STD.API/PETRO R P 7G-ENGL la996 - 0 7 3 2 2 9 0 ObO=lbbE’ 3 7 0 m

Recommended Practice for DrillStem Design and Operating Limits

API RECOMMENDED PRACTICE 7GSIXTEENTH EDITION, AUGUST 1998

EFFECTIVE DATE: DECEMBER I,1998

wbStrategies for Today’sEnvironmental Partnership

AmericanPetroleumInstitute

S T D . A P I / P E T R O R P 7G-ENGL I,998 - 0 7 3 2 2 9 0 0609663 2 0 7 -

s&bS t r a t e g i e s f o r TodayS-E n v i r o n m e n t a l P a r t n e r s h i p

API ENVIRONMENTAL, HEALTH AND SAFETY MISSIONAND GUIDING PRINCIPLES

The members of the American Petroleum Institute are dedicated to continuous efforts toimprove the compatibility of our operations with the environment while economicallydeveloping energy resources and supplying high quali ty products and services to consum-ers. We recognize our responsibil i ty to work with the public, the government, and others todevelop and to use natural resources in an environmentally sound manner while protectingthe health and safety of our employees and the public. To meet these responsibilities, APImembers pledge to manage our businesses according to the following principles usingsound science to prioritize risks and to implement cost-effective management practices:

l To recognize and to respond to community concerns about our raw materials, prod-ucts and operat ions.

l To operate our plants and faci l i t ies , and to handle our raw materials and products in amanner that protects the environment, and the safety and health of our employeesand the public.

l To make safety, health and environmental considerations a priority in our planning,and our development of new products and processes.

l To advise promptly, appropriate officials, employees, customers and the public ofinformation on significant industry-related safety, health and environmental hazards,and to recommend protective measures.

l To counsel customers, transporters and others in the safe use, transportat ion and dis-posal of our raw materials, products and waste materials.

l To economically develop and produce natural resources and to conserve thoseresources by using energy efficiently.

l To extend knowledge by conducting or supporting research on the safety, health andenvironmental effects of our raw materials, products, processes and waste materials.

l To commit to reduce overall emissions and waste generation.

l To work with others to resolve problems created by handling and disposal of hazard-ous substances from our operat ions.

l To participate with government and others in creating responsible laws, regulationsand standards to safeguard the community, workplace and environment.

l To promote these principles and practices by sharing experiences and offering assis-tancc to others who produce, handle, use, transport or dispose of similar raw materi-als , petroleum products and wastes.

S T D . A P I / P E T R O R P 7G-ENGL l1978 m 0 7 3 2 2 9 0 Ob09bb4 143 m

Recommended Practice for Drill StemDesign and Operating Limits

Exploration and Production Department

API RECOMMENDED PRACTICE 7GSIXTEENTH EDITION, AUGUST 1998

EFFECTIVE DATE: DECEMBER 1,1998

!I? AmericanPetroleumInstitute

Helping YouOetTheJObDone Rim%

STD.API/PETRO R P 7G-ENGL L998 - 0 7 3 2 2 9 0 0609665 OBT -

SPECIAL NUTES

API publications necessarily address problems of a general nature. With respect to partic-ular circumstances, local, state, and federal laws and regulations should be reviewed

API is not undertaking to meet the duties of employers, manufacturers, or suppliers towarn and properly train and equip their employees, and others exposed, concerning healthand safety risks and precautions, nor undertaking their obligations under local, state, or fed-eral laws.

Information concerning safety and health risks and proper precautions with respect to par-ticular materials and conditions should be obtained from the employer, the manufacturer orsupplier of that material, or the material safety data sheet.

Nothing contained in any API publication is to be construed as granting any right, byimplication or otherwise, for the manufacture, sale, or use of any method, appamtus, or prod-uct covered by letters patent. Neither should anything contained in the publication be con-strued as insuring anyone against liability for infringement of letters patent.

Generally, API standards are reviewed and revised, reafhrmed, or withdrawn at least everyfive years. Sometimes a one-time extension of up to two years will be added to this reviewcycle. This publication will no longer be in effect five years after its publication date as anoperative API standard or, where an extension has been granted upon republication. Statusof the publication can be ascertained from the API Exploration and production Department[telephone (202) 682-80001. A catalog of API publications and materials is published annu-ally and updated quarterly by API, 1220 L Street, N.W., Washington, D.C. 20005.

This document was produced under API standardization procedures that ensure appropri-ate notitication and participation in the developmental process and is designated as an APIstandard. Questions concerning the interpretation of the content of this standard or com-ments and questions concerning the procedures under which this standard was developedshould be directed in writing to the director of the Exploration and Production Department,American Petroleum Institute, 1220 L Street, N.W., Washington, D.C. 20005. Requests forpermission to reproduce or translate all or any part of the material published herein shouldalso be addressed to the director.

API standards are published to facilitate the broad availability of proven, sound engineer-ing and operating practices. These standards are not intended to obviate the need for apply-ing sound engineering judgment regarding when and where these standards should beutilized. The formulation and publication of API standards is not intended in any way toinhibit anyone from using any other practices.

Any manufacturer marking equipment or materials in calf ormance with the markingrequirements of an API standatd is solely responsible for complying with all the applicablerequkements of that standard. API does not represent, warrant, or guarantee that such prod-ucts do in fact conform to the applicable API standard

AU rights nzserved No part of this work may be mpnxhce4 stored in a retrieval system, ortmnsmitted by any means, electronic, mechanical, photocopying, Tecording, or otherwise,

without prior written permission from the publisher: Contact the Publishel;API Publishing Services, 1220 L Street, N. W!, Washington, D. C. 2cxXS.

Copyright Q 1998 America0 petroleum Iustim

STD.API/PETRO RI’ -7G-ENGL L99B - 0 7 3 2 2 9 0 0609bbb TLb -

FOREWORDThis recommended practice is under the jurisdiction of the API Subcommittee on Stan-

dadization of Drilling and Servicing Equipment.The purpose of this recommended practice is to standardize techniques for the procedure

of dr i l l s tem design and to defme the operat ing l imits of the driIl s tem.API publications may be used by anyone desiring to do so. Every effort has been made by

the Inst i tute to assure the accumcy and reliability of the data contained in them; however, theInsti tute makes no representat ion, warranty or guarantee in connection with this publicat ionand hereby expressly disclaims any liability or responsibility for loss or damage resultingfrom i ts use or for the violat ion of any federal, s tate , or municipal regulat ion with which thispubl icat ion may confl ic t .

I

Changes from th& previous edit ion are denoted with bars in the margins. The bars indicatenew content or major editorial changes. Changes to section numbem due to reformatting orminor editorial changes are not denoted with bars .

Suggested revisions are invi ted and should be submit ted to the director of the Explorat ionand Production Department, American Petroleum Institute, 1220 L Street, N.W., Washing-ton, DC. 20005.

T&is WC ommmakd pmctice shall become @ective on the date printed on the cover butmay be used voluntarily from the date ofdistribution.

iii

STD.API/PETRO R P 7G-ENGL 1998 - 0 7 3 2 2 9 0 Ob09bb7 952 m

CONTENTS

1 SCOPE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.1 Coverage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 . 2 SectionCoverage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

2 REFERENCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

3 DEFINITIONS....................................................- . . . . 1

4 PROPERTIESOFDRILLPIPEANDTOOLJOINTS . . . . . . . . . . . . . . . . . . . . . . . . . 3

5 PROPERTIES OF DRILL COLLARS, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 3

6 PROPERTIES OF KELLYS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 3

7 DESIGNCALCULATIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 67.1 DesignParameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 67.2 Special Design Parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 67.3 Supplemental Drill Stem Members. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 67.4 TensionLoading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 67.5 CollapseDuetoExtemalFl~dRessure.~. . . . . . . . . . . . . . . . . . . . . . . . . . . 5 07.6 Internal~ssure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 17 .7 TorsionalStrength . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 17 .8 ExampIe CaIcuIation of a Typical Drill String Design-Based on

MarginofOverpull. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 17 .9 DrillPipeBendingResultingFromTongingOperaGons.. . . . . . . . . . . . . . . . 5 2

8 LIMITATIONS RELATED TO HOLE DEVIATION . . . . . . . . . . . . . . . . . . . . . . . . 538 . 1 FatigueDamage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 38.2 Remedial Action to Reduce Fatigue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 48.3 Estimation of Cumulative Fatigue Damage . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 88.4 Iden~cationofFatiguedJoints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 88.5 WearofToolJointsandDrilIPipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 88.6 HeatcheckingofToolJoints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 9

9 LIMITATIONS RELATED TO FLOATING VESSELS . . . . . . . . . . . . . . . . . . . . . . 5 9

1 0 DRILL STEM CORROSION AND SULFIDE STRESS CRACKING . . . . . . . . . . . 6 210.1 Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 210.2 sulfklestress crackirlg . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 41 0 . 3 DrillingFluidsContaiuing Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 5

1 1 COMPRESSIVE SERVICE LIMITS FOR DRILL PIPE. . . . . . . . . . . . . . . . . . . . . . 6 711 .l Compressive Service Applications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 71 1 . 2 DrillPipeBucklinginStraight,InclinedWellBores . . . . . . . . . . . . . . . . . . . . 6 71 1 . 3 Critical Buckling Force for Curved Boreholes. . . . . . . . . . . . . . . . . . . . . . . . . 7 811.4 Bending Stresses on Compressively Loaded Drill Pipe in Curved Boreholes 7911.5 Fat.igueLimitsforAPIDrillPipe.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 611.6 Esthating Cumulative Fatigue Damage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 811.7 Bending Stresses onBuckIedDriUPipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 0 1

1 2 SPECIAL SERVICE PROBLEMS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 0 11 2 . 1 Severe Downhok Vibration- . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 0 112.2 Trausitionh-omDrillPipetoDrillCollars.. . . . . . . . . . . . . . . . . . . . . . . . . . 108

V

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STD=API/PETRO R P 7G-ENGL I,998 M 0 7 3 2 2 9 0 Ob09bb8 899 -

1 2 . 3 pullingonStuckpipe...............................- . . . . . . . . . . . 1081 2 . 4 Jarring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10912.5 Torque in Washover Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10912.6 AlIowable Hookload aud Torque Combinations . . . . . . . . . . . . . . . . . . . . . . 10912.7 BiaxialLoadingofDrillPipe.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11012.8 Formulas and Physical Constants. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11012.9 Transition from Elastic to Plastic Collapse. . . . . . . . . . . . . . . . . . . . . . . . . . . 11012.10 Effect of Tensile Load on Collapse Resistance. . . . . . . . . . . . . . . . . . . . . . . . 11012.11 Example Calculation of Biaxial Loading ............................ 110

1 3 IDENTIFICATION, INSPECI‘ION AND CLASSIFICATION OF DRILLsTEMcoMPoNENTs.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11213.1 Drill Striug Marking andIdentification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11213.2 InspectionStandards--DrillpipeandTubingWorkS~~. . . . . . . . . . . . . 1121 3 . 3 TooiJoints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12213.4 Drill collar Inspection Procahm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12413.5 Drill ColhxHandling Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1241 3 . 6 Kellys............................-.........................- . 12513.7 RecutConnections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12613.8 Piu Stress Relief Grooves for Rental Tools and Other Short Term

UsageTools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126

1 4 WELDINGONDOWNHOLEDRILLINGTOOLS.. . . . . . . . . . . . . . . . . . . . . . . 127

1 5 DYNAMIC LOADING OF DRILL PIPE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127

1 6 CLASSlFICATION SlZE AND MAKE-UP TORQUE FOR ROCK BlTS. . . . . . . 127

APPENDIX A STRENGTH AND DESIGN FO RMULAS . . . . . . . . . . . . . . . . . . . . . 1 3 1APPENDIXB ARTICLES ANDTECHNICALPAPERS . . . . . . . . . . . . . . . . . . . . . . 145

Figuresl-25 Torsional Strength and Recommended Make-up Torque Curves. . . . . . . . . . 20-3226272829303 132333435

363738394041

DrillCollarBendingStrengthRatios.1’/,andl3/,InchID.. . . . . . . . . . . . . . . . 39lkillCollarBendingStrengthRatios,2and21/,InchID.. . . . . . . . . . . . . . . . . . 40DrillCollarBendingStrengthRatios,21/,InchID . . . . . . . . . . . . . . . . . . . . . . . . 41~CollarBendingStrengthRatios,213/,,InchID . . . . . . . . . . . . . . . . . . . . . . . 42DriUColl~BendingStceugthRatios,3InchID.. . . . . . . . . . . . . . . . . . . . . . . . . 43DrillCollarBendingStrengthRatios,3l/,InchID . . . . . . . . . . . . . . . . . . . . . . . . 44DrillCollarBendingStrengthRatios,31/,InchID . . . . . . . . . . . . . . . . . . . . . . . . 45New Kelly-New Drive Assembly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48New Kelly-New Drive Assembly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48Maximum Height of Tool Joint Above Slips to Prevent BendingDuringTonging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53DoglegSeverityLimitsforFatigueofGradeE75Drillpipe.. . . . . . . . . . . . . . . 55DoglegSeverityLimitsforFatigueof S-135DrillPipe . . . . . . . . . . . . . . . . . . . . 56LateralForceonToolJoint . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57Fatigue Damage iu Gradual Doglegs (Noncormsive Environment). . . . . . . . . . . 58Fatigue Damage in Gradual Doglegs (In Extremely Corrosive Environment) . . 58Lateral Forces on Tool Joints and Range 2 Drill Pipe 3l/, Inch, 13.3 PoundsperFoot,Range2DrillPipe,43/,InchToolJoints.. . . . . . . . . . . . . . . . . . . . . . . 60

STD.API/PETRO R P 7G-ENGL I1998 - 0 7 3 2 2 9 0 Oh09669 7 2 5 -

4 2 Lateral Forces on Tool Joints and Range 2 Drill Pipe 4V2 Inch, 16.6 PoundsperFoot,Range2Dri~pipe,61/,InchToolJoints. . . . . . .._. . . . . . . . . . ._... 60

4 3 Lateral Forces on Tool Joints and Range 2 Drill Pipe 5 Inch, 19.5 Pounds perF~~Range2DrillPipe,63/,InchToolJoints . . . . . . . . . . . . .., . . . . . . . . . . . . 61

4 4 Lateral Forces on Tool Joints and Range 3 Drill Pipe 5 Inch, 19.5 Pounds perFoot,Range3Drillpipe,63/,~chT~lJoints . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

4 5 Delayed-Failure Chamcteristics of &notched Specimens of an SAE 4340 SteelDuring Cathodic Charging with Hydrogen Under Standardized Conditions. . . . 66

46-66 Approximate Axial Compressive Loads at which Sinusoidal Buckling isExpectedtoocCur............................................ 68-78

67a-74a Bkling Stress and Fatigue Limits. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80-9467b-74b Lateral Contact Forces and Length . . . . . . . . . . . . . . . _ . . . . . . . . . . . . . . 8 1-957 57 67 77 8 a78b7 9 a79b80a8 0 b8 1

8 28 3

8 48 58 68 78 88 99 0A-lA-2A-3A-4

A-5A-6A-7

Tables1234567

Hole Curvature Adjustment Factor To Allow for Differences in Tooljoint OD’s. 9 7Median Failure Limits for API Drillpipe Noncorrosive Service. . . . . . . . . . . . . . 9 9Minimum Failure Limits for API Drillpipe Noncorrosive Service. . . . . . . . . . . 100Bending Stress for High Curvatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102Lateral Contact Forces and Length. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 0 3Bending Stress for High Curvatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104Lateral Contact Forces and Length. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105Bending Stress for High Curvatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106LateralContactForcesandLength . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 0 7Ellipse of Biaxial Yield Stress or Maximum Shear-Strain Energy DiagramAfter Holmquist and Nadai, Collapse of Deep Well Casing, APK Drilling andproductionpractice(1939) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1 1Marking on Tool Joints for Identification of Drill String Components . . . . . . . 1 1 3Recommended Practice for Mill Slot and Groove Method of DrillStringIdentification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 114Identification of Lengths Covered by Inspection Standards . . . . . . . . . . . . . . . . 116Drill Pipe and Tool Joint Color Code Identification. . . . . . . . . . . . . . . . . . . . . . 122Tong Space and Bench Mark Position . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 2 3Drill Collar Elevator. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124Drill Collar Grooves for Elevators and Slips. . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 2 5DrillCollarWear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 2 5Modified Pin Stress-Relief Groove . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126Eccentric Hollow Section of Drill Pipe. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 3 1RotaryShoulderedConnedion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133Limits for Combined Torsion and Tension for a Rotary Shouldered Connection134Rotary Shouldered Connection Location of Dimensions for BendingStrengthRatioCalculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 136Buckling Force vs Hole Curvature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139Buckling Force vs Hole Curvature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 140Buckling Force vs Hole Curvature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 4 1

