drilling, a plastic mixture of cement and water that is pumped into a well to harden. There it supports the casing and provides a seal in the wellbore to prevent migration of underground fluids. slurry n: 2. a mixture in which solids are suspended in a liquid. slush pit n: now commonly used as mud pit. Originally it was the pit in which clay and shale cuttings used to mix mud were stored. sonic logging n: the recording of the time required for a sound wave to travel a specific distance through a formation. Difference in observed travel times is largely caused by variations in porosities of the medium, an important determination. The sonic log, which may be run simultaneously with a spontaneous potential log or a gamma ray log, is useful for correlation and often is used in conjunction with other logging services for substantiation of porosities. It is run in an uncased hole. spear n: a fishing tool used to retrieve pipe lost in a well. The spear is lowered down the hole and into the lost pipe. When weight, torque, or both are applied to the string to which the spear is attached, the slips in the spear expand and tightly grip the inside of the wall of the lost pipe. Then the string, spear, and lost pipe are pulled to the surface. specific gravity n: the ratio of the weight of a given volume of a substance at a given temperature to the weight of an equal volume of a standard substance at the same temperature. For example, if 1 cubic inch of water at 39'F weighs 1 unit and 1 cubic inch of another solid or liquid at 39'F weighs 0.95 unit, then the specific gravity of the substance is 0.95. In determining the specific gravity of gases, the comparison is made with the standard of air or hydrogen. See gravity. spinner survey n: an operation designed to indicate the point at which fluids are escaping from the wellbore into a cavernous or porous formation. Also used to determine point of formation fluid entry. spinning cathead n: a spool attachment on the makeup cathead to permit use of a spinning chain to spin up or make up drill pipe. See spinning chain. spinning chain n: a Y-shaped chain used to spin up (tighten) one joint of drill pipe into another. One end of the chain is attached to the tongs, another end to the spinning cathead, and the third end left free. The free end is wrapped around the tool joint, and the cathead pulls the chain off the joint, causing the joint to spin rapidly and tighten up. After the free end of the chain is pulled off the joint, the tongs are secured in the spot vacated by the chain and continued pull on the chain (and thus on the tongs) by the cathead makes up the joint to final tightness. spool, drilling n: a flanged joint with side outlets, also serving as a spacer, between rams in a blowout preventer stack or between stack and casinghead. spud v: 1. to move the drill stem up and down in the hole over a short distance without rotation. Careless execution of this operations creates pressure surges that can cause a formation to break down, resulting in lost circulation. spud v: 2. to force a wireline tool or tubing down the hole by using a reciprocating motion. spud v: 3. to begin drilling a well; i.e., to spud in.

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spud in v: to begin drilling; to start the hole. squeeze cementing n: the forcing of cement slurry by pressure to specified points in a well to cause seals at the points of squeeze. It is a secondary cementing method that is used to isolate a producing formation, seal off water, repair casing leaks, and so forth. stab v: to guide the end of a pipe into a coupling or tool joint when making up a connection. stabbing board n: a temporary platform erected in the derrick or mast some 20 to 40 feet (6-12 metres) above the derrick floor. The derrickman or another crew member works on the board while easing is being run in a well. The board may be wooden or fabricated of steel girders floored with anti-skid material and powered electrically to be raised or lowered to the desired level. A stabbing board serves the same purpose as a monkeyboard but is temporary instead of permanent. stabilizer n: a centralizer attached to the Drill Collar to center the bit in the hole. Stabilizers may be spaced out over the drill collar string to prevent the buckling of the collars and provide a rigid drilling assembly, i.e. "a packed hole assembly." or may be positioned in such a manner to take advantage of the bending moment of the drill collars to keep the bit drilling vertically sometimes called the "pendulum effect." stacking a rig v: storing a drilling rig upon completion of a job when the rig is to be withdrawn from operation for a period of time. stake a well v: to locate precisely on the surface of the ground the point at which a well is to be drilled. After exploration techniques have revealed the possibility of a subsurface hydrocarbon-bearing formation, a certified and registered land surveyor drives a stake into the ground to make the spot where the well is to be drilled. stand n: the connected joints of pipe racked in the derrick or mast during a trip. The usual stand is about 90 feet long (about 27 metres), which is three lengths of drill pipe screwed together (a thribble). stand it on the boards v: to bring the pipe out of the hole (make a trip) and rack it in the derrick. stand of pipe n: two, three or four joints of pipe fastened together, called a double, thribble, or fourble, respectively. standpipe n: a vertical pipe rising along the side of the derrick or mast, which joins the discharge line leading from the mud pump to the rotary hose and through which mud is pumped going into the hole. stimulation n: any process undertaken to enlarge old channels or to create new ones in the producing formation of a well (e.g., acidizing or formation fracturing). stratification n: the natural layering or lamination characteristic of sediments and sedimentary rocks. stratigraphic trap n: a petroleum trap that occurs when the top of the reservoir bed is terminated by other beds or by a change of porosity or permeability within the reservoir itself. Compare structural trap. string n: the entire length of casing, tubing, sucker rods, or drill pipe run into a hole. string up v: to thread the drilling line through the sheaves of the crown block and traveling block. One end of the line is secured to the hoisting drum and the other to the derrick substructure. structural trap n: a petroleum trap that is formed because of deformation (such as folding or faulting) of the reservoir formation. Compare stratigraphic trap. stuck pipe n: drill pipe, drill collars, casing, or tubing that has inadvertently become immovable in the hole. Sticking may occur when drilling is in progress, when easing is being run in the hole, or when the drill pie is being hoisted.

