IADC Drilling Manual
eBook Version (V.11)
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All Rights Reserved by International Association of Drilling Contractors
The IADC Drilling Manual Published by Technical Toolboxes, Inc.
3801 Kirby Drive, Suite 340
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Tel: 713-630-0505
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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".
This Page Left Intentionally Blank
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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IADC Drilling Manual - Eleventh Edition
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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IADC Drilling Manual - Eleventh Edition
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 Equiptment......................... 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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IADC Drilling Manual - Eleventh Edition
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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IADC Drilling Manual - Eleventh Edition
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 Equiptment Descriptions ................................................................................................ R-62
R-5 Surface Equiptment 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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Table of Contents
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
Chapter A
Bit Classification and Grading
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IADC Drilling Manual - Eleventh Edition
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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Chapter A: Bit Classification and Grading
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
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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IADC Drilling Manual - Eleventh Edition
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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Chapter A: Bit Classification and Grading
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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IADC Drilling Manual - Eleventh Edition
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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Chapter A: Bit Classification and Grading
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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IADC Drilling Manual - Eleventh Edition
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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Chapter A: Bit Classification and Grading
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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IADC Drilling Manual - Eleventh Edition
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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Chapter A: Bit Classification and Grading
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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IADC Drilling Manual - Eleventh Edition
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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Chapter A: Bit Classification and Grading
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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Chapter A: Bit Classification and Grading
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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Chapter A: Bit Classification and Grading
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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Chapter A: Bit Classification and Grading
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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Chapter A: Bit Classification and Grading
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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Chapter A: Bit Classification and Grading
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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Chapter A: Bit Classification and Grading
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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Chapter A: Bit Classification and Grading
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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Chapter A: Bit Classification and Grading
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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Chapter B: Drill String
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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For Full Size Image of this Table Click Here
Table B1-1 Tool Joints on Standard Weight Drill Pipe - Grade 75
IADC Drilling Manual - Eleventh Edition
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Table B1-2 Tool Joints on Light Weight Drill Pipe - Grade 75
For Full Size Image of this Table Click Here
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Chapter B: Drill String
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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
For Full Size Image of this Table Click Here
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Chapter B: Drill String
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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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Chapter B: Drill String
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For Full Size Image of this Table Click Here
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Chapter B: Drill String
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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For Full Size Image of this Table Click Here
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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For Full Size Image of this Table Click Here
Table B1-7 Minimum OD and Make-up Torque of Weld-on Tool Joints
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For Full Size Image of this Table Click Here
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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 <From API RP 7G, 14th ed. Table 2.14>
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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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Chapter B: Drill String
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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Chapter B: Drill String
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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Chapter B: Drill String
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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Chapter B: Drill String
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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Chapter B: Drill String
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 <Past & Present (1992)>
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
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
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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For Full Size Image of This Table Click Here
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Chapter C: Casing and Tubing
Table C1-1b 8-Rd LT Casing Make-up Torque
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For Full Size Image of This Table Click Here
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Chapter C: Casing and Tubing
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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For Full Size Image of This Table Click Here
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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
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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
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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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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 D5-3a TJ Dim. for E, X, G, and S DP 2-3/8 IF -- 4-1/2 IEU
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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
Chapter E
Pipe Handling Equiptment
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Table of Contents - Chapter E
Pipe Handling Equiptment
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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Chapter E: Pipe Handling Equipment
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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Chapter E: Pipe Handling Equipment
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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Chapter E: Pipe Handling Equipment
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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Chapter E: Pipe Handling Equipment
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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Chapter E: Pipe Handling Equipment
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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Chapter E: Pipe Handling Equipment
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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Chapter E: Pipe Handling Equipment
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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Chapter E: Pipe Handling Equipment
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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Chapter E: Pipe Handling Equipment
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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Chapter E: Pipe Handling Equipment
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
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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Chapter F: Drawworks Brakes
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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Chapter F: Drawworks Brakes
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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Chapter F: Drawworks Brakes
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Chapter F: Drawworks Brakes
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Chapter F: Drawworks Brakes
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Chapter F: Drawworks Brakes
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Chapter F: Drawworks Brakes
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Chapter F: Drawworks Brakes
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 F: Drawworks Brakes
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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
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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Chapter G: Chains and Sprockets
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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Chapter G: Chains and Sprockets
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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Chapter G: Chains and Sprockets
Roller Chain Drive Troubleshooting Guide
Excessive Noise
Chain Climbs Sprocket Teeth
Chain Clings to Sprocket
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IADC Drilling Manual - Eleventh Edition
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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International Association of Drilling Contractors
Chapter G: Chains and Sprockets
Cracked Link Plates
Broken Pins
Broken, Cracked, or Deformed Rollers
Pin Galling
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IADC Drilling Manual - Eleventh Edition
Worn Link Plate Contour
Battered Link Plate Edges
Missing Parts
Rusted Chain
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International Association of Drilling Contractors
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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G-45
Chapter H: Rotary Hose & Swivel
Chapter H
Rotary Hose and Swivels
International Association of Drilling Contractors
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IADC Drilling Manual - Eleventh Edition
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
H-2
International Association of Drilling Contractors
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.