New Drill Pipe Dimensional Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4New Drill Pipe Torsional andTensile Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5NewDrillPipeCollapseandInternalPressureData . . . . . . . . . . . . . . . . . . . . . . . . 6Used Drill Pipe Torsional and Tensile Data API Premium Class. . . . . . . . . . . . . . . 7Used Drill Pipe Collapse and Internal Pressure Data API Premium Class . . . . . . . 8UsedDrillPipeTorsionalandTensileDataAPIClass2.. . . . . . . . . . . . . . . . . . . . 9UsedDrillPipeCollapseandlntemalPressureDataAPIClass2.. . . . . . . . . . . . 1 0

v i i

STD.API/PETRO R P 7G-ENGL 1996 - 0 7 3 2 2 9 0 0609670 4 4 7 -

8910

11121 31 4

1 516

1 71 81 9202 12223242526

27

2829

303132333435

MechanicalpropertiesofNewToolJointsandNeworadeE75Drillpipe.. . . . 11Mechanical Properties of New Tool Joints and New High Strength Drill Pipe . . . 1 3Recommended Minimum OD and Makeup Torque of Weld-on Qpe ToolJointsBasedonTorsionalStrengthofBoxandDrillPipe.. . . . . . . . . . . . . . . . . . 1 5BuoyancyFactors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 8Rotary Shouldered Connection Interchange List. . . . . . . . . . . . . . . . . . . . . . . . . . 1 9DrillCollarweight(steel)@oundsperfoot). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34Recommended Make-up Torque1 for Rotary Should Drill CollarCOnnectiOnS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35StrengthofKellys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47Contact Angle Between Kelly and Bushing for Development of MaximumWidthWearPattern . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48Strength of Remachined Kellys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49SectionModulusValues..............................-............- . 53EffectofDrillingFluidTypeonCoefficientofFriction . . . . . . . . . . . . . . . . . . . . 67Hole curvatures that Prevent Buckling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79Youngstown Steel Test Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96Fatigue Endurance Limits Compressively Loaded Drill Pipe . . . . . . . . . . . . . . . . 98ValuesUsedinPreparingFigure77.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98ClassiftcationofUsedDrillPipe.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115Classification of Used Tubing Work Strings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117Hook-Load at MinimumY~eld Strength for New, Premium Class (Used), andclass2(used)Drillpipe............................- . . . . . . . . . . . . . . . 1 1 8Hook-Load at MinimumYleld Strength for New, premium Class (Used), andClass2(Used)TubingWorkStrings.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120DrillCollarGrooveandElevatorBoreDimensions.. . . . . . . . . . . . . . . . . . . . . . 125Maximum Stress at Root of Last Engaged T&ad for the Pin of an NC50AxisymmetricModel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126IADC Roller Bit Classification Chart . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 2 8L4DC Bit Classi6cation Codes Fourth Position. . . . . . . . . . . . . . . . . . . . . . . . . . 129Recommended Make-up Torque Ranges for Roller Cone Drill Bits. . . . . . . . . . 129Recommended Minimum Make-up Torques for Diamond Drill Bits . . . . . . . . . 130Common Roller Bit Sizes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130Common Fixed Cutter Bit Sizes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130

A- 1 Rotary Shouldered Connection Thread Element Information . . . . . . . . . . _ . . . . 143

. . .VIII

STD.API/PETRO R P 7G-ENGL I,998 - 0 7 3 2 2 9 0 0609b7L 383 -

1 scope1.1 COVERAGE

Recommended Practice for Drill Stem Design and Operating Limits

This recommended practice involves not only the selectionof drill string members, but also the consideration of holeangle control, drilling fluids, weight and rotary speed, andother operational procedures.

1.2 SECTION COVERAGE

Sections 4, 5, 6, and 7 provide procedures for use in theselection of drill string members. Sections 8, 9, 10, 11, 12,and 15 are related to operating limitations which may reducethe normal capability of the drill string. Section 13 contains aclassification system for used drill pipe and used tubing workstrings, and identification and inspection procedures for otherdrill string members. Section 14 contains statements regard-ing welding on down hole tools. Section 16 contains a classi-fication system for rock bits.

2 References(See also Appendix B.)

RP 5CA Care and Use of Casing and TubingBull 5C3 Bulle t in on Formulas and Calculutions for

Casing, Tubing, Dri l l Pipe, and Line PipePropert ies

Spec7 Specijication for Rotary Drill Stem Ele-ments

IZP 7Al Recommended Practice for Testing ofThread Compounh for Rotary Shouhieredconnectio?ls

RP 13B-1 Recommended Practice Stanahrd Proce-dure for Fie ld Tes t ing Water -Based Dr i l l -ing Flui&

RP 13B-2 Recommended Practice StMdard Pnxe-dure for Field Test ing Oi l -Based Dri l l ingFluids

ASTM’D3370 Standard Practices for Sampling Water

NACE2MIX-01-75 Sulfide Stress Cracking Res i s tant Meta l l i c

Materiul for Oil Field Equipment

‘American !3ociety for Testing Materials, 100 Barr Harbor Drive, West Con-shccken. Pennsylvania 19428.ZNACE International, P.O. Box 218340, Houston, Texas 772184340.

3

3.1

Definitionsbending strength ratio: The ratio of the section

modulus of a rotary shouldered box at the point in the boxwhere the pin ends when made up divided by the section mod-ulus of the rotary shouldered pin at the last engaged thread.

3.2 bevel diameter: The outer diameter of the contactface of the rotary shouldered connection.

3.3 bit sub: A sub, usually with 2 box connections, that isused to connect the bit to the drill string.

3.4 box connection: A threaded connection on OilCountry Tubular Goods (OCTG) that has internal (female)threads.

3.5 calibration system: A documented system of gaugecalibration and control.

3.6 Class 2: An API service classification for used drillpipe and tubing work strings.

3.7 cold working: Plastic deformation of metal at a tem-perature low enough to insure or cause permanent strain.

3.8 corrosion: The alteration and degradation of materialby its environment

3.9 critical rotary speed: A rotary speed at which har-monic vibrations occur. These vibrations may cause fatiguefailures, excessive wear, or bending.

3.10 decarburization: The loss of carbon from the sur-face of a ferrous alloy as a result of heating in a medium thatrwcts with the carbon at the surface.

3.11 dedendum: The distance between the pitch line androotofthread.

3.12 dogleg: A term applied to a sharp change of direc-tion in a wellbore or ditch. Applied also to the permanentbending of wire rope or pipe.

3.13 dogleg severity: A measure of the amount ofchange in the inclination and/or direction of a bomhole, usu-ally expressed in degrees per 100 feet of course length.

3.14 drift: A drift is a gauge used to check minimum ID ofloops, flowlines, nipples, tubing, casing, drill pipe, and drillcollars.

3.15 drill collar: Thick-walled pipe or tube designed toprovide stiffness and concentration of weight at the bit.

3.16 drill pipe: A length of tube, usually steel, to whichspecial thmaded co~ections called tool joints are attached

1

STD.API/PETRO R P 7G-ENGL l1998 m 0 7 3 2 2 9 0 0609b72 2LT -

2 API RECDMMENDED PRACI-ICE 76

3.17 drill string element: Drill pipe with tool jointsattached.

3.18 failure: improper performance of a device or equip-ment that prevents completion of its design function.

3.19 fatigue: The process of progressive localized perma-nent structural change occurring in a material subjected toconditions that produce fluctuating stresses and strains atsome point or points and that may culminate in cracks orcomplete fmctunz after a sufiicient number of fluctuations.

3.20 fatigue failure: A failure which originates as a resultof repeated or fluctuating stresses having maximum valuesless than the tensile strength of the material.

3.21 fatigue crack: A crack resulting from fatigue. Seefatigue.

3.22 forging: (1) PlasticaIly deforming metal, usually hot,into desired shapes with compressive force, with or withoutdies. (2) A shaped metal part formed by the forging method.

3.23 kelly: The square or hexagonal shaped steel pipe con-necting the swivel to the drill string. The kelly moves throughthe rotary table and transmits torque to the chill string.

3.24 kelly saver sub: A short substitute that is made uponto the bottom of the kelly to protect the pin end of the kellyfrom wear during make-up and break-out operations.

3.25 last engaged thread: The last thread on the pinengaged with the box or the box engaged with the pin.

3.28 lower kelly valve: An essentially f&opening valveinstalled immediately below the kelly, with outside diameterequal to the tool joint outside diameter. Valve can be closed toremove the kelly under pressure and can be shipped in thehole for snubbing operations.

3.27 make-up shoulder: The sealing shoulder on arotay shouldered connection.

3.28 minimum make-up torque: The minimum make-up torque is the minimum amount of torque necessary todevelop an arbitrarily derived tensile stress in the pin or com-pressive stress in the box. This arbitrarily derived stress levelis perceived as being su&ient in most drilling conditions toprevent downhole make-up and to prevent shoulder separa-tion frombending loads.

329 minirnumOD:Fortooljointsondrillpipewithrotaryshouldered connections, the minimumODistheminimumboxODthatwill~~thecwnectiontoremainasstrongasaspecified percentage of the drill pipe tube in torsior~

3.39 oil muds: The term “oil-base drill& fluid” isapplied to a special type drilling fluid where oil is the contin-uous phase and water the dispersed phase. Such fluids containblown asphalt and usually 1 to 5 percent water emulsified into

the system with caustic soda or quick lime and an organicacid. Silicate, salt, and phosphate may also be present. Oil-base drilling fluids are differentiated from invert-emulsiondrilling fluids (both water-in& emulsions) by the amounts ofwater used, method of controlling viscosity and thixotropicproperties, wall-building materials, and fluid loss.

3.31 pin end: A threaded connection on Oil CountryTubular Goods (OCTG) that has external (male) threads.

3.32 plain end: Drill pipe, tubing, or casing withoutthreads. The pipe ends may or may not be upset

3.33 premium class: An API service classification forused driil pipe and tubing work strings.

3.34 quenched and tempered: Quench hardening-Hardening a ferrous alloy by austenitizing and then coolingrapidly enough so that some or all of the austenite transformsto martensite.Tempering-Reheating a quenched-hardened or normal&dferrous alloy to a temperature below the transformation rangeand then cooling at any rate desired.

3.35 range: A length classification for API Oil Countrymbular Goods.

3.39 rotary shouldered connection: A connectionused on drill string elements which has coarse, taperedthreads and seating shouldem.

3.37 shear strength: The stress required to produce frac-ture in the plane of cross section, the conditions of loadingbeing such that the directions of force and of resistance areparallel and opposite although their paths are offset a speci-fied minimum amount.. The maximum load divided by theoriginal cross-sectional areaofa section separatedby shear.

3.38 slip area: The slip area is contained within a distanceof 48 inches along the pipe body from the juncture of the tooljoint OD and the elevator shoulder.

3.39 stress-relief feature: A modi&ation performed onrotary should& connections which removes the unengagedthreads of the pin or box. This process makes tbe joint monoflexible and reduces the likelihood of fatigue cracking in thishighlystressedarea

3.40 swivel: Device at the top of the drill stem which per-mits simultaneous circulation and rotation.

3.41 tensile strength: The maximum tensile stresswhich a mat&al is capable of sustaining. Tensile strength iscalculated from the maximum load during a tension test car-ried to N~~UN and the Original ~~~~+ectiOd area Of thespecimen.

3.42 test pressure: A pressure above working lnessureused to demonstrate structural integrity of a press vessel.

STD.API/PETRO R P 7G-ENGL I,998 W 0 7 3 2 2 9 0 0609673 156 -

RECOMMENDED PFWCT~CE FOR DRLL STEM DESIGN AND OPEFLATING km-s 3

3.43 thread form: The form of thread is the thread profilein an axial plane for a length of one pitch.

3.44 tolerance: The amount of variat ion permit ted.

3.45 tool joint: A heavy coupling element for driU pipehaving coarse, tapered threads and sealing shoulders designedto sustain the weight of the dr i l l s tem, withstand the s t rain ofqxated make-up and break-out, resist fatigue, resist addi-tional make-up during drilling, and provide a leak-proof seal.The male section (pin) is attached to one end of a length ofdril l pipe. and the female section (box) is at tached to the otherend Tool joints may be welded to the dri l l pipe, screwed ontothe pipe, or a combination of screwed on and welded.

3.46 upper kelly cock: A valve immediately above thekelly that can be closed to confine pressures inside the drilltig.

3.47 upset: A pipe end with increased wall thickness. Theoutside diameter may be increased, or the inside diametermay be reduced, or both. Upsets sule usually formed by hotforging the pipe end

3.46 working gauges: Gauges used for gauging pmductthreads.

3.49 working pressure: The pressure to which a partic-ular piece of equipment is subjected during normal opera-t ions .

3.50 working temperature: The temperature to which aparticular piece of equipment is subjected during normaloperat ions.

4 Properties of Drill Pipe and Tool Joints4.1 This section contains a series of tables (Tables 1through 11) designed to present the dimensional , mechanical ,and performance properties of new and used drill pipe. Tablesare also included listing these properties for tool joints usedwith new and used dri l l pipe.

4.2 All drill pipe and tool joint properties tables areincluded in Sect ion 4 .

4.3 Values listed in drill pipe tables are based on acceptedstandards of the industry and calculated fmm formulas inAppendix A.

4.4 Recommended drift diameters for new drill stringassemblies are shown in column 8 of Tables 8 and 9. Driftbars must be a minimum of four inches long. The drift barmust pass through the upset area but need not penetrate morethan twelve inches beyond the base of the elevator shoulder.

4.5 The torsional strength of a tool joint is a function of sev-eral variables. These include the strength of the steel, connec-

t ion size, thread form, lead, taper and coefficient of friction onmating surfaces, threads, or shoulders. The coefficient of fiic-

lion for the purposes of this lecommended practice isassumed a constant; i t has been demonstmted, however, thatnew tool joints and tice temperature often affect the coeffi-cient of friction of the tool joint system. While new tool jointstypically exhibit a low coefficient of friction, service tempera-tures greater than 300°F can dramatically increase or decreasethe coefficient of friction depending primarily on thread com-pound The torque required to yield a mtary shouldered con-nection may be obtained from the equation in Section A-8.

4.6 The pin or box area, whichever controls, is the largestfactor and is subject to the widest variation. The tool joint out-side diameter (OD) and inside diameter (ID) largely deter-mine the strength of the joint in torsion. The OD affects theboxareaandthelDaffectsthepinarea.ChoiceofODandIDdetermines the areas of the pin and box and establishes thetheoretical torsional strength, assuming all other factors areconstant .

4.7 The greatest reduction in theoretical torsional strengthof a tool joint during its service life occurs with OD wear. Atwhatever point the tool joint box area becomes the smaller orcontrolling area, any further reduction in OD causes a directreduction in torsional s trength. If the box area controls whenthe tool joint is new, initial OD wear reduces torsionalstrength. If the pin controls when new, some OD wear mayoccur before the torsional strength is affected Conversely, i t ispossible to increase torsional strength by making joints withoversize OD and reduced ID.

4.6 Minimum OD, box shoulder, and make-up torque val-ues listed in Table 10 were determined using the followingcriteria:

4.6.1 Calculations for recommended tool joint make-uptorque are based on the use of a thread compound containing40 to 60 percent by weight of finely powdered metallic zincapplied to al l threads and shoulders, and containing not morethan 0.3 percent total active sulfur (reference the cautionregarding the use of hazardous materials in Speciiication 7,Appendix G). Calculations are also based on a tensile stress of60 percent of the minimum tensile yield for tool joints.

4.6.2 In calculation of torsional strengths of tool joints,both new and worn, the bevels of the tool joint shoulders aredisregarded.

4.6.3 premium Class Dri l l Str ing is based on dr i l l p ipe hav-ing a minimum wall thickness of 80 percent.

4.8.4 Class 2 drill string allows drill pipe with a minimumwall thickness of 70 percent .

4.8.5 The tool joint to pipe torsional ratios that are usedhere (20.80) are recommendations only and it should be real-ized that other combinations of dimensions may be used Agiven assembly that is suitable for certain service may beinadequate for some areas and overdesigned for others.