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sub n: a short, threaded piece of pipe used to adapt parts of the drilling string that cannot otherwise be screwed together because of differences in thread size or design. A sub (i.e., a substitute) may also perform a special function. Lifting subs are used with drill collars to provide a shoulder to fit the drill pipe elevators; a kelly saver sub is placed between the drill pipe and the kelly to prevent excessive thread wear of the kelly and drill pipe threads; a bent sub is used when drilling a directional hole. submersible drilling rig n: a mobile bottom-supported offshore drilling structure with several compartments that are flooded to cause the structure to submerge and rest on the seafloor. Submersible rigs are designed for use in shallow waters to a maximum of 175 feet (53.4 metres). Submersible drilling rigs include the posted barge submersible, the bottle-type submersible, and the arctic submersible. See bottom-supported offshore drilling rig. substructure n: the foundation on which the derrick or mast and usually the drawworks sit. It contains space for storage and well control equipment. suction pit n: also called a suction tank, sump pit, or mud suction pit. See suction tank. suction tank n: the mud tank from which mud is picked up by the suction of the mud pumps. Also called a suction pit. surface casing n: the first string of casing (after the conductor pipe) that is set in a well. It varies in length from a few hundred to several thousand feet. Some states require a minimum length to protect freshwater sands. Compare conductor pipe. swabbing v: operation of a lifting device on a wireline to bring well fluids to the surface when the well does not flow naturally. This is a temporary operation to determine whether or not the well can be made to flow or require artificial lift or stimulation to bring oil to the surface. swivel n: a rotary tool that is hung from the rotary hook and traveling block to suspend the drill stem and to permit it to rotate freely. It also provides a connection for the rotary hose and a passageway for the flow of drilling fluid into the drill stem. syncline n: a downwarped, trough shaped configuration of folded, stratified rocks. Compare anticline.

IADC Glossary - T TD abbr: total depth. tearing down v: the act of dismantling a rig at the completion of a well and preparing it for moving to the next location. tender n: the barge anchored alongside an offshore drilling platform. Usually contains living quarters, storage space, and the mud system. thread protector n: a metal or plastic device that is screwed onto or into pipe threads to protect them from damage when the pipe is not in use. thribble n: a stand of pipe made up of three joints and handled as a unit. Compare single, double, and fourble. thribble board n: the name used for the derrickman's working platform, the monkeyboard, when it is located at a height in the derrick equal to three lengths of pipe joined together. Compare double board and fourble board. See monkeyboard. throw the chain n: to flip the spinning chain up from a tool joint box so that the chain wraps around the tool joint pin after it is stabbed into the box. The stand or joint of drill pipe is turned or spun by a pull on the spinning chain from the cathead on the drawworks.