International Association of Drilling Contractors
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IADC Drilling Manual - Eleventh Edition
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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International Association of Drilling Contractors
Chapter H: Rotary Hose & Swivel
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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IADC Drilling Manual - Eleventh Edition
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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International Association of Drilling Contractors
Chapter H: Rotary Hose & Swivel
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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IADC Drilling Manual - Eleventh Edition
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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IADC Drilling Manual - Eleventh Edition
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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International Association of Drilling Contractors
Chapter H: Rotary Hose & Swivel
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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IADC Drilling Manual - Eleventh Edition
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
H-12
International Association of Drilling Contractors
Chapter H: Rotary Hose & Swivel
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.
International Association of Drilling Contractors
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IADC Drilling Manual - Eleventh Edition
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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International Association of Drilling Contractors
Chapter H: Rotary Hose & Swivel
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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IADC Drilling Manual - Eleventh Edition
* 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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Chapter H: Rotary Hose & Swivel
Figure H4-1a Inspection of Rotary Swivel - External
International Association of Drilling Contractors
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IADC Drilling Manual - Eleventh Edition
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 H: Rotary Hose & Swivel
This Page Left Intentionally Blank
International Association of Drilling Contractors
H-19
Chapter I: Engines - Care and Maintenance
Chapter I
Engines
International Association of Drilling Contractors
I-1
IADC Drilling Manual - Eleventh Edition
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
I-2
International Association of Drilling Contractors
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.
International Association of Drilling Contractors
I-3
IADC Drilling Manual - Eleventh Edition
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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International Association of Drilling Contractors
Chapter I: Engines - Care and Maintenance
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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IADC Drilling Manual - Eleventh Edition
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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International Association of Drilling Contractors
Chapter I: Engines - Care and Maintenance
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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International Association of Drilling Contractors
Chapter I: Engines - Care and Maintenance
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.
International Association of Drilling Contractors
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IADC Drilling Manual - Eleventh Edition
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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Chapter I: Engines - Care and Maintenance
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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Chapter I: Engines - Care and Maintenance
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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IADC Drilling Manual - Eleventh Edition
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: Pumps
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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Chapter J: Pumps
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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Chapter J: Pumps
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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Chapter J: Pumps
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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Chapter J: Pumps
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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Chapter J: Pumps
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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International Association of Drilling Contractors
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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: BOP Equipment, Procedures
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.
International Association of Drilling Contractors
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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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Reading & Bates Drilling Company
International Association of Drilling Contractors
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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Chapter K: BOP Equipment, Procedures
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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Chapter K: BOP Equipment, Procedures
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.
<Reference> "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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Chapter K: BOP Equipment, Procedures
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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Chapter K: BOP Equipment, Procedures
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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Chapter K: BOP Equipment, Procedures
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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Chapter K: BOP Equipment, Procedures
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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Chapter K: BOP Equipment, Procedures
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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International Association of Drilling Contractors
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Chapter L: Derricks and Masts
Chapter L
Derricks and Masts
International Association of Drilling Contractors
L-1
IADC Drilling Manual - Eleventh Edition
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
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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.
International Association of Drilling Contractors
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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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Chapter L: Derricks and Masts
Dreco Inc.
International Association of Drilling Contractors
L-5
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Dreco Inc.
L-6
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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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
International Association of Drilling Contractors
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
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International Association of Drilling Contractors
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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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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IADC Drilling Manual - Eleventh Edition
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International Association of Drilling Contractors
Chapter L: Derricks and Masts
International Association of Drilling Contractors
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IADC Drilling Manual - Eleventh Edition
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
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International Association of Drilling Contractors
Chapter L: Derricks and Masts
Folding Masts
"Dynamic" Derricks
International Association of Drilling Contractors
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IADC Drilling Manual - Eleventh Edition
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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International Association of Drilling Contractors
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 ______
International Association of Drilling Contractors
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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.
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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 _______________________________________
International Association of Drilling Contractors
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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
M-1
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
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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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IADC Drilling Manual - Eleventh Edition
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
International Association of Drilling Contractors
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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
M-7
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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International Association of Drilling Contractors
Chapter M: Wire Rope
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.
International Association of Drilling Contractors
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IADC Drilling Manual - Eleventh Edition
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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International Association of Drilling Contractors
Chapter M: Wire Rope
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.
International Association of Drilling Contractors
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IADC Drilling Manual - Eleventh Edition
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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International Association of Drilling Contractors
Chapter M: Wire Rope
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.
International Association of Drilling Contractors
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IADC Drilling Manual - Eleventh Edition
Table M1-3 Sizes and Constructions of Wire Rope for Oilfield Service
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International Association of Drilling Contractors
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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IADC Drilling Manual - Eleventh Edition
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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Chapter M: Wire Rope
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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Chapter M: Wire Rope
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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IADC Drilling Manual - Eleventh Edition
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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Chapter M: Wire Rope
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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Chapter M: Wire Rope
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