STD.API/PETRO R P 7G-ENGL 1998 - 0 7 3 2 2 9 0 ObO9b74 092 -

4 API REW~MENDED PRACIICE 76

Table l-New Dril l Pipe Dimensional Data

(1) (2) (3) (4) (5) (6> 0

Size N o m i n a l W e i g h t SectionArea PolaTsecticmalO D -and PlainEnd Wall I D BodyofPi~ MCdUlUS3i n C0UldiXlg.S Weight’ ThiCkIESS 111. sq. in. cu.ilLD l b/ i t 1lSt i n . d A Z

2’iR 4 . 8 56 . 6 5

2% 6 . 8 5IO.40

3112 9 . 5 01 3 . 3 01 5 . 5 0

4 1 1 . 8 51 4 . 0 01 5 . 7 0

4’12 1 3 . 7 51 6 . 6 02 0 . 0 02 2 . 8 2

5 1 6 . 2 51 9 . 5 02 5 . 6 0

5’1, 19.m2 1 . 9 02 4 . 7 0

f% 2 5 . 2 02 7 . 7 0

4 . 4 3 .1906 . 2 6 .280

6 . 1 6 .2179 . 7 2 .362

8 . 8 1 25412.31 3681 4 . 6 3 A49

1 0 . 4 6 .26212.93 .3301 4 . 6 9 .380

1 2 . 2 4 -2711 4 . 9 8 -3371 8 . 6 9 -4302 1 . 3 6 .500

1 4 . 8 7 .2%1 7 . 9 3 .3622 4 . 0 3 .5m

1 6 . 8 7 -30419.81 .3612 2 . 5 4 A15

2 2 . 1 9 -3302 4 . 2 2 -362

1 . 9 9 5 1 . 3 0 4 2 1 . 3 2 11 . 8 1 5 1 . 8 4 2 9 1 . 7 3 3

2 . 4 4 1 1 . 8 1 2 0 2 . 2 4 12 . 1 5 1 2 . 8 5 7 9 3 . 2 0 4

2 . 9 9 2 2 . 5 9 0 2 3 . 9 2 32 . 7 6 4 3 . 6 2 0 9 5 . 1 4 42.m 4 . 3 0 3 7 5 . 8 4 7

3 . 4 7 6 3 . 0 7 6 7 5 . 4 0 03 . 3 4 0 3 . 8 0 4 8 6 . 4 5 83 . 2 4 0 4 . 3 2 1 6 7 . 1 5 7

3 . 9 5 8 3.6cm 7 . 1 8 43 . 8 2 6 4 . 4 0 7 4 8 . 5 4 33 . 6 4 0 5 . 4 9 8 1 1 0 . 2 3 23.5cm 6 . 2 8 3 2 1 1 . 3 4 5

4 . 4 0 8 4 . 3 7 4 3 9 . 7 1 84 . 2 7 6 5 . 2 7 4 6 1 1 . 4 1 54sxm 7 . 0 6 8 6 14.491

4 . 8 9 2 4.%24 12.2214 . 7 7 8 5 . 8 2 8 2 1 4 . 0 6 24 . 6 7 0 6.62% 1 5 . 6 8 8

5.965 6 . 5 2 6 2 1 9 . 5 7 25 . 9 0 1 7 . 1 2 2 7 2 1 . 1 5 6

‘lb/ft = 3.3996 x A (COL 6)=A = 0.7854 (P - op)

M = 0.19635 D+( B)

4.9 Many sizes and styles of connecuous are interchange-able with certain other sizes and styles of connections. Thesecmditions differ only in name aud in some cases thread form.If the head fixms are interchangeable, the connections aminterchangeable.

These interchangeable connections are listed inTable 12.

4.10 The curves of Figures 1 through 25 depict the theoreti-cal torsional yield stmngth of a number of commonly usedtool joint connections over a wide range of inside and outsidedbmetas. The coefficient of tiction on mating smfkes,threads and shoulders, is assumed to be 0.08 (See Section 3 ofAPI lW 7A1, Recommended Pmciice for Testing of ThmadCompound for Romy Sho&red Corme&ns). The makeup torque should be based on a tensile stress level of 60 per-centofthe minimum yield for tool joints.

4.11 The curves may be used by taking the following steps:

4.11 .l Select the appropriately titled curve for the size andtype tool joint connection being studied.

4.11.2 Extend a horizoutal line from the OD under consid-eration to the curve and read the torsional strength mpresent-ingthebox.

4.11.3 Extend a vertical line from the ID to the curve andread the torsional stmngth repmsenting the pin.

4.11.4 The smallex of the two torsional stmngths thusobtained is the tkoretical torsional strength of the tool joint

4.11.5 It is emphasized that the values obtained from thecurves are theoretical values of torsional strength. Tooljoints in the field, subject to many factors not included indetermiuation of points for the curves, may vary from thesuvalues.

4.11.6 The curves are most useful to show the relative tor-sional strengths of joints for variations in OD and ID, bothnew and after wear. In each case, the smaller vale should be

(Text amtilIued on page 33.)

STD=API/PETRO R P 7G-ENGL l,qqB m 0732290 0609b75 T29 -

REWMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPmimNo hms 5

Table 2-New Drill Pipe Torsional and Tensile Data

(1)

Si2.CO Dm.

(2)N o m i n a l W e i g h t

Threadsand~uplings

lb&

(3)

E75

(4) (5)

‘ T o r s i o n a l D a t aTorsional Yield Stmqth, A-lb

x95 G 1 0 5

(6)

s135

Q (8) (9) (10)

2Tensile Data Based on Minimum ValuesLoad at the Minimum Yield Strength, lb

E75 x95 GlO5 s 1 3 5

4 . 8 5

6 . 6 5

6 . 8 5

1 0 . 4 0

9.50

1 3 . 3 0

1 5 . 5 0

4

4’1,

5

1 1 . 8 5 19474. 2 4 6 6 8 . 2 7 2 6 4 . 3 5 0 5 4 . 2 3 0 7 5 5 . 2 9 2 2 9 0 . 3 2 3 0 5 7 . 4 1 5 3 6 0 .

1 4 . 0 0 2 3 2 8 8 . 2 9 4 9 8 . 32603. 4 1 9 1 8 . 2 8 5 3 5 9 . 3 6 1 4 5 4 . 3 9 9 5 0 2 . 5 1 3 6 4 6 .

1 5 . 7 0 2 5 8 1 0 . 3 2 6 9 2 . 3 6 1 3 4 . 4 6 4 5 8 . 3 2 4 1 1 8 . 4 1 0 5 5 0 . 4 5 3 7 6 5 . 5 8 3 4 1 3 .

1 3 . 7 5 2 5 9 0 7 . 32816. 3 6 2 7 0 . 4 6 6 3 3 . 2 7 0 0 3 4 . 3 4 2 0 4 3 . 3 7 8 0 4 7 . 4 8 6 0 6 1 .

1 6 . 6 0 3 0 8 0 7 . 3 9 0 2 2 . 4 3 1 3 0 . 5 5 4 5 3 . 3 3 0 5 5 8 . 4 1 8 7 0 7 . 4 4 2 7 8 1 . 5 9 5 0 0 4 .

m.00 3 6 9 0 1 . 4 6 7 4 1 . 5 1 6 6 1 . 66421. 4 1 2 3 5 8 . 5 2 2 3 2 0 . 5 7 7 3 0 1 . 7 4 2 2 4 4 .

2 2 . 8 2 40912. 5 1 8 2 1 . 5 7 2 7 6 . 7 3 6 4 1 . 4 7 1 2 3 9 . 596903. 6 5 9 7 3 4 . 8 4 8 2 3 0 .

1 6 . 2 5 3 5 0 4 4 . 4 4 3 8 9 . 4 9 0 6 2 . 6 3 0 7 9 . 328073. 4 1 5 5 5 9 . 4 5 9 3 0 2 . 5 9 0 5 3 1 .

1 9 . 5 0 4 1 1 6 7 . 5 2 1 4 4 . 5 7 6 3 3 . 7 4 1 0 0 . 3 9 5 5 9 5 . 5 0 1 0 8 7 . 5 5 3 8 3 3 . 7 1 2 0 7 0 .

25.60 5 2 2 5 7 . 6 6 1 9 2 . 7 3 1 5 9 . 9 4 0 6 2 . 5 3 0 1 4 4 . 6 7 1 5 1 5 . 7 4 2 2 0 1 . 9 5 4 2 5 9 .

1 9 . 2 0

2 1 . 9 0

2 4 . 7 0

2 5 . 2 0 7 0 5 8 0 . 8 9 4 0 2 . 9 8 8 1 2 . 1 2 7 0 4 4 .

2 7 . 7 0 7 6 2 9 5 . 9 6 6 4 0 . 1 0 6 8 1 3 1 3 7 3 3 0 .

4 7 6 3 . 6 0 3 3 . 6668. 8 5 7 4 . 9 7 8 1 7 . 1 2 3 9 0 2 . 1 3 6 9 4 4 . 1 7 6 0 7 1 .

6 2 5 0 . 7 9 1 7 . 8 7 5 1 . 1 1 2 5 1 . 1 3 8 2 1 4 . 1 7 5 0 7 2 . 193500. 2 4 8 7 8 6 .

8 0 8 3 . 1 0 2 3 8 . 1 1 3 1 6 . 1 4 5 4 9 . 135902. 1 7 2 1 4 3 . 1 9 0 2 6 3 . 2 4 4 6 2 4 .

1 1 5 5 4 . 1 4 6 3 5 . 1 6 1 7 6 . 2 0 7 9 8 . 2 1 4 3 4 4 . 2 7 1 5 0 3 . 3Om82. 3 8 5 8 2 0 .

1 4 1 4 6 . 1 7 9 1 8 . 1 9 8 0 5 . 2 5 4 6 3 . 1 9 4 2 6 4 . 2 4 6 0 6 8 . 2 7 1 9 7 0 . 34%76.

1 8 5 5 1 . 2 3 4 9 8 . 2 5 9 7 2 . 3 3 3 9 2 . 2 7 1 5 6 9 . 3 4 3 9 8 8 . 3 8 0 1 9 7 . 4 8 8 8 2 5 .

2 1 0 8 6 . 2 6 7 0 8 . 2 9 5 2 0 . 3 7 9 5 4 . 3 2 2 7 7 5 . 4 0 8 8 4 8 . 4 5 1 8 8 5 . 5 8 0 9 9 5 .

4 4 0 7 4 . 5 5 8 2 6 . 6 1 7 0 3 . 7 9 3 3 2 . 3 7 2 1 8 1 . 4 7 1 4 2 9 . 5 2 1 0 5 3 . 6 6 9 9 2 5 .

5 0 7 1 0 . 6 4 2 3 3 . 7 0 9 9 4 . 9 1 2 7 8 . 4 3 7 1 1 6 . 5 5 3 6 8 1 . 6 1 1 9 6 3 . 7 8 6 8 0 9 .

5 6 5 7 4 . 7 1 6 6 0 . 79204. 1 0 1 8 3 3 . 4 9 7 2 2 2 . 6 2 9 8 1 4 . 696111. 8 9 4 9 9 9 .

489464.

5 3 4 1 9 9 .

6 1 9 9 8 8 . 6 8 5 2 5 0 . 8 8 1 0 3 5 .

6 7 6 6 5 1 . 7 4 7 8 7 7 . 9 6 1 5 5 6 .

‘Basedontbeshearstrqthequalto57.7paxmofminim um yield strength and nominal wall thichw.M i n i m u m t o r s i o n a l y i e l d s t r e n g t h c a l c u l a t e d from E q u a t i o n A . 1 5 .

winimumtensilestIengthcalculat!=dfromEquatioIlk13.

STD.API/PETRO R P 7G-ENGL L998 m 0 7 3 2 2 9 0 Ob09b76 965 -

6 API RECOMMENDED FMcmc~ 76

Table 3-New Drill Pipe Collapse and Internal Pressure Data

(1)

S i zeO Dill.

(2)N o m i n a l W e i g h t

Threadsandc-l-m3

1Wfi

(3)

E75

(4) Q

cdapsePlt?sslueBasedoll. .MlmmumVal~, psi

x95 G 1 0 5

(61

s135

(7)

lx75

(8) (9)

internal pressure at.

h4mmumYleld Stmqth, psix95 G105

(10)

s 1 3 5

2318 4 . 8 5

6 . 6 5

2% 6 . 8 5

1 0 . 4 0

3v2 9 . 5 0

1 3 . 3 0

1 5 . 5 0

1 1 . 8 5

1 4 . 0 0

1 5 . 7 0

1 3 . 7 5

1 6 . 6 0

20.00

2 2 . 8 2

1 6 . 2 5

1 9 . 5 0

2 5 . 6 0

5’1, 1 9 . 2 0

2 1 . 9 0

2 4 . 7 0

@Is 25.20

2 7 . 7 0

ll@lO. 1 3 9 8 4 . 1 5 4 5 6 . 1 9 0 3 5 . 1 0 5 0 0 . 13300. 14700. 18900.

1 5 5 9 9 . 1 9 7 5 9 . 2 1 8 3 9 . 28079. 1 5 4 7 4 . 1 9 6 0 0 . 2 1 6 6 3 . 2 7 8 5 3 .

1 0 4 6 7 . 1 2 9 4 0 . 1 4 0 2 0 . 1 7 0 3 4 . 9 9 0 7 . 1 2 5 4 8 . 1 3 8 6 9 . 1 7 8 3 2 .

1 6 5 0 9 . 2 0 9 1 1 . 2 3 1 1 2 . 2 9 7 1 6 . 1 6 5 2 6 . 2 0 9 3 3 . 2 3 1 3 7 . 2 9 7 4 7 .

loool. 1 2 0 7 7 . 1 3 0 5 5 . 1 5 7 4 8 . 9 5 2 5 . 1 2 0 6 5 . 1 3 3 3 5 . 1 7 1 4 5 .

1 4 1 1 3 . 1 7 8 7 7 . 1 9 7 5 8 . 2 5 4 0 4 . 13800. 1 7 4 8 0 . 1 9 3 2 0 . 2 4 8 4 0 .

1 6 7 7 4 . 2 1 2 4 7 . 2 3 4 8 4 . 3 0 1 9 4 . 1 6 8 3 8 . 2 1 3 2 8 . 2 3 5 7 3 . 3 0 3 0 8 .

8 3 8 1 . 9 9 7 8 . 1 0 7 0 8 . 12618. 8 5 9 7 . 1 0 8 8 9 . 1 2 0 3 6 . 1 5 4 7 4 .

1 1 3 5 4 . 1 4 3 8 2 . 1 5 8 % . 2 0 1 4 1 . 1 0 8 2 8 . 1 3 7 1 6 . 1 5 1 5 9 . 1 9 4 9 1 .

128%. 1 6 3 3 5 . 1 8 0 5 5 . 2 3 2 1 3 . 1 2 4 6 9 . 1 5 7 9 4 . 1 7 4 5 6 . 2 2 4 4 4 .

7 1 7 3 . 8 4 1 2 . 8 9 5 6 . 1 0 2 8 3 . 7 9 0 4 . 10012. 1 1 0 6 6 . 1 4 2 2 8 .

1 0 3 9 2 . 1 2 7 6 5 . 1 3 8 2 5 . 1 6 7 7 3 . 9 8 2 9 . 1 2 4 5 0 . 1 3 7 6 1 . 1 7 6 9 3 .

1 2 9 6 4 . 1 6 4 2 1 . 1 8 1 4 9 . 2 3 3 3 5 . 1 2 5 4 2 . 1 5 8 8 6 . 1 7 5 5 8 . 2 2 5 7 5 .

1 4 8 1 5 . 1 8 7 6 5 . 2 0 7 4 1 . 261567. 1 4 5 8 3 . 1 8 4 7 2 . 2 0 4 1 7 . 2 6 2 5 0 .

6 9 3 8 . 8 1 0 8 . 8 6 1 6 . 9 8 3 1 . 7 7 7 0 . 9 8 4 2 . 10878. 1 3 9 8 6 .

9 9 6 2 . 1 2 0 2 6 . 1 2 9 9 9 . 1 5 6 7 2 . 9 5 0 3 . 12037. 133M 1 7 1 0 5 .

1 3 5 0 0 . 171cn. 18900. 24300. 1 3 1 2 5 . 1 6 6 2 5 . 1 8 3 7 5 . 2 3 6 2 5 .

6 0 3 9 . 6 9 4 2 . 7 3 1 3 . 8 0 9 3 . 7 2 5 5 . 9 1 8 9 . 1 0 1 5 6 . 1 3 0 5 8 .

8 4 1 3 . 1 0 0 1 9 . 1 0 7 5 3 . 1 2 6 7 9 . 8 6 1 5 . 1 0 9 1 2 . 1 2 0 6 1 . 15507.