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tight formation n: a petroleum - or water - beating formation of relatively low porosity and permeability. tight hole n: 1. a well about which information is restricted for security or competitive reasons. tight hole n: 2. a section of the hole that, for some reason, is undergauge. For example, a bit that is worn undergauge will drill a tight hole. tongs n pl:the large wrenches used to make up or break out drill pipe, casing, tubing, or other pipe; variously called casing tongs, pipe tongs, and so forth, according to the specific use. Power tongs are pneumatically or hydraulically operated tools that serve to spin the pipe up tight and, in some instances, to apply the final makeup torque. tool joint n: a heavy coupling element for drill pipe. It is made of special alloy steel and has coarse, tapered threads and seating shoulders designed to sustain the weight of the drill stem, withstand the strain of frequent coupling and uncoupling, and provide a leakproof seal. The male section of the joint, or the pin, is attached to one end of a length of drill pipe, and the female section, or box, is attached to the other end. The tool joint may be welded to the end of the pipe, screwed on, or both. A hard-metal facing is often applied in a band around the outside of the tool joint to enable it to resist abrasion from the walls of the borehole. toolpusher n: an employee of a drilling contractor who is in charge of the entire drilling crew and the drilling rig. Also called a drilling foreman, rig manager, rig superintendent, or rig supervisor. torque n: the turning force that is applied to a shaft or other rotary mechanism to cause it to rotate or tend to do so. Torque is measured in units of length and force (foot-pounds, newton-metres). torque converter n: a hydraulic device connected between an engine and a mechanical load such as a compound. Torque converters are characterized by an ability to increase output torque as the load causes a reduction in speed. Torque converters are used on mechanical rigs that have compounds. total depth (TD) n: the maximum depth reached in a well. tour (pronounced "tower") n: a working shift for drilling crew or other oilfield workers. The most common tour is 8 hours; the three daily tours are called daylight, evening (or afternoon), and graveyard (or morning). Sometimes 12hour tours are used, especially on offshore rigs; they are called simply day tour and night tour. transmission n: the gear or chain arrangement by which power is transmitted form the prime mover to the drawworks, mud pump, or rotary table of a drilling rig. transmission loss or mechanical efficiency n: are related terms for expressing the same basic idea. The difference between input horsepower and output horsepower is transmission loss. It may be stated as so much horsepower or it may be expressed as percentage of input horsepower. The ratio of output horsepower to input horsepower is called mechanical efficiency. It is usually expressed in percent. There is some loss of power for every bearing, sheave, gear, chain, belt wireline, stuffing box, fluid-drive and electric-drive. trap n: a body of permeable oil-bearing rock surrounded or overlain by an impermeable barrier that prevents oil from escaping. The types of traps are structural, stratigraphic, hydrodynamic, or a combination of these. traveling block n: an arrangement of pulleys, or sheaves, through which drilling line is reeved and which moves up and down in the derrick or mast. See block. tricone bit n: a type of bit in which three cone-shaped cutting devices are mounted in such a way that they intermesh and rotate together as the bit drills. The bit body may be fitted with nozzles, or jets, through which the drilling fluid is discharged. trip n: the operation of hoisting the drill stem from and returning it to the wellbore. See make a trip. turbodrill n: a downhole motor that rotates a bit by the action of the drilling mud on turbine blades built into the tool. When a turbodrill is used, rotary motion is imparted only at the bit; therefore, it is unnecessary to rotate the drill stem. Although straight holes can be drilled with the tool, it is used most often in directional drilling.

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turning to the right n: a slang term on a rotary rig referring to the actual drilling operation during which the drill stem is rotated in a clockwise direction. twist-off v: to twist a joint of drill pipe in two by excessive force applied by the rotary table. Many failures which result in parting of the drill pipe in the wellbore are erroneously referred to by this term.

IADC Glossary - U underream v: to enlarge a drill hole below the casing. unit operator n: the oil company in charge of development and production in an oilfield in which several companies have joined to produce the field.

IADC Glossary - V vacuum n: a void; an absence of matter of any kind. Complete vacuum is not attained, but a partial vacuum or reduction in pressure through suction is achieved in various items of mechanical equipment. valve n: a device used to control the rate of flow in a line to open or shut off a line completely, or to serve as an automatic or semiautomatic safety device. Those used extensively include the check valve, gate valve, globe valve, needle valve, plug valve, and pressure relief valve. See check valve, needle valve, and pressure relief valve. vapor-proof adj: a term used to describe a produce which is not susceptible to the action of gases or other vapors. Its principal application on a drilling rig is to describe explosion proof light fixtures which are safe in the presence of combustible gases. V-belt n: a belt with a trapezoidal cross section, made to run in sheaves, or pulleys, with grooves of corresponding shape. V-door (window) n: an opening in a side of a standard derrick at the floor level having the form of an inverted V. This opening is opposite the drawworks. It is used as an entry to bring in drill pipe and casing from the pipe rack. viscosity n: a measure of a liquid's resistance to flow. The viscosity of petroleum products or mud is usually expressed, and measured by the time it takes for a certain volume to flow through an orifice of specific size. See Marsh Funnel. rug n: 1. a cavity in a rock. rug n: 2. a small cavern, larger than a pore but too small to contain a person. Typically found in limestone subject to ground water leaching.

IADC Glossary - W waiting on cement (WOC) adj: pertaining to the time when drilling or completion operations are suspended so that the cement in a well can harden sufficiently. wall cake n: also called filter cake or mud cake. See filter cake. water string n: a string of casing used to shut off all water above an oil sand. It is often necessary to run more than one string before a well is completed. water table n: the underground level at which water is found. This term is often used in connection with underground water supplies used for irrigation and industrial plants. Term also used to designate the top of the drilling derrick which supports the crown block. weevil n: shortened form of boll weevil. See boll weevil.