1 0 4 6 4 . 1 2 9 3 3 . 1 4 0 1 3 . 1 7 0 2 3 . 9 9 0 3 . 1 2 5 4 4 . 1 3 8 6 5 . 1 7 8 2 6 .

4 7 8 8 . 5 3 2 1 . 5 5 0 0 . 6 0 3 6 . 6 5 3 8 . 82-81. 9 1 5 3 . 1 1 7 6 8 .

58%. 6 7 5 5 . 7 1 0 3 . 7 8 1 3 . 7 1 7 2 . 9cw. loo40. 12909.

Note:Calculatim1mebasedonformulainAPIBulletin5C3.

STD.API/PETRO R P ? G - E N G L 1998 W 0 7 3 2 2 9 0 0609677 8TL -

RECOMMENDED PRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS 7

Table 4-Used Drill Pipe Torsional and Tensile Data API Premium Class

(1) (2) (3) (4) (5) (‘5) 0 (8) (9) (10)

Size

New WeightNominal W/-and l-%rsional Yield Strength TensileDataBasedonUniformWear

O D collplillgsIn. M-t E75

Based on Unif- Ww, t-lbx95 G105 s135

Load at Minimum Yield Strength, lbJz75 x95 G105 s135

23/* 4.85

6.65

2va 6.85

10.40

3’/* 9.50

13.30

15.50

11.85

14.00

15.70

4’& 13.75

16.60

20.00

22.82

16.25

19.50

25.60

5’12 19.20

21.90

24.70

6% 25.20

27.70

3725. 4719. 5215. 6705. 76893. 97398. 107650. 138407.

4811. 6093. 6735. 8659. 107616. 136313. 150662. 193709.

6332. 8020. 8865. 11397. 106946. 135465. 149725. 192503.

8858. 11220. 12101. 15945. 166535. 210945. 233 149. 299764.

11094. 14052. 15531. 19968. 152979. 193174. 214171. 275363.

14361. 18191. 20106. 25850. 212150. 268723. 297010. 381870.

16146. 20452. 22605. 29063. 250620. 3 17452. 350868. 451115.

15310. 19392. 21433. 27557. 182016. 230554. 254823. 327630.

181%. 23048. 25474. 32752 224L82. 283%3. 313854. 403527.

20067. 25418. 28094. 36120. 253851. 321544. 355391. 456931.

20403. 25844. 28564. 36725. 213258. 270127. 298561. 383864.

24139. 30576. 33795. 43450. 260165. 329542. 364231. 468297.

28683. 36332. 40157. 51630. 322916. 409026. 452082. 581248.

3 1587. 40010. 44222. 56856. 367566. 465584. 514593. 661620.

27607. 34969. 38650. 4%93. 259155. 328263. 362817. 466479.

32285. 40895. 45199. 58113. 311535. 394612. 436150. 560764.

40544. 51356. 56762. 72979. 414690. 525274. 580566. 746443.

34764. 44035. 48670. 62575. 294260. 372730. 411965. 529669.

39863. 50494. 55809. 71754. 344780. 436721. 482692. 620604.

44324). 56139. 62048. 79776. 391285. 495627. 547799. 704313.

55766. 71522 79050. 101635. 387466. 490790. 542452. 697438.

60192. n312. 85450. 109864. 422419. 535064. 591387. 760354.

*Based on the shear strength equal to 57.7 percent of minimum yield swqtb.%mional data based on u) percent uniform wear on outside diameter and tensile data based on 20 percent uniform weax on outside diame.ter.

STD.API/PETRO R P 7G-ENGL I1798 W 0732290 Ob09678 738 m

8 API RECOMMENDED PRKTICE 7G

Table 5-Used Drill Pipe Collapse and Internal Pressure Data API Premium Class

(1)

S i z eO Di n .

(2)N o m i n a l W e i g h t

-headsandcouplings

lbm

(3)

E 7 5

(4) (5)

‘collapse pressureBased on MinimumVahes. psi

x95 G105

(6)

s135

0 (8) (9) (10)

%%mum hterd Yield l+xsure. .atlammum Yiild Stnagth, psi

E75 x95 G105 5 1 3 5

231, 4 . 8 5

6 . 6 5

2’fs 6 . 8 5

1 0 . 4 0

31/z 9 . 5 0

1 3 . 3 0

1 5 . 5 0

1 1 . 8 5

1 4 . 0 0

1 5 . 7 0

1 3 . 7 5

1 6 . 6 0

2 0 . 0 0

2 2 . 8 2

1 6 . 2 5

1 9 . 5 0

2 5 . 6 0

5’/2 1 9 . 2 0

2 1 . 9 0

2 4 . 7 0

6% 25.20

2 7 . 7 0

8 5 2 2 . 1 0 1 6 1 . 1 0 9 1 2 . 1 2 8 9 1 . 9600. 1 2 1 6 0 . 1 3 4 4 0 . 1 7 2 8 0 .

1 3 3 7 8 . 1 6 9 4 5 . 1 8 7 2 9 . 2 4 0 8 0 . 1 4 1 4 7 . 1792a 19806. 2 5 4 6 5 .

7 6 4 0 . 9 0 1 7 . %33. 1 1 1 8 6 . 9 0 5 7 . 1 1 4 7 3 . 1 2 6 8 0 . 1 6 3 0 3 .

1 4 2 2 3 . 1 8 0 1 6 . 1 9 9 1 2 2 5 6 0 2 . 1 5 1 1 0 . 1 9 1 3 9 . 2 1 1 5 3 . 2 7 1 9 7 .

7 0 7 4 . 8 2 8 4 . 8 8 1 3 . 1 0 0 9 3 . 8 7 0 9 . 1 1 0 3 1 . 12192. 1 5 6 7 5 .

1 2 0 1 5 . 1 5 2 1 8 . 16820. 2 1 6 2 6 . 1 2 6 1 7 . 1 5 9 8 2 . 1 7 6 6 4 . 2 2 7 1 1 .

1 4 4 7 2 . 1 8 3 3 1 . 2 0 2 6 0 . 2 6 0 4 9 . 1 5 3 9 4 . 1 9 4 9 9 . 2 1 5 5 2 . 2 7 7 1 0 .

5704. 6 5 0 8 . 6 8 2 7 . 7 4 4 5 . 7 8 6 0 . 9 9 5 6 . 1 1 0 0 4 . 1 4 1 4 8 .

9 0 1 2 . 1 0 7 9 5 . 1 1 6 2 2 . 1 3 8 3 6 . 9 9 0 0 . 1 2 5 4 0 . 1 3 8 6 0 . 1 7 8 2 0 .

1 0 9 1 4 . 1 3 8 2 5 . 1 5 1 9 0 . 1 8 5 9 3 . 1 1 4 0 0 . 14440. 1 5 9 6 0 . 20520.

4 6 8 6 . 5 1 9 0 . 5 3 5 2 . 5 9 0 8 . 7 2 2 7 . 9 1 5 4 . 1 0 1 1 7 . 1 3 0 0 8 .

7 5 2 5 . 8 8 6 8 . 9 4 6 7 . 1 0 9 6 4 . 8 9 8 7 . 1 1 3 8 3 . 1 2 5 8 1 . 1 6 1 7 6 .

1 0 9 7 5 . 1 3 9 0 1 . 1 5 3 5 0 . 1 8 8 0 6 . 1 1 4 6 7 . 14524. 16053. 2 0 6 4 0 .

1 2 6 5 5 . lE030. 1 7 7 1 8 . 2 2 7 8 0 . 1 3 3 3 3 . 1 6 8 8 9 . 1 8 6 6 7 . 24oal

4 4 9 0 . 4 9 3 5 . 5 0 6 7 . 5 6 6 1 . 7 1 0 4 . 8 9 9 8 . 9 9 4 6 . 1 2 7 8 7 .

7 0 4 1 . 8 2 4 1 . 8 7 6 5 . 1 0 0 2 9 . 8 6 8 8 . 1 lax. 1 2 1 6 3 . 1 5 6 3 8 .

1 1 4 5 8 . 1 4 5 1 4 . 16042. 2 0 5 1 0 . 1 2 0 0 0 . 1 5 2 0 0 . 16800. 21600.

3 7 3 6 . 4 1 3 0 . 4 3 3 6 . 4 7 1 4 . 6 6 3 3 . 8 4 0 1 . 9 2 8 6 . 1 1 9 3 9 .

5 7 3 0 . 6 5 4 2 . 6 8 6 5 . 74%. 7 8 7 6 . 9 9 7 7 . 1 1 0 2 7 . 1 4 1 7 7 .

7 6 3 5 . 9 0 1 1 . 9626. 1 1 1 7 7 . 9 0 5 5 . 1 1 4 6 9 . 1 2 6 7 6 . 1 6 2 9 8 .

2 9 3 1 . 3 2 5 2 3 3 5 3 . 3 4 2 9 . 5 9 7 7 . 7 5 7 1 . 8 3 6 8 . 1 0 7 5 9 .

3 6 1 5 . 4029. 4 2 2 2 . 4 5 6 2 . 6 5 5 7 . 8 3 0 6 . 9 1 8 0 . 1 1 8 0 3 .

S T D . A P I / P E T R O R P ?G-ENGL 1998 - 0 7 3 2 2 9 0 0609679 679 m

REWMMENDED PIWTICE FOR DRIU STEM DESIGN AND OPERATING L#m.s 9

Table 6-Used Drill Pipe Torsional and Tensile Data API Class 2

(1)

S i zeO Dill.

(2)N e w W e i g h tNominal WfThadsand

coopliIlgslb/ft

(3)

E75

(4) (5)

QTorsionalY~eld StrengthBased on Uniform Wear, A-lb

x95 G 1 0 5

(6)

s135

(7) (8) (9) (10)

Smile Data Based on Uniform WearLoad at Minimum Yield Strength, lb

E75 x95 G 1 0 5 5 1 3 5

4

23/B 4 . 8 5

6 . 6 5

2% 6 . 8 5

1 0 . 4 0

3v2 9 . 5 0

1 3 . 3 0

1 5 . 5 0

1 1 . 8 5

1 4 . 0 0

1 5 . 7 0

4v2 1 3 . 7 5

1 6 . 6 0

2 0 . 0 0

2 2 . 8 2

1 6 . 2 5

1 9 . 5 0

25.60

5v2 1 9 . 2 0

2 1 . 9 0

2 4 . 7 0

f% 2 5 . 2 0

2 7 . 7 0

3 2 2 4 . 4 0 8 3 . 4 5 1 3 . 5802s 6 6 6 8 6 . 84449. 93360.

4 1 3 0 . 5 2 3 2 . 5 7 8 2 . 7 4 3 4 . !m71. 1 1 7 6 3 6 . 1 3 0 0 1 9 .

5 4 8 4 . 6946 7 6 7 7 . 9 8 7 1 . 9 2 8 0 1 . 1 1 7 5 4 9 . 1 2 9 9 2 2 .

7 5 9 1 . 9615. 1 0 6 2 7 . 1 3 6 6 3 . 1 4 3 5 5 7 . 1 8 1 8 3 9 . 2 0 0 9 8 0 .

9612. 1 2 1 7 6 . 1 3 4 5 7 . 1 7 3 0 2 . 1 3 2 7 9 3 . 1 6 8 2 0 4 . 1 8 5 9 1 0 .

1 2 3 6 5 . 1 5 6 6 3 . 1 7 3 1 2 . 2 2 2 5 8 . 1 8 3 3 9 8 . 2 3 2 3 0 4 . 2 5 6 7 5 7 .

1 3 8 2 8 . 1 7 5 1 5 . 1 9 3 5 9 . 2 4 8 9 0 . 215%7. 2 7 3 5 5 8 . 3 0 2 3 5 4 .

13281. 1 6 8 2 3 . 1 8 5 9 4 . 2 3 9 0 7 . 1 5 8 1 3 2 . 2 0 0 3 0 1 . 2 2 1 3 8 5 .

15738. 1 9 9 3 5 . 2 2 0 3 4 . 2 8 3 2 9 . 1 9 4 3 6 3 . 2 4 6 1 9 3 . 2 7 2 1 0 8 .

17315. 2 1 9 3 2 . 2 4 2 4 1 . 3 1 1 6 6 . 2 1 9 7 3 8 . 2 7 8 3 3 5 . 3 0 7 6 3 3 .

17715. 2 2 4 3 9 . 2 4 8 0 1 . 3 1 8 8 7 . 1 8 5 3 8 9 . 2 3 4 8 2 7 . 2 5 9 5 4 5 .

20908. 2 6 4 8 3 . 2 9 2 7 1 . 3 7 6 3 4 . 2 2 5 7 7 1 . 2 8 5 9 7 7 . 3 1 6 0 8 0 .

2 4 7 4 7 . 3 1 3 4 6 . 3 4 6 4 5 . 4 4 5 4 4 . 2 7 9 5 0 2 . 3 5 4 0 3 5 . 3 9 1 3 0 2 .

2 7 1 6 1 . 3 4 4 0 4 . 3 8 0 2 6 . 4 8 8 9 0 . 3 1 7 4 9 7 . 4 0 2 1 6 3 . 4444%.

23974. 3 0 3 6 8 . 3 3 5 6 4 . 43154. 2 2 5 3 1 6 . 2 8 5 4 0 0 . 3 1 5 4 4 2 .

2 7 9 7 6 . 3 5 4 3 6 . 3 9 1 6 6 . 5 0 3 5 6 . 2 7 0 4 3 2 . 3 4 2 5 4 8 . 3 7 8 6 0 5 .

3 4 9 4 7 . 4 4 2 6 7 . 4 8 9 2 6 . 6 2 9 0 5 . 3 5 8 7 3 1 . 4 5 4 3 9 2 . 5 0 2 2 2 3 .

3 0 2 0 8 . 3 8 2 6 3 . 4 2 2 9 1 . 5 4 3 7 4 . 2 5 5 9 5 4 . 3 2 4 2 0 8 . 3 5 8 3 3 5 .

3 4 5 8 2 . 4 3 8 0 4 . 4 8 4 1 4 . 6 2 2 4 7 . 2 9 9 5 3 3 . 3 7 9 4 0 9 . 4 1 9 3 4 6 .

3 8 3 8 3 . 4 8 6 1 9 . 5 3 7 3 7 . 6 9 0 9 0 . 3 3 9 5 3 3 . 4 3 0 0 7 6 . 4 7 5 3 4 7 .

4 8 4 9 7 . 6 1 4 3 0 . 6 7 8 9 6 . 8 7 2 9 5 . 3 3 7 2 3 6 . 4 2 7 1 6 6 . 4 7 2 1 3 1 .

5 2 3 0 8 . 6 6 2 5 7 . 7 3 2 3 1 . 9 4 1 5 5 . 3 6 7 4 5 5 . 4 6 5 4 4 3 . 5 14437.

‘Based on the shear sfnmgth equal to 57.7 percent of minimum yieid strength.%r.sional data based on 30 percent unifom wear on outside diameter and tensile data based on 30 pacent uniform wear on outside diametet.

1 2 0 0 3 5 .

1 6 7 1 6 7 .

1 6 7 0 4 3 .

2 5 8 4 0 3 .

2 3 9 0 2 7 .

3 3 0 1 1 6 .

3 8 8 7 4 1 .

2 8 4 6 3 8 .

3 4 9 8 5 2 .

3 9 5 5 2 8 .

3 3 3 7 0 1 .

4 0 6 3 8 8 .

5 0 3 1 0 3 .

5 7 1 4 9 5 . I

4 0 5 5 6 8 .

4 8 6 7 7 8 .

6 4 5 7 1 5 .

4 6 0 7 1 7 .

5 3 9 1 6 0 .

611160.

607026.

6 6 1 4 1 9 .

S T D . A P I / P E T R O R P 7G-ENGL 1998 - 0732290 ObO=lbtlO 39b m

10 API RECOMMENDED PRACTIICE 76

Table 7-Used Drill Pipe Collapse and Internal Pressure Data API Class 2

(1) (2) (3) (4) (5) (6) 0 (8) (9) (10)

S i zeO Din.

N o m i n a l W e i g h tl’keadsand~uplinss

lb/R B75

‘cog pressureBasedmMbimumValue.s,psi

x95 G1t-K s 1 3 . 5 Em

‘M . . Internal Yield Pressure. .atMmlmllm Y i e l d S t r e n g t h , p s ix95 G 1 0 5 s135

4

411,

234 4 . 8 5

6 . 6 5

2va 6 . 8 5

1 0 . 4 0

3’/* 9 . 5 0

1 3 . 3 0

1 5 . 5 0

1 1 . 8 5

1 4 . 0 0

1 5 . 7 0

1 3 . 7 5

1 6 . 6 0

2 0 . 0 0

2 2 . 8 2

1 6 2 5

1 9 . 5 0

2 5 . 6 0

511, 19m

2 1 . 9 0

2 4 . 7 0

6% 2 5 . 2 0

2 7 . 7 0

6 8 5 2 . 7 9 9 6 . 8 4 9 1 . 9664. 8400. 1 0 6 4 0 . 1 1 7 6 0 . 1 5 1 2 0 .

1 2 1 3 8 . 1 5 3 7 5 . 1 6 9 9 3 . 2 1 8 4 9 . 1 2 3 7 9 . 1 5 6 8 0 . 1 7 3 3 1 . 2 2 2 8 2 .

6 0 5 5 . 6 9 6 3 . 7 3 3 5 . 8 1 2 3 . 7 9 2 5 . 1 0 0 3 9 . 1 1 0 9 5 . 1 4 2 6 5 .

1 2 9 3 8 . 1 6 3 8 8 . 1 8 1 1 3 . 2 3 2 8 8 . 1 3 2 2 1 . 1 6 7 4 6 . 1 8 5 0 9 . 2 3 7 9 8 .

5 5 4 4 . 6 3 0 1 . 65%. 7 1 3 7 . 7 6 2 0 . 9652. 1 0 6 6 8 . 1 3 7 1 6 .

1 0 8 5 8 . 1 3 7 5 3 . 1 5 0 4 2 1 8 3 % . 11040. 1 3 9 8 4 . 1 5 4 5 6 . 1 9 8 7 2 .

1 3 1 7 4 . 1 6 6 8 6 . 1 8 4 4 3 . 2 3 7 1 2 . 1 3 4 7 0 . 1 7 0 6 2 . 1 8 8 5 8 . 2 4 2 4 6 .

4 3 1 1 . 4 7 0 2 . 4 8 7 6 . 5 4 3 6 . 6 8 7 8 . 8 7 1 2 . %29. 1 2 3 8 0 .

7 2 9 5 . 8 5 7 0 . 9 1 3 4 . 10520. 8 6 6 3 . 1 0 9 7 3 . 1 2 1 2 8 . 1 5 5 9 3 .

9 5 3 1 . 1 1 4 6 8 . 1 2 3 7 4 . 14840. 9 9 7 5 . 1 2 6 3 5 . 13965. 1 7 9 5 5 .

3 3 9 7 . 3 8 4 5 . 4 0 1 6 . 4 2 8 7 . 6 3 2 3 . 8 0 1 0 . 8 8 5 3 . 1 1 3 8 2 .

5 9 5 1 . 6 8 2 8 . 7 1 8 5 . 7 9 2 3 . 7 8 6 3 . 9 9 6 0 . 11009. 1 4 1 5 4 .

%31. 1 1 5 9 8 . 1 2 5 2 0 . 1 5 0 3 3 . 1 0 0 3 3 . 1 2 7 0 9 . 1 4 0 4 7 . 1 8 0 6 0 .

1 1 4 5 8 . 145 14. 1 6 0 4 2 . 2 0 5 1 0 . 1 1 6 6 7 . 1 4 7 7 9 . 1 6 3 3 3 . 21m.

3 2 7 5 . 36%. 3 8 5 0 . 4 0 6 5 . 6 2 1 6 . 7 8 7 4 . 8 7 0 2 . 1 1 1 8 9 .

5 5 1 4 . 6 2 6 2 . 6 5 5 2 . 7 0 7 9 . 7602. 9629. 1 0 6 4 3 . 1 3 6 8 4 .

1 0 3 3 8 . 1 2 6 4 0 . 1 3 6 8 5 . 1 6 5 8 7 . 10500. 13300. 1 4 7 0 0 . 18900.

2 8 3 5 . 3 1 2 8 . 3 2 1 5 . 3 2 6 5 . 5 8 0 4 . 7 3 5 1 . 8 1 2 5 . 10447.

4 3 3 4 . 4 7 3 3 . 4 8 9 9 . 5 4 6 5 . 6 8 9 2 . 8 7 3 0 . 9 6 4 9 . 1 2 4 0 5 .

60543. 6 9 5 7 . 7 3 2 9 . 8 1 1 5 . 7 9 2 3 . 1 0 0 3 5 . 1 1 0 9 2 . 1 4 2 6 1 .

2 2 2 7 . 2 3 4 3 . 2 3 4 6 . 2 3 4 6 . 5 2 3 0 . 6 6 2 5 . 7 3 2 2 . 9 4 1 4 .

2 7 6 5 . 3 0 3 7 . 3 1 1 3 . 3 1 4 8 . 5 7 3 7 . 7 2 6 7 . 8 0 3 2 . 1 0 3 2 7 .

STD=API/PETRO R P ?G-ENGL L=l=lB - 0 7 3 2 2 9 0 0609683 2 2 2 m

REWMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPEIumNG Lltms 1 1

Table 8-Mechanical Properties of New Tool Joints andNew Grade E75 Drill Pipe

(1) (2) (3) (4) C-4 (6) 0 (8) (9) (10) WI (12)

DIillPipeData Tool Joint Data Tensile Yield, lb Torsional Ylelcl, &lb

Nominal Nominal Appim. Driftsize Weight W e i g h t ’ Type OD ID Diamee TOO1 Toolln. lbtft 1Wft upset conll. in. in. in pipe3 JOid pi@ JOid

234 4.85

6.65

2’/8 6.85

10.40

3’1, 9.50

3v2 13.30

15.50

4 11.85

14.00

5.26 N NW4.95 N OH

5.05 N SLH90

5.15 EU w o

6.99 EU NC=@7

6.89 N OH

6.71 Iu PAC

6.78 N SLID0

7.50 N NC310

6.93 N OH

7.05 N SLH90

7.31 N w o

10.87 N NCU(IF)

10.59 N OH

10.27 lu PAC

10.59 N SL‘H90

11.19 Ku XH

10.35 Ku NC26(W

10.58 N NC380

9.84 EU OH

9.99 EU SLH90

10.14 N w o

14.37

13.93

13.75

13.40

13.91

16.54

N H9Q

N NC380

EU OH

Ju NC31(SH)

EU XH

13.00

13.52

12.10

12.91

N

lu

N

N

N

lu

l u

N

NC380

H90

NC46CIF)

OH

w o

15.04

15.43

15.85

N-

H90

NC4WO

1.625 97817. 313681. 4763. 6875-b

1.807 97817. 206416. 4763. 4521-p

1.850 97817. 202670. 4763. 5129.p

1.8W 97817. 205369. 4763. 4311.p

1.625 138214. 313681. 6250. 6875.b

1.625 138214. 294620. 6250. 6484.b

1.250 138214. 238504. 6250. 4688-P

1.670 138214. 202850. 6250. 5129.p

2.000 135902. 447130. 8083. 12053.p

2.253 135902. 223937. 8083. 5585.P

2.2% 135902. 260783. 8083. 762.8.~

2.253 135902. 289264. 8083. 7197.p

1.963 214344. 447130. 11554. 12053 .p

1.963 214344. 345566. 11554. 8814.P

1.375 214344. 272938. 11554. 5730.P

2.006 214344. 382765. 11554. 11288.~

1.750 214344. 505054. 11554. 13282.~

1.625 214344. 313681. 11554. 6875.B

2563 194264. 587308. 14146.

2.804 194264. 392071. 14146.

2.847 194264. 366705. 14146.

2.804 194264. 419797. 14146.

2.619 271569. 664050. 18551.

2.457 271569. 587308. 18551.

2.414 271569. 559582. 18551.

2.000 271569. 447130. 18551.

2.313 271569. 570939. 18551.

18107.~

11870.~

12650.~

12878.~

23847.~

18107.~

17305.p

11869.P

17493.p

2.414 322775. 649158. 20326.p

2688 230755. 913708.

3.125 230755. 901164.

3.287 230755. 621357.

3.313 230755. 782987.

35374.p

33625.~

21976.~

28809.~

2.688 285359. 711611.

2.688 285359. 913708.

3.125 285359. 901164.

21086.

19474.

19474.

19474.

19474.

23288.

23288.

23288.

23487.p

35374.p

33625.~

(Table wntinued on next page.)

S T D . A P I / P E T R O R P 7G-ENGL 1998 - 0732290 Ob07b82 Lb9 -

12 API RECOMMENDED PWWIJCE 76

Table 8-Mechanical Properties of New Tool Joints andNew Grade E75 Drill Pipe (Continued)

(1) (2) (3) (4) 0 (6) 0 (8) (9) (10) (11) (12)MechanicalPrupmies

DIillPipeDslta TbOlJoilltData Tensile Yield, Ib Tlmbnal Y i e l d , A - l b

Nominal Nominal Approx. Dlitls i i Wtigllt Weight1 Qpe O D ID DiaIm& T o o l lb01i n . lwft lwft upset cmm. ill. iu i n . pipe3 JOiXll? fie Joint6

1 4 . 0 0

1 5 . 7 0

1 3 . 7 5

16.60

1 5 . 0 2

14.3s

1 6 . 8 0

1 7 . 0 9

1 7 . 5 4

1 5 . 2 3

1 5 . 3 6

1 4 . 0 4

1 4 . 7 7

1 8 . 1 4

1 7 . 9 2

17.9s

1 7 . 0 7

1 6 . 7 9

1 8 . 3 7

21.64

21.64

2159

22.09

2 4 . 1 1

24.56

22.28

20.85

28.27

26.85

23.78

26.30

27.28

29.06

Eu

Iu

KJ

lu

Eu

lu

ELJ

ElJ

Eu

IEU

IEU

Eu

Eu

IEU

JEU

IEXJ

JEU

Eu

IEU

Eu

IEU

mu

lEu

lEu

IEU

lEu

5u

lEu

lEu

O H

S H

NCWW

H90

NC-

H90

N-00

O H

w o

PI-I

H90

N-J@?

O H

NC38(SH)

N-

PH

l-m

NC%W

NCWXW

NCWW

N-

Sip Fw

N-0

sv2 PH

N-W=)

PI-I

FH

F H

F H

3.125 285359. 759875. 23288. 27289.~

2.438 285359. 512O35. 23288. 1s 17O.P

2.563

2.688

3.095

3 . 1 2 5

3.625

3.770

3.7So

2.875

3.125

3.625

3.625

2.563

3.125

2.875

2.875

3.452

2.875

3 2 4 1 1 8 .

324118.

324118.

270034.

270034.

270034.

270034.

330558.

330558.

330558.

330558.

330.558.

330558.

776406.

913708.

901164.

938403.

939096.

554844.849266.

25673.~

35374.p

33625.~

976156.

938403.

939096.

713979.

587308.

901164.

3.452

2.875

3.625

3.625

3.37s

3.37s

3.875

3.875

4.87s

4.87s

412358. 976156.

412358. 1085665.

412358. 1 0 2 5 9 8 0 .

412358. 1048426.

471239. 1 0 2 5 9 8 0 .

471239. 104.8426.

39559s. 1 4 4 8 4 0 7 .

39559s. 93909s.

530144. 1619231.

530144. 1Kl992O.

437116. 1265802.

497222. 1265802.

489464. 1 4 4 7 6 9 7 .

534198. 1 4 4 7 6 9 7 .

25810.

25810.

25810.

25907.

25907.

25907.

25907.

30807.

30807.

30807.

30807.

30807.

30807.

36901.

36901.

36901.

36901.

40912.

40912.

41167.

41167.

52257.

52257.

mm

56574.

7osm

76295.

38925.~

37676.~

20939.p

336Sl.p

34780.~

38925.~

37676.~

27243.~

18346.P

3 3 9 9 3 . p

3478O.p

45152.~

41235.~

39659.p

41235.~

3%59.p

60338.b

37676.~

60338.b

44673.p

S604s.p

5604S.p

73620.p

73620.p

STD.API/PETRO R P 7G-ENGL L998 - 0 7 3 2 2 9 0 0609683 OT5 -

RECXMMENDED PRACXICE FOR DRIU S-EM DESIGN AND OPERATING LIMITS 13

Table &Mechanical Properties of New Tool Joints and New High Strength Drill Pipe

(1) (2) (3)

DlillPi~Data

(4) (9 (6) 0 (8) (9) (10) (11) (12)MecbauiealPmperties

Tool Joint Data Tensile Yield, lb Torsional Yield, &-lb

Nominal Nominal Approx. DriftSize Weight Weight’ OD ID Diameter? Tool Tool

111. ltdft 1WtI Typeupset Cmlu in. in. in pipe’ Joint! pipe’ Joid

15.50

4 14.00

2V8 6.65

6.65

2’18 10.40

10.40

10.40

3=/z 13.30

13.30

13.30

15.50

15.50

14.00

14.00

15.70

15.70

15.70

4=i2 16.60

4’1, 16.60

16.60

7.11 EU-x956.99 EU-X95

7.11 EU-GlOS6.99 EU-GlOS

11.09 EUk9510.95 EU-X95

11.09 EU-GlOS10.95 EU-GlOS

11.55 m-s13511.26 EU-S135

14.60 EU-x9514.62 EU-X9514.06 EU-X9.5

14.71 EUG10514.06 EU-GlO.5

14.92 EU-S13514.65 EU-s13515.13 EU-S135

16.82 El-Lx95

17.03 EU-GlOS16.97 EU-GlOS

17.57 EU-S135

15.34 IU-x9515.63 IU-x9516.19 EU-X95

15.91 KJ-GlOS15.63 IU-GlOS16.19 EU-G 105

16.19 lU-s13515.63 N-S13516.42 EU-S13.5

17.52 N-X9517.23 N-X9517.80 EU-X95

17.52 N-G10517.23 N-G10517.80 ElJ-GlO5

18.02 EU-s135

la.33 IEU-x9518.11 IEU-x9518.36 EU-X95la.79 IEwx95

la.33 IFU-G10518.33 IJZU-G10518.36 m-G10518.79 lEU-G105

19.19 IEU-SlU

NC260SLH90

NCWWSLH90

NC310SLH90

NC31iJF)SLH90

NC310SLH90

H90NC380

SLH90

NC380SLHW

NC380SLH90

NCM4FH-l

NC38gFq

NC38(F)NC40(4FH)

NC400

NC40H90

NC46(W

NCW-0H90

NCWQ

NC400H90

NCWW

N’=WWH90

NC4W.V

NC4W-WH90

NCWW

NC460

FHH90

N-W?NCWXI-0

PHH90

N-0

NC460

Fw

1.6251.670

1.6251.670

1.8751.875

1.8751.875

1.5001.500

2.6192.4382.438

2.3132.438

2.0002.alO2.313

2.313

2.Oal2.438

2.125

2.5632.6883.125

2.3132.6883.125

1.8752.6882.875

2.3132.6883.125

2.3132.6883.125

2.875

28753.1253.6252.875

2.6253.1253.6252.875

2.375

175072175072.

193500.193500.

271503.271503.

3ooO82.3CKIO82.

385820.385820.

343988.343988.343988.

380197.380197.

488825.488825.488825.

408848.

451885.451885.

580995.

361454.361454.361454.

399502.399502.399502.

513646.513646.513646.

410550.410550.410550.

453765.453765.453765.

583413.

418707.418707.418707.418707.

462781.462781.462781.462781.

595cm4.

313681. 7917.270223. 7917.

313681. 8751.270223. 8751.

495726. 14635.443971. 1463s.

495726. 16176.443971. 16176.

623844. 20798.572089. 20798.

6640ms 23498.649158. 23498.596066. 23498.

708063. 259725960&s. 25972.

842440. 33392.789348. 33392.897161. 33392.

708063. 26708.

842440. 29520.838257. 29520.

979996. 37954.

7764M. 29498.913708. 29498.901164. 29498.

897161. 32603.913708. 32603.901164. 32603.

1080135. 41918.913708. 41918.

1048426. 41918.

897161. 32692.913708. 32692.901164. 32692.

897161. 36134.913708. 36134.901164. 36134.

1048426. 46458.

976156. 39m2.938403. 39022.939095. 39022.

1048426. 39022.

976156. 43130.1085665. 43130.939095. 43130.

1048426. 43130.

1235337. 554.53.

6875.b6884.p

6875.b6884.P

13389.p13218.~

13389.~13218.~

17170.p17213.~

23833.p20326.p20879.p

22213.pma79.p

26515.P2ma.p29930.p

22213.~

26515.p27760.~

32943.~

25673.~35374.p3362.5.~

30114.p35374.p33625.~

36363.~35374.p39229.~

30114.p35374.p33625.~

30114.p35374.p33625.~

392.29.~

347a0.p38925.p37676.~3%59.p

347a0.p45152-p37676-p39659-p

44769-p

(Table continued on next page.)