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weight indicator n: an instrument near the driller's position on a drilling rig that shows both the weight of the drill stem that is hanging from the hook (hook load) and the weight that is placed on the bit by the drill collars (weight on bit). weighting material n: a material that has a high specific gravity and is used to increase the density of drilling fluids or cement slurries. wellbore n: a borehole; the hole drilled by the bit. A wellbore may have casing in it or it may be open (uncased); or part of it may be cased, and part of it may be open. Also called a borehole or hole. See cased and open. well completion n: 1. the activities and methods of preparing a well for the production of oil and gas or for other purposes, such as injection. well completion n: 2. the method by which one or more flow paths for hydrocarbons are established between the reservoir and the surface. The method of well completion used by the operator depends on the individual characteristics of the producing formation or formations. These techniques include open-hole completions, sand exclusion completions, tubingless completions, multiple completions, and miniaturized completions. wellhead n: the equipment installed at the surface of the wellbore. A wellhead includes such equipment as the casinghead and tubing head. adj: pertaining to the wellhead (e.g., wellhead pressure). well logging n: the recording of information about subsurface geologic formations, including records kept by the driller and records of mud and cutting analyses, core analysis, drill stem tests, and electric, acoustic, and radioactivity procedures. Sec acoustic log, core analysis, driller's log, drill stem test, electric well log, mud analysis, and radioactivity log. well stimulation n: any of several operations used to increase the production of a well, such as acidizing or fracturing. See acidize, formation fracturing. whipstock n:a long steel casing that uses an inclined plane to cause the bit to deflect from the original borehole at a slight angle. Whipstock are sometimes used in controlled directional drilling, in straightening crooked boreholes, and in sidetracking to avoid unretrieved fish. wildcat n: 1. a well drilled in an area where no oil or gas production exists. wildcat n: 2. (nautical) the geared sheave of a windlass used to pull anchor chain. v: to drill wildcat wells. wind-load rating n: a specification of a derrick used to indicate the resistance of the derrick to the force of wind. The wind load rating is calculated according to formulas incorporated in API specifications. Typical wind resistance of derricks is 75 miles per hour with pipe standing in the derrick and 115 miles per hour and more with no pipe standing in the derrick. wireline n: a slender, rodlike or threadlike piece of metal, usually small in diameter, that is used for lowering special tools (such as logging sondes, perforating guns, and so forth). Compare wire rope. wire rope n: a cable composed of steel wires twisted around a central core of fiber or steel wire to create a rope of great strength and considerable flexibility. Wire rope is used as drilling line (in rotary and cable-tool rigs), coring line, servicing line, winch line, and so on. It is often called cable or wireline; however, wireline is a single, slender metal rod, usually very flexible. Compare wireline. WOC abbr: waiting on cement; used in drilling reports. workover v: to perform one or more of a variety of remedial operations on a producing oil well with the hope of restoring or increasing production. Examples of workover operations are deepening, plugging back, pulling and resetting the liner, squeeze cementing, shooting, and acidizing. worm n: 1. a new and inexperienced worker on a drilling rig.

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worm n: 2. a short revolving screw with spiral shaped-threads.

IADC Glossary - X IADC Glossary - Y yield n: a term used to define the quality of a clay by describing the number of barrels of a given centipoise slurry that can be made form a ton of clay. Based on the yield, clays are classified as bentonite, high-yield, low-yield, etc., types of clays. Not related to yield value below. See API RP 13B for procedures. yield point n: in drilling-fluid terminology, yield point means yield value (which see). Of the two terms, yield point is more common. yield value n: the yield value (commonly called “yield point”) is the resistance to initial flow, or represents the stress required to start fluid movement. This resistance is due to electrical charges located on or near the surfaces of the particles. The values of the yield point and thixotropy, respectively, are measurements of the same fluid properties under dynamic and static states. The Bingham yield value, reported in lb/100 sq ft, is determined by the directindicating viscometer by subtracting the plastic viscosity from the 300-rpm reading.

IADC Glossary - Z zero-zero gel n: a condition wherein the drilling fluid fails to form measurable gels during a quiescent time interval (usually 10 min). zeta potential n: the electrokinetic potential of a particle as determined by its electrophoretic mobility. This electric potential cause colloidal particles to repel each other and stay in suspension. zinc chloride n: ZnCl2 - A very soluble salt used to increase the density of water to points more than double that of water. Normally added to a system first saturated with calcium chloride. zone n: a section of the well’s formation.

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