S T D . A P I / P E T R O R P ‘?G-ENGL I,998 - 0 7 3 2 2 9 0 0609684 T3L m

14 API RECOMMENDED PWXICE 76

Table g-Mechanical Properties of New Tool Joints and New High Strength Drill Pipe (Continued)

(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12)Me&anicalPxqedes

DriUPipeData lbolJointData Tensile Yield, lb Torsional Yield, ft-lb

NominalNominal &pm. Dliesize Wtigllt weight OD ID Diame& TOO1 Tool

111. Wft lb/e TyPeupset corm in. in. in pipe3 Joint’ pipe3 Joints

4’1, 16.60 18.33 IEU-s135 H90 3 2.875 595004. 1085665. 55453. 45152.~

20.00

20.00

20.00

22.82

22.82

22.82

19.50

19.50

19.50

25.60

25.60

25.60

21.90

21.90

21.9024.70

24.7024.70

25.2025.2025.20

27.70n.70n.70

18.6219.00

22.3921.7822.0822.67

22.3922.0022.0822.86

23.0323.03

25.1324.2424.77

24.7224.96

25.41

22.6221.9321.45

226222.1521.93

23.4822.61

28.5927.87

29.1628.3229.43

24.5324.80

25.38

26.5027.85

27.85n.77

27.1528.2029.63

30.1130.1131.54

EU-s135IEU-s135

IEU-X95m-X95EU-X95m&x95

IEWG105IEU-G105E&G105IEU-(3105

Bus135IEU-s135

mu-x95Eu-x95IFUX95

EU-GlO5IEU-G105

EU-s135

m-X95mu-x95lEu-x95

IEU-G105IBU-GlO5IEU-G105

IEU-s135IEU-s135

lEu-x95Eu-x95

IEU-GlO5IEU-GlO5IEU-sl35

lEWX95IETJX95

IEU-GlO5

IEU-sl35lEU-X95

mJ-GlO5IEU-sl35

EU-X95IEU-GlO5IEU-sl35

IEXJ-x95IFuGm-J-s135

3.3752.625

2.3753.1253.3752.625

2.3752.8753.3752.375

2.8752.125

2.1253.3752.625

3.1252.375

2.625

3.6253.1253.375

3.6252.8753.125

3.3752.625

3.3752.875

3.3752.6253.125

3.6253.125

3.375

2.8753.375

3.3752.875

4.8754.6254.125

4.6254.6254.125

595004.595004.

522320.522320.522320.522320.

577301.577301.577301.577301.

742244.742244.

596903.596903.596903.

659735.659735.

848230.

501087.501087.501087.

553833.553833.553833.

712070.712070.

671515.671515.

742201.742201.954259.

553681.553681.

611%3.

786309.629814.

696111.894999.

619988.685250.a8 1035.

676651.747250.961556.

1109920.1183908.

1235337.938403.

1109920.1183908.

1235337.1085665.1109920.13076Oa.

1416225.1419527.

1347256.1109920.1183908.

1268%3.13076oa.

1551706.

14WW7.1176265.1109920.

1448407.1323527.1268963.

1619231.1551706.

1619231.1416225.

1619231.1551706.1778274.

1448407.1268877.

1619231.

1925536.1619231.

1619231.1925536.

1448416.1678145.2102260.

1678145.1678145.2102260.

55453.55453.

46741.46741.46741.46741.

51661.51661.51661.51661.

66421.66421.

51821.51821.51821.

57276.57276.

73641.

52144.52144.52144.

57633.57633.57633.

74100.74100.

66192.66192.

73159.73 159.94062.

64233.64233.

70994.

91278.71fxio.

79204.101833.

89402.98812.127044.

96640.106813.137330.

44673.p44871.p

44265.~38925.~44673.p44871.p

44265.~45152.~44673.p4%3o.p

57800.p53936.p

48912.p44673.p44871.p

5 1447.p4%3O.p

63406.~

60338.b51807.p44673.p

60338.b58398.~5 1447.p

72627.~63406.~

60338.b56984.b

72627.p634&b76156.b

60338.b59091.p

72627-P

87341.p72627.~

72627.p87341.p

73661.p86237.~

109226.p

86237.~86237.~

109226.P

STD.API/PETRO R P ? G - E N G L 1978 - 0132270 ObO=lb85 978 m

RECOMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING LIMITS 15

Table lO-Recommended Minimum OD* and Make-up Torque of Weld-on Type Tool JointsBased on Torsional Strength of Box and Drill Pipe

(1) (2) (3) (4) (5) (6) 67 (8) (9) (10) (11) (12) (13)

Premiumclass class 2

DrillPipe New Tool Joint DataMin. Min. Box Iblake-upOD Shoulder Torque for

Nominal Nomsize Weight -Upsetin. lblfi andGrade COIUL

NeW New --up To01 with Eccen- Min. ODOD ID Torsue6 Joint tric Wear Tool Jointin. ln. &lb in. in. ft-lb

Mi l l . Min.Box Make-upOD Sboulde-r Torque for

To01 withEuxm- Min.ODJoint i&Wear Tool Joint

m. m. ft-lb

231s

231s

2318

231,

2’Js

2’18

2718

2’JB

27/,

3’J2

3’Jz

3’12

3’12

3’J2

3’1,

3’Jz

3’12

4

4.85 W-E754.85 EU-MS4.85 m-E75

4.85 EU-E75

6.65 WE756.65 EVE756.65 EU-E756.65 EU-E75

6.65 E U - X 9 5

6.65 EU-G105

6.85 EVE756.85 EU-E75

6.85 EVE756.85 EU-E75

10.40 EU-E7510.40 IU-E7510.40 lU-E7510.40 EVE7510.40 EU-E7510.40 IU-E75

10.40 EU-x9510.40 E&x95

10.40 EU-G105

10.40 EU-s135

9.50 EVE759.50 EU-E759.50 EU-E759.50 BU-E75

13.30 EU-E7513.30 lU-E7513.30 EU-EV513.30 EVE7513.30 E&x9513.30 EU-x9513.30 EU-X95

13.30 EU-G105

13.30 EU-S13513.30 EU-s135

15.50 BU-E75

15.50 BU-x95

15.50 EU-G10515.50 BUG105

15.50 Bus135

I l . 8 5 EVE7511.85 EU-E75

N C 2 6W.O.

23/s OHLW2’J8 SGH90

23J, PACNC26

23Js SL-HW2V, OHSW

N C 2 6

NC26

NC312’J& w o

2’& OHLW2V8 SLH90

NC312’/8 XH

N C 2 62’/, OHSW2’JB SL-H90

27JB PACT=

NC312Vs SGH902

NC31

NC31

NC38N C 3 8

3’J2 OHLW3’/, SLH90

N C 3 8NC31z

3’1, OHSW3’J2 H90N C 3 8

3’/, SL-HW3’12 H90

N C 3 8

YJ8

VJ*3’1,

3’1,

271933183’1,

3’1,

VJ8

33J*

4’1,4’J,

PJ&3vg

4’1,4’1,

33/@3’/8371,

3’1,

4’1,3’19

4’1,

43JB

43/,43l.$

43/44’/8

43,‘4’1843/4

5’J4

54’J8

5’1,

5

N C 4 0 918N C 3 8 5

N C 3 8 5

N C 3 8 5

N C 3 8 5NC40 5’&

N C 4 0 5’J*

NC46 6

4 w o 914

4,125 B2,586 P2713 P3,074 P

2813 P4,125 B3,074 P3,891 B

4,125 B

4,125 B

7,122 P4,318 P

3,351 P4,575 P

7,122 P7,969 P4,125 B5,270 P6,773 P3,439 P

7,918 P6,773 P

7,918 P

10,167 P

7,688 P10,864 P7218 P7,584 P

10,864 P7,122 P

10,387 P14,300 P12,196 P11,137 P14,300 P

13,328 P

17,958 P15,909 P

121% P

13,328 P

15,909 P16,656 P

19,766 P

20.175 P17385 P

3’J,

3'JM3

23’la

2=,=

33Jl,

3’Jz

3’J1,

3’14

3’132

3”J35J*‘6

3’1,3’1,

3’3,FIE3319

3’91P3’9,

31,*=

329/,

3”J 16

3"Jl,

4'Jl,

4’12

44’3,

417;;4’91

43,s=4=/8

42’1a

5

4”J’,

4’71P

421,32

423/p

415J 16

53J3/,,

1,9451,9941,830

19%

z455

z4672549

z324

3,005

3,279

3,1543,21632973.397

4,5974,357

4,12542734,529

3,439

5,7265,702

6,110

7,694

5,7735,773

5,3405,521

72746,8937,278

7,0648,822

8,7428,826

9,879

12,56912,614

7,785

9,879

10,95711.363

14,419

7,8437,843

331,

3’lz231J 37.215J 1 6

2BJa

3Yz23’Ja

3’132

3’JQ

3’J,

32’1323’913’1,;

3'Jl,

3314

3=J323’Y

3s;3’lJa

3’J,

3nJp

35/8

3’/8

4

4’1, 324”J

41,,=

4=JD

4%315J 16

4”J

4’JzB4”J

451,;

49J1,

4’91a

4”/p4”/p

4’51a

4’9132

4’ls

4”lu

43’131

55&Sl,

1,6891,746lJ891.726

28042,876

w%u=

3,867

3.6643,8393.9413,7703,439

4,9694,915

5,345

6,893

4.797

4,7974,8685,003

638611063996,487

7,7857,647

7,646

8,822

10,76810,957

6,769

8,822

9,348

9,595

11,%3

6,476

6,476

(Table continued on next page.)

STD.API/PETRO R P TG-ENGL I,998 - 0732290 Db09bdb 8 0 4 -

1 6 API REW~IMENDED PFWTICE 7G

Table 1 O-Recommended Minimum OD* and Make-up Torque of Weld-on Type Tool JointsBased on Torsional Strength of Box and Drill Pipe (Continued)

(1) (2) (3) (4) (3 (6) 0) (8) (9) (10) (11) (12) (13)

Drillpipe

Nominal Nomsize weight nvUP=ti n . lb/ft andGrade

Remiumclass c l a s s 2

New Tool Joint DataM i n . MilLBox Make-up Min. MimBox Make-upOD Shoulder Toquefor OD slloulder Torque for

NeW New -up TOO1 with Eccen- Min. OD Tbol with Eccen- Min. ODO D ID Torsue6 J o i n t t ic Wear T o o l J o i n t Joint bit Wear T o o l J o i n t

ComL in. in. fi-lb in. in. i&lb in. i n f&lb

11.85 EU-E7.5 4oHLw 5’14 3fita 13,186 P 5 9fa 7,866 6,593

4

4

4

4

4

4

4

4

4’1,

4’1,

4’12

4’1,

4112

I4’1,

11.85 n&E75

14.00 IU-E7514.00 EU-E7514.00 IU-E7514.00 EU-E7514.00 IU-E75

14.00 IU-x9514.00 Eu-x9514.00 IU-x95

14.00 NJ-G10514.00 EU-GlO514.00 IU-Glo5

14.00 Ems135

15.70 lSLE7515.70 Ew37515.70 IU-E75

15.70 mx9515.70 EU-x9515.70 ILJ-x95

15.70 EU-GlO515.70 IU-Glo5

15.70 IU-s13515.70 EU-Sl35

16.60 IEU-Ei’516.60 IEU-E7516.60 IEU-E7516.60 EU-E7516.60 IEU-E75

16.60 IEU-X9516.60 lEU-X9516.60 EU-X9516.60 lEU-X95

16.60 lEUGlO516.60 IEUGlO516.60 El&G10516.60 IEuGlO5

16.60 IEU-S13516.60 ELLS135

20.00 IEU-B7520.00 m-E7520.00 EU-E7520.00 IEU-E75

20.00 IEU-x9520.00 IBU-x9524lBo Eu-x9520.00 IFmx95

4H90

NC40NC464sw

4 O H S W4H90

NC40NC464H90

NC40NC464H90

NC46

NC40NC464H90

NC40NC464H90

NC464H90

NC46NC46

4’1, PHNC46

4’12 OHSWNC50

4’lz H-90

4’12 PHNC46NC50

4’f, H-90

4’12 PHNC46NC50

4’/* H-90

NC46NC50

4’1, PHNC46NC50

4’12 H-90

4’12 PHNC46NC50

4’1, H-90

5’12

5’f46

4%5’12

5’12

5’1,6511,

5’1,65’/,

6

5’f465’1,

5’f265’fz

65’f,

66

66’1,

@fs6

66’l.

@fe6

6’1,

6%66’1,

6%6

6

@I*@fs6

21224P

14,092 P20,175 P

9,102 P16,320 P21,224 P

15,404 P20.175 P21224 P

18,068 P20,175 P21224 P

23,538 P

15,404 P20,175 P21224 P

18,068 P23,538 P21224 P

2 3 5 3 8 P21224 P

26,982 B25,118 P

20,868 P2 0 . 3 % P14346 P22,836 P23,355 P

23,843 P2 0 . 3 % P22,836 P27 ,091 P

23,843 P23,795 P22,836 P27,091 P

S923P27,076 P

20.868 P23,795 P24,993 P27,091 P

26559 P2&9=P27.076 P27,091 P

4718

4’3f’S

s)/,

4 %

51f’,4’5fM

415f’65’185’&

5

5%5

sJ/n

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4’/8

5’f’ET43’1a

5

5%53lz

5’3fz

551a

9’f,

5’1~

5319

5’3f2

%s”ID5’1,P

5’l*

5’1,

PI;

5’51,

Yfl,5’91

5-t:

5’1,

5%6’f’e

5’5lz5’l*5’31165’3&

Yf8

ml5’51m

Pf’6

7 , 6 3 0

9,01792338 , 7 8 29,1318,986

11,36311,36311,065

12,56912,81312&l

15,787

10,1799,9379,673

12,569lZ813K&481

133471 3 , 9 2 2

1 8 . 0 8 318,083

12.12512.+08511,8621139012215

14,94515,03514,92615,441

la911654616,6331W

2 1 9 3 021,017

1423114,28814,08213,815

17,861l&o8317,49717,929

6,%2

7 , 8 7 77 , 8 4 37,8177,8397 , 6 3 0

95959,9379,673

10,76810,64711,065

14S8

8,4448 , 5 3 58 , 3 0 5

1 0 , 7 6 810,64711,065

143114,28814,08214,625

15,66515,78715,7761 5 , 4 4 1

(Table amtimed on next pnge.)

STD.API/PETRO R P i’G-ENGL 1948 - 0?32290 ObCl9b87 7’40 -

RECXMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING L~rim-s 17

Table 1 O-Recommended Minimum CID* and Make-up Torque of Weld-on Type Tool JointsBased on Torsional Strength of Box and Drill Pipe (Continued)

(1) (2) (3)

DrillPipe

Nomina l NomSize Weight QpeUpsetill. lb/e andGrade

(4) (5) (6) (7) (8) (9) (10) (11) (12) (13)

PrcIniumcluss class2

New Tbol Joint Dataluin Min.Box M a k e - u p Min. Min.Box Make-upO D Shoulder l’bquefor OD Shoulder Torque for

NeW N e w --up T o o l w&E&en- Min.OD ‘Ibol with-- Min.ODO D I D Torsue6 Joint tic Wear Tml Joint J o i n t tic Wear T o o l J o i n t

coml. i n . m . f t - l b i n . m. &lb in. i n A-lb

2 0 . 0 0 IEU-GlO5 NC46

2 0 . 0 0 ECU-G105 NC50

20.00 EU-S135 NC50

19.50 IEvE NC50

1 9 . 5 0 IEU-x95 NC50

1 9 . 5 0 IN-x95 5 H - 9 0

1 9 . 5 0 IEU-G105 NC501 9 . 5 0 IFLLG105 5 H - 9 0

1 9 . 5 0 IEU-s135 NC501 9 . 5 0 m-s135 5’1, PH

25.m IEU-E75 NC502 5 . 6 0 IEU-E75 5’12 PH

2 5 . 6 0 IEU-x95 NC50

2 5 . 6 0 IEKJ-x95 5’1, PH

2 5 . 6 0 IEU-G105 NC50

2 5 . 6 0 IEU-Glo5 S’l, ml

2 5 . 6 0 IFXJ-s135 5’1, PH

2 1 . 9 0 EU-I375 5’1, PH

2 1 . 9 0 IEU-x95 5’12 Fu

2 1 . 9 0 DXJ-x95 5’12 H-90

2 1 . 9 0 E&G105 5’12 PH

2 1 . 9 0 IEU-s135 5’12 PI-l

2 4 . 7 0 IEU-E75 5’1, PH

2 4 . 7 0 IFXJ-x95 5’/* PH

2 4 . 7 0 IEU-GlO5 5’1, PH

2 4 . 7 0 IEU-s 135 St2 PH

2 5 . 2 0 IEu-E75 @I8 PHIEU-x95 65/8 PH

IEU-G105 678 PHIEU-s135 ‘?I* F-H

2 7 . 7 0 IEU-E75 @I8 PH

IEU-x95 6q, PHIEU-G105 6-Y~ PH

IEU-s135 6v* PH

2 9 , 7 7 8 P2 7 , 0 7 6 P

3 6 , 3 9 8 P

2 2 , 8 3 6 P

2 7 , 0 7 6 P3 1 , 0 8 4 P

3 1 , 0 2 5 P35,039 P

3 8 , 0 4 4 P4 3 , 4 9 0 P

2 7 , 0 7 6 P3 7 , 7 4 2 B

3 4 , 6 8 0 P3 7 , 7 4 2 B

3 8 , 0 4 4 P4 3 , 4 9 0 P

4 7 , 2 3 0 B

3 3 5 6 0 P

3 7 , 7 4 2 B3 5 , 4 5 4 P

4 3 , 4 9 0 P

5 3 , 3 0 2 P

3 3 , 5 6 0 P

4 3 , 4 9 0 P

4 3 , 4 9 0 P

5z302 P

44,1%P44,1%P5 1 , 7 4 2 P6 5 , 5 3 5 P

44,1%P5 1 , 7 4 2 P5 1 , 7 4 2 P6 5 , 5 3 5 P

1 9 , 6 4 42 0 . 1 2 7

2 5 , 5 6 9

1 5 , 7 7 6

2 0 , 1 2 71 9 , 8 6 2

2 1 . 9 1 42 1 , 7 2 7

2 8 . 3 8 12 8 , 7 3 7

2 0 , 1 2 72 0 , 2 0 5

2 5 , 5 6 92 5 , 4 8 3

2 7 , 4 3 72 7 , 6 4 5

3 5 , 4 4 6

1 9 , 1 7 2

2 4 , 4 1 22 4 , 4 1 4

2 7 , 6 4 5

3 5 , 4 4 6

222942 1 , 6 4 5

2 9 , 8 3 6

3 8 , 9 0 1

2 6 , 8 1 03 5 , 1 3 937,983

2 9 , 5 5 23 7 , 9 8 340,86052714

1 7 , 3 1 11 6 , 6 3 3

21,914

1 4 , 0 8 2

1 7 , 4 9 71 7 , 1 1 6

192441 8 , 9 4 0

2 4 , 6 4 52 4 , 4 1 2

1 7 , 4 9 71 7 , 1 2 7

2 1 , 9 1 4222942 3 , 7 2 82 4 , 4 1 2

3 0 , 9 4 3

1 7 , 1 2 7

212462 1 , 3 4 9

2 3 , 3 5 0

3 0 , 9 4 3

1 9 , 1 7 2

2 3 , 3 5 0

2 6 , 5 6 0

3 3 , 1 8 0

2 4 , 1 0 02 9 , 5 5 23 3 , 7 3 04 2 , 3 1 2

2 5 . 4 5 13 2 , 3 2 93 6 , 5 5 645241

‘The use of outside diameters (OD) smaller than those listed in the table may be acceptable due to special service requirements.Tool joint with dimensions shown has lower torsional yield radio than the 0.80 which is generally used.Qeanmended make-up toque is based on 72.000 psi stress.*in calculation of torsional strengths of tool joints, both new and worn, the bevels of the tool joint shoulders an. disregarded. This thickness measurement shouldbemadeintheplaneofthe~fromtbeLD.ofthecounterboretotheoutsidediameterofthebox,disregardingthe~vels.5Auy tool joint with an outside diameter less than API bevel diameter should be provided with a minimum ‘Ia inch depth x 45 degree bevel on the outside andinside diameter of the box shoulder and outside diameter of the pin shoulder.6p=Pinlim&B=BoxlimiL+Timl joint diameters speciiied am required to retain torsiomd stnzngtb in the tool joint comparable to the torsional strength of the attached drill pipe. These shouldbeadequateforau service. Tool joints with torsional strengths wnsidcrably below that of the drill pip may be adequate for much drilling service.

S T D . A P I / P E T R O R P 7G-ENGL 1998 m 07322=JO ObOqb88 687 m

18 API RECOMMENDED PRACTICE 7G

(1)Mud Density lb&al

8 . 4

Table 11 -Buoyancy Factors

(2)MudDensitylbkuA

6 2 . 8 4

(3)

B u o y a n c y F a c t o r , K b

.8728 . 68 . 8

6 4 . 3 36 5 . 8 3

-869A66

9 . 0 6 7 . 3 2 .8629 2 6 8 . 8 2 3599 . 4 7 0 . 3 2 A569 . 6 7 1 . 8 1 -8539 . 8 7 3 . 3 1 A50

1 0 . 0 7 4 . 8 0 .8471 0 . 2 7 6 . 3 0 3441 0 . 4 7 7 . 8 0 -8411 0 . 6 7 9 . 2 9 X381 0 . 8 8 0 . 7 9 .X35

1 1 . 0 8 2 . 2 9 .8321 1 . 2 8 3 . 7 8 3291 1 . 4 8 5 . 2 8 -8261 1 . 6 8 6 . 7 7 -82311.8 8 8 . 2 7 .820

1 2 . 01221 2 . 41 2 . 612.8

1 3 . 01 3 . 21 3 . 41 3 . 613.8

1 4 . 01 4 . 21 4 . 41 4 . 614.8

1 5 . 01521 5 . 41 5 . 61 5 . 8

1 6 . 01 6 . 21 6 . 41 6 . 61 6 . 8

1 7 . 01 7 . 21 7 . 41 7 . 61 7 . 8

1 8 . 01 8 . 5

1 9 . 01 9 . 5

2 0 . 0

8 9 . 7 7 .8179 1 . 2 6 .8149 2 . 7 6 All9 4 . 2 5 .8079 5 . 7 5 304

9 7 . 2 5 3019 8 . 7 4 .798

1 0 0 . 2 4 .7951 0 1 . 7 4 .7921 0 3 . 2 3 .789

1 0 4 . 7 3 .7861 0 6 . 2 2 .7831 0 7 . 7 2 .7801 0 9 2 2 7771 1 0 . 7 1 774

1 1 2 . 2 1 7711 1 3 . 7 0 .7681 1 5 2 0 .7651 1 6 . 7 0 .7621 1 8 . 1 9 .759

1 1 9 . 6 9 .7561 2 1 . 1 8 .7521 2 2 . 6 8 .7491 2 4 . 1 8 .7461 2 5 . 6 7 .743

1 2 7 . 1 7 .7401 2 8 . 6 6 .7371 3 0 . 1 6 .7341 3 1 . 6 6 .7311 3 3 . 1 5 .728

1 3 4 . 6 5 -7251 3 8 . 3 9 .717

1 4 2 . 1 3 .7101 4 5 . 8 7 .702

1 4 9 . 6 1 594

STD.API/PETRO R P 7G-ENGL 1998 m 0 7 3 2 2 9 0 ObO=lbd=l Sl13 -

REWMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING Lwms 19

Table 124otaty Shouldered Connection Interchange List

Common Name

style s i i

Internal Fhlsh (LFC) 231,”

PillBZW

2.876

Taperill/fL !%ml’

V-O.065

27/,”

31/z”

4”

3.391

4.016

4.834

4$” 5.250

(V-O.038 ml)

v-O.065(V-O.038 md)

v-O.065(V-o.038 rad)

v-O.065(V-O.038 lad)

V-O.065

038 m-l)

sallx?ssorInterchanges With

2T8” Slim HoleN.C. 262

31/2n Slim Hole

N.C. 31*41/2” Slim HoleN.C. 3@

4$” Extra Hole

N.C. 4625” Extra Hole

N.C. 5025’/,” Double Streamline

Full Hole (FIT)

Extra Hole (X.H.) (E.H.)

4

27/s”

3v*-

4’/,”

5”

4.280 4’&” Double Sixamline

NC 402

3.327 3l/,” Double StreamI&

3.812

4.834

5250

v-O.065

(v-o.038 lad)

v-O.065(V-o.038 lad)

v-0.065(WI.038 lad)

V-O.065(V-O.038 rad)

v-O.065(V-O.038 rad)

4” Slim Hole

4Yz” lstemal Flush4” Internal FlushNC 462

4’/z” lntemal FlushN.C. 502

S1t2” Double Streamline

Slim Hole (S.H.) 2’18” 2.876

3’12” 3.391

4” 3.812

4v; 4.016

2Ys” Internal Flush

N.C. 262’/8” Internal Flush

N.C. 3123’/,” Bxtra Hole

4l/*” lstemal Flush3’/,” Internal Flush

N.C. 38=

Double Streamline (DSL) 3l/,”

4’1,”

3.327 27/8” Extra Hole

4.280

5$” 5.250

v-o.065

(VO.038 lad)v-o.065(V-o.038 Iad)

v-o.065(WI.038 m-l)

V-O.065(V-O.038 ml)

v-O.065

(V-o.038 lad)

v-o.065(V-O.038 lad)V-O.065

(V-o.038 l-ad)

4” Full HoleN.C. 402

4’1,” Internal Flush5” Bxtra Hole

N.C. 501

Numbeed Connection (NC.) 26

31

2.876 V-O.038 lad

3.391 v-0.038 l-ad

38 4.016 V-o.038 l-ad

40 4.280 V-O.038 rad

46 4.834

50 5.250

Jktmd Flush (BE) 4’12” 3.812

4

4

4

4

4

4

4

4

4

4

4

4

4

4

4

4

4

4

4

4

4

4

4

4

2

2

2

2

2

2

2

2

2

2

2

2

2

2

2

2

2

2

2

2

2

2

2

2

V-O.038 rad

V-O.038 l-ad

V-O.065

(v-o.038 lad)

2Y8” Internal Flush

2718 1’ slim Hole

Z7/ s ” Internal Flush3y” Slim Hole3’1,” Internal Flush

4’/,” Slim Hole4” Full Hole

4’/,” Double Stmamline4” Internal Flush

4’&” Extra Hole4$” lntemal Flush

5” Extra Hole

4” Slim Hole

3’/,” Bxtca Hole

lConneetions with two thread forms shown may be machined with either thread form witbout affect@ gauging or interchangeability.?Numbered txmmcrions (N.C.) may be machined only with the V-O.038 radius tbmad f-

STD.API/PETRO R P 7G-ENGL I,998 - 0 7 3 2 2 9 0 ObO=lb=lO 2 3 5 -

2 0 API RECXMMENDED PRACTICE 76

Figures l -2+Torsional Strength and Recommended Make-up Torque Curves(All curves based on 120,000 psi minimum yield strength and 60 percent

of minimum yield strength for recommended make-up torque.)

3 . 3 7

%::

mE 3 .12

qbc”

2.87

Tool Joint Pin I.D.

Figure l-NC26 Torsional Yield and Make-up

I

i

Torsional yield strength

I I

8Ae--t--lo--cr!

cv

Tool Joint Pin I.D.

Figure 2-P& Open Hole Torsional Yield and Make-up

STD.API/PETRO R P 7G-ENGL 1199B D 0 7 3 2 2 9 0 ObO=lb=l1 l17l1 -

REWMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERAnNG him 2 1

3.250

%3 -I4ac

3.culO

2.750

Recommended make-up torqueM b

rength

N

Tool Joint Pin I.D.

Figure 3-2V, Wide Open Torsional Yield and Make-up

Torsional yield strengthM b

Recommended make-up torque

ol 04

Tool Joint Pin I.D.

Figure 4-2V8 SLHSO Torsional Yield and Make-up

STD.API/PETRO R P 7G-ENGL I,994 - 0 7 3 2 2 9 0 Db09692 0 0 8 -

2 2 API REWMMENDED PFIACIXE 76

2 Torsional yield strength

::; 2.750

45I-” Recommended make-up torque

4.500

iii::m 4.oooE4

cg I

3.750

3 . 5 0 0 I

gcP

Tool Joint Pin I.D.

Figure 5-2V8 PAC Torsional Yield and Make-up

Torsional yield strength

commended make-up torqueM b

Tool Joint Pin I.D.

Figure 6-NC31 Torsional Yield and Make-up

STD.API/PETRO R P 7G-ENGL I,998 m 0 7 3 2 2 9 0 0609693 T44 -

REWMMENDED PFWTICE FOR DRIU STEM DESIGN AND OPERAIING LIMITS 2 3

4 . 2 5 0

-

4.cQo

z8 -mE43 3 . 7 5 0z

3 . 5 0 0

3 . 2 5 08o!

4 . 2 5 0

4.ooo

%303 -E2 3 . 7 5 08t-

Recommended make-up torque

Is

I4

$j ’ g ’ 3 ’ i$ ’4 ci ci ti

Tool Joint Pin I.D.

8.8

Figure 7-27/, SLHSO Torsional Yield and Make-up

Recommended makeup torqueftAb

Torsional yield strengthfVlb

32

Figure 8-2’/, Wide Open Torsional Yield and Make-up

STD=API/PETRO R P 7G-ENGL l,=l98 m 0732290 Ob09694 980 -

24 API RECOMMENDED PFIACTICE 76

. 3.75

z::mEs

3.25

3.25

%

PE 3.00

4

2.75l

M b

I I IQ w 5ni c\i C

Tool Joint Pin I.D.

Figure 9-2’4 Open Hole Torsional Yield and Make-up

Qh

h+,83

II

Q

I

Torsions

Recommended make-up torqueit/lb

II yield strengthftllb

G r

Tool Joint Pin I.D.

Figure 1 W27/8 PAC Torsional Yield and Make-up

STD.API/PETRO R P 7G-ENGL I,998 - 0 7 3 2 2 9 0 0609695 8L7 D

RECOMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING LIMITS 2 5

5 . 1 2 5

-

4 . 6 7 5

4 . 3 7 5

4.125 , l+!&!+8 ’ i ’ SJ ’ zti ci ci ci ti ti l-5

Tool Joint Pin I.D.

Figure 1 l-NC38 Torsional Yield and Make-up

Recommended make-up torqueMb

I

Torsipnal yield strength

Figure 12-W, SLHSO Torsional Yield and Make-up

Tool Joint Pin I.D.

STD.API/PETRO R P 7G-ENGL I1998 - 0 7 3 2 2 9 0 ObO=lbqb 7 5 3 m

2 6 API REWMMENDED PRACTICE 76

Torsional yield strengthwlb

0 IPE2 t

Torsional yield strength

Tool Joint Pin I.D.

Figure 1 3-3V2 FH Torsional Yield and Make-up

Tool Joint Pin I.D.

Figure 14-3V2 Open Hole Torsional Yield and Make-up

STD.API/PETRO R P 7G-ENGL I,998 - 0 7 3 2 2 9 0 0609697 b=lT m

REUMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING LIMITS 2 7

4 . 0 0

3 . 7 5

%::

mI43I-”

3.5a

3.2:

8 -wi3 cTorsional yield strength

Recommended make-up torqueftilb

I I I I II I-

54 1 H I4 ,: z ’ 3 Icj ci

Tool Joint Pin I.D.

Figure 1 5-3V2 PAC Torsional Yield and Make-up

8

Tool Joint Pin I.D.

Figure 1 6-3V2 XH Torsional Yield and Make-up

STD.API/PETRO R P 7G-ENGL I.1948 - 0 7 3 2 2 9 0 0609698 526 -

2 8 API REWMMENDED PRNXICE 76

Recommended make-up torqueftllb

Torsional yield strength

5 . 6 2 5

5 . 3 7 5

2

P= 5 . 1 2 5

2

z -

4 . 8 7 5

Tool Joint Pin I.D.

Figure 17-tC40 Torsional Yield and Make-up

I Recommen

Torsional yield strength

ti tiTool Joint Pin I.D.

Figure W-4-Inch H90 Torsional Yield and Make-up

STD.API/PETRO R P 7G-ENGL I1998 - 0?322=lO Ob09699 4b2 m

RECOMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING LIMITS 29

Torsiopl yield strength_ _

Tool Joint Pin I.D.

Figure 19-4~Inch Open Hole Torsional Yield and Make-up

Tool Joint Pin I.D.

Figure 2O-NC46 Torsional Yield and Make-up

STD.API/PETRO R P 7G-ENGL 1998 - 0 7 3 2 2 9 0 Ob09700 T O 4 -

30 API REWMMENDED PFWTCE 76

E4 ci c-4 li ti l-5 ti ti 05 d

Tool Joint Pin I.D.

Figure 214V, FH Torsional Yield and Make-up

Tool Joint Pin I.D.

Figure 224V2 H90 Torsional Yield and Make-up

STD.API/PETRO R P 7G-ENGL I,998 - 0 7 3 2 2 9 0 0 6 0 9 7 0 3 940 -

RECOMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING L~~rrs 3 1

6.000

5.756

2

i 5 . 5 0 0

45c

5.250

5.ooo

6.750

6.5Wl

5.7x

Tool Joint Pin I.D.

Figure 234V/, Open Hole (Standard Weight) Torsional Yield and Make-up

R e c o m m e n d e d makeup t o r q u eMb

Tool Joint Pin I.D.

Figure 24-NC50 Torsional Yield and Make-up

STD.API/PETRO R P 7G-ENGL I,998 - 0 7 3 2 2 9 0 Ob09702 8 8 7 -

3 2 API RECOMMENDED PRACTICE 76

7.250

6.760 1 I I I I I

Tool Joint Pin I.D.

Figure 25--5$ FH Torsional Yield and Make-up

STD=APIlPETRO R I ’ ?G-ENGL L998 - 0732290 ObO9703 713 m

RECOMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING LlMlTs 3 3

4.12 The recommended make-up torque for a used tooljoint is determined by taking the following steps:

4.121 Select the appmpriately titled curve for the size andtype tool joint connection being studied.

4.12.2 Extend a horizontal line from the OD under consid-eration to the curve and read the recommended make-uptorque representing the box.

4.12.3 Extend a vertical line from the ID under consider-ation to the curve and read the recommended make-up torquerepresenting the pin.

4.12.4 The smaIler of the two recommended make-uptorques thus obtained is the recommended make-up torquefor the tool joint

4.12.5 A make-up torque higher than recommended maybe required under extreme conditions.

5 Properties Of Drill Collars5.1 Table 13 contains steel drill collar weights for a widerange of OD and ID combinations, in both API and non-APIsizes. Values in the table may be used to provide the basicinformation required to calculate the weights of drill collarstrings that am not made up of collars having uniform andstandard weights.

5.2 Recommended make-up torque values for rotary shoul-dered drill collar connections a listed in Table 14. These val-ues are listed for various connection styles and for commonlyused drill collar OD and ID sizes. The table also includes adesignation of the weak member (pin or box) for each con-nection size and style.

5.3 Many drill collar connection faihues are a result ofbending stresses rather than torsional stresses. Figures 26through 32 may be. used for determining the most suitableconnection to be used on new drill collars or for selecting thenew connection to be used on collars which have been worndown on the outside diameter.

5.4 A connection that has a bending strength ratio of 2.50: 1is generally accepted as an average balanced connection.However, the acceptable range may vary from 3.20:1 to1.90: 1 depending upon the drilling conditions.

5.5 As the outside diameter of the box will wear more rap-idly than the pin inside diameter, the resulting bendingstrength ratio will be reduced accordingly. When the bendingstrength ratio falls below 2.00:1, connection troubles maybegin. These troubles may consist of swollen boxes, splitboxes, or fatigue cracks in the boxes at the last engaged thread.

5.6 The minimum bending strength ratio acceptable in oneoperating area may not be acceptable in another. Local operat-ing practices experience based on recent predominance offailures and other conditions should be considered when

debmining the minimum acceptable bending strength ratiofor a particular area and type of operation.

5.7 Certain other precautions should be observed in usingthese charts. It is imperative that adequate shoulder width andarea at the end of the pin be maintained The calculationsinvolving bending strength ratios are based on standarddimensions for all connections.

5.6 Minor differences between measured inside diameterand inside diameters in Figures 26 through 32 anz of little sig-nificance; therefore select the figure with the inside diameterclosest to measured inside diameter.

5.9 The curves in Figures 26 through 32 were determinedfrom bending strength ratios calculated by using the SectionModulus (Z) as the measure of the capacity of a section toresist any bending moment to which it may be subjected. Theeffect of stress-relief features is disregarded. The equation, itsderivation, and an example of its use are included in A.lO.

6 Properties of Kellys6.1 Kellys aremanufacmed with one of two drive cotigu-rations, square or hexagonal. Dimensions are listed in Tables2 and 3 entitled “Square Kellys” and ‘Hexagon Kellys” ofAPI Specification 7.

6.2 Square kellys are furnished as forged or machined in thedrive section. On forged kellys, the drive sections are normal-ized and tempered and the ends are quenched and tempexzd.

6.3 Hexagonal or fully machined square kellys aremachined fiom round bars. Heat treatment may be either:

6.3.1 Full length quenched and tempered before machin-ing; or

6.3.2 The drive section normal&d and tempered and theends quenched and tempered.

It should be noted that fully quenched drive sections havehigher minimum tensile yield strength than normal&d drivesections when tempered to the same hardness level. For thesame hardness level, the ultimate tensile strength may bc con-sidered as the same in both cases.

6.4 The following criteria should be considered in selectingsquare or hexagonal kellys.

6.4.1 It may be noted from Table 15 that the drive sectionof the hexagonal kelly is stronger than the drive section of thesquare kelly when the appropriate kelly is selected for a givencasing size.

Example: A 4l/,-inch square kelly or a S/,-inch hexagonalkelly would be selected for use in gs/,-inch casing.

It should be noted, however, that the connections on thesetwo kellys are generally the same and unless the bores (insidediameters) are the same, the kelly with the smaller bore couldbe interpreted to have the greater pin tensile and torsionalstrength.

(Text continued on page 46.)

STD.API/PETRO R P 7G-ENGL I,998 - 0 7 3 2 2 9 0 0 6 0 9 7 0 4 b5T -

(2) (3)

API RECOMMENDED PRACTICE 7G

Table 13-Drill Collar Weight (Steel)(pounds per foot)

(4) (5) (‘5) 03 (8) (9) (10) (11) (12) (13) (14)

1 9 1 8 1 6

2 1 20 1 8

2 2 2 2 2 0

2 6 2 4 2 2

3 0 2 9 2 7

3 5 3 3 3 2

4 0 3 9 3 7

4 3 4 1 3 9

4 6 4 4 4 2

5 1 5 0 4 8

5 4

3 5 3 2 2 9

3 7 3 5 3 2

4 0 3 8 3 5

4 6 4 3 4 1

5 2 5 0 4 7 44

6 1 5 9 5 6 5 3 50

6 8 6 5 6 3 6 0 5 7

7 5 7 3 7 0 6 7 6 4

8 2 8 0 7 8 7 5 7 2

9 0 8 8

9 8 %

1 0 7 1 0 5

1 1 6 1 1 4

8 3 7 9 7 5 7 2 68

9 1 8 8 8 3 8 0 7 6

9 9 % 9 1 8 9 8 5

1 0 8 1 0 5 1 0 0 9 8 9 3

1 2 5 1 2 3

1 3 4 1 3 2

144 1 4 2

1 5 4 1 5 2

1 1 7 1 1 4 1 1 0 1 0 7 1 0 3 9 8 9 3

1 2 7 1 2 4 1 1 9 1 1 6 1 1 2 1 0 8 1 0 3

1 3 7 1 3 3 1 2 9 1 2 6 1 2 2 1 1 7 1 1 3

1 4 7 1 4 4 1 3 9 1 3 6 1 3 2 128 123

1 6 5 1 6 31 7 6 1 7 4

1 8 7 1 8 5

8 5

9 4

1 0 2

111

1 2 0

1 3 0

1 3 9

1 5 0

1 6 0

171

1 8 2

206

2 3 0

2 4 3

2 5 7

3 1 3

3 7 4

1 5 4 1 5 0 1 4 7 1 4 3 1 3 8 1 3 3

1 6 5 1 6 0 1 5 8 1 5 4 1 4 9 1 4 4

1 7 6 1 7 2 1 6 9 1 6 5 1 6 0 1 5 5

2 1 0

2 3 4

248

2 6 1

3 1 7

3 7 9

208

2 3 2

2 4 5

2 5 9

3 1 5

3 7 7

1 5 7

1 6 8

1 7 9

2Q3

2 2 7

240

2 5 4

3 1 0

3 7 1

2002 2 4

2 3 7

2 5 1

3 0 7

3 6 8

60

6 7

1 9 5

220

2 3 2

246

3 0 2

3 6 4

64

1 9 2

2 1 6

2 2 9

243

2 9 9

3 6 1

60

1 8 82 1 2

2 2 5

2 3 9

2 9 5

3 5 7

7 2

80

89

1 8 4

209

2 2 1

2 3 5

2 9 1

3 5 2

1 7 92 0 6

2 1 6

2 3 0

2 8 6

3 4 7

84

93

102

1 1 2

1 2 2

1 3 3

1 5 0

1 7 4

1 9 8

2 1 1

225

2 8 1

3 4 2

STD.API/PETRO R P 7G-ENGL L998 - 0 7 3 2 2 9 0 0609705 596 -

RECOMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING LIMITS 35

Table 14-Recommended Make-up Torque’ for Rotary Shouldered Drill Collar Connections(See footnotes for use of this table.)

(1)

size,i n

(4)

1

(6)

1’J2

(7) (8) (9) (10)

Minimum Make-up Torque R-lb2km?. of Drill collar, in&s

1V4 2 2’J4 2’1,

(11) (12) (13)

2’Y,, 3 33J,

Am NC 23

2’Jt

2’Ja

23JeA P I

2’/8

APIIFNC 26

2718

27~~

3’J22’Js

2’/8API

3’J2

S l i m H o l e

E x t r a H o l eDouble streamline

I-d-open

APIIFNC31

3’J2 S l i m H o l e

API NC 35

3’12 Exta Hole4 Slim Hole3’J2 Mod. Open

3’J2 APIIFAPI NC 384’J2 S l i m H o l e

3’J2 H-W

4 F u l l H o l eA P I NC404 Mod. Open4’J, D o u b l e S t r e a m l i n e

33’J83’Ja

*UC@ *2,508*3530 *3,3304,000 3,387

-31‘3,0283285

‘25082,6472,647

33’183’1,

‘231 1 , 7 4 92,574 1 , 7 4 92,574 1 , 7 4 9

3 *3,797 *3,797 29263’/, *4,966 4 , 1 5 1 59263’J4 536 4 , 1 5 1 29%3’J2 *4,606 *4,606 3.6973=J., 5Jol 4,668 3.697

3’J2 *3,838 *3.838 *3,838YJ. 5,766 4 , 9 5 1 4.0023’/8 5,766 4,95 1 4.002

3314 *4,089 *4$x39 *4,0893’18 ‘5,352 *5,352 *5.3524’f8 *s,o59 *a,059 7,433

3’Ja *4,640 *4,640 *4&w *4,6404’J, +7,390 *7,390 *7,390 6,853

4’1, *6,466 *6,466 *6.4&i *6,466 5,6854’Jd *7,886 *7,886 *7.886 7 , 1 1 5 5,6854’J2 1 0 , 4 7 1 9314 8,394 7 , 1 1 5 5,685

4’J4 “8,858 *8,858 8 , 1 6 1 6,853 5 , 3 9 14’J, 1 0 , 2 8 6 9,307 8 , 1 6 1 6,853 5 , 3 9 1

4’J2 *9,038 *9,038 *9,038 7 , 4 1 143i4 12,273 10,826 9a2 7 , 4 1 15 12,273 10,826 9 3 0 2 7 , 4 1 1

4’J, *5,161 *5,161 *5,161 *5,1614’12 %,479 q479 *a,479 8 , 3 1 143Jd *12g74 1 1 , 8 0 3 10,144 8,3115 1 3 , 2 8 3 1 1 , 8 0 3 1 0 , 1 4 4 8,3115’1, 1 3 , 2 8 3 1 1 , 8 0 3 1 0 . 1 4 4 8,311

43J4 *9,986 *9,986 *9.986 9,986 8 , 3 1 55 *13,949 *13,949 1 2 , 9 0 7 10,977 8 , 3 1 55v4 1 6 , 2 0 7 1 4 , 6 4 3 12,907 10,!?77 8 , 3 1 55’1, 1 6 , 2 0 7 1 4 , 6 4 3 1 2 , 9 0 7 1 0 , 9 7 7 8 , 3 1 5

43J4 *8,786 *8,786 *8,786 *a,786 *8,7865 *12;794 ‘12,794 * 12,794 *12,794 1 0 , 4 0 8S’J, ‘17,094 1 6 , 9 2 9 1 5 , 1 3 7 13,151 1 0 , 4 0 8sr, 1 8 , 5 2 2 1 6 , 9 2 9 1 5 , 1 3 7 13,151 1 0 , 4 0 8

5 *10,910 *10,910 *10,910 *10,910 *10,9105’f4 *15,290 *15,290 *l&290 14,%9 12125sv, *19,985 1 8 , 8 8 6 1 7 , 0 2 8 1 4 , 9 6 9 12J2591, 20,539 1 8 , 8 8 6 17.028 1 4 , 9 6 9 1 2 , 1 2 56 20,539 18,886 1 7 , 0 2 8 1 4 , 9 6 9 1 2 , 1 2 5

fJ%ble continued on next page.)

STD.API/PETRO R P ? G - E N G L In998 - 0 7 3 2 2 9 0 Ob0970b 4 2 2 -

36 API RECOMMENDED PRACTICE 76

Table W-Recommended Make-up Torque’ for Rotary Shouldered Drill Collar Connections (Continued)(See footnotes for use of this table.)

(1)

Size,in.

(2) (3)

conneuion

OD.Type in.

(41

1

(5)

1’1,

(6)

l$

(7) (‘3) (9) (10) (11) (12) (131

hfinimun~ Make.-up Torque i&lb2Bore of Drill cow inches

131, 2 2v4 2’f2 2131 16 3 331,

H-90’

API N C 4 4

5 H-90’

4’1,API555’1,5

5v2

API Full Hole

Extra HoleN C 4 6APIIFSemiIFDouble Stinsmbe

Mod-open

H-90’

APIIFN C 5 0ExtraHole-d-openDouble streamlineSemi-IF

H-W

*25,360 *253@ 9,360 -360 23,988*31,895 *31.895 2 9 , 4 0 0 2 7 , 1 6 7 23,988

35292 3 2 , 8 2 5 2 9 , 4 0 0 2 7 , 1 6 7 23,98835292 3 2 , 8 2 5 29.4m 2 7 , 1 6 7 23,988

*23,004 +23.004 *23,004 *u,oo4 *23,004*29,679 f29.679 *29,679 q9.679 26,675*36,742 3 5 . 8 2 4 32377 2 9 , 9 6 6 26,675

38,379 3 5 , 8 2 4 32277 2 9 , 9 6 6 26,6753&379 3 5 , 8 2 4 32977 2 9 , 9 6 6 26,67538J79 3 5 , 8 2 4 32277 2 9 , 9 6 6 26,675

*%508*41,9934z7194x719

*31,941*39,419

42J.814z4.81

+%=4 0 , 1 1 74 0 . 1 1 74 0 . 1 1 7

*31.941‘39,419w=3 9 , 8 6 6

*%-? 3 4 , 1 4 2 30,78136,501 3 4 , 1 4 2 30,78136,501 3 4 , 1 4 2 30,78136,501 3 4 , 1 4 2 30,781

*31,!941 *31,941 30,49536235 3 3 , 8 6 8 30,4953 6 , 2 3 5 3 3 , 8 6 8 30,4953 6 , 2 3 5 3 3 , 8 6 8 30,495

* 12590 *K&590 *x&590*17,401 *17,44x *17,401*2L&531 *w31 21,714

2 5 , 4 0 8 2 3 , 6 7 1 21,7142 5 . 4 0 % 2 3 , 6 7 1 21,714

*12&x40 *12J90*17,401 1 6 , 5 3 6

1 9 , 5 4 3 1 6 , 5 3 61 9 , 5 4 3 1 6 , 5 3 61 9 , 5 4 3 1 6 , 5 3 6

*15.576 * 15,576 * 15,576 *15,576 * 15,576*20,609 *20,609 *20,609 1 9 , 6 0 1 1 6 , 6 2 9

25.407 23,686 2 1 , 7 4 9 1 9 , 6 0 1 1 6 , 6 2 9=;407 23,686 2 1 , 7 4 9 1 9 , 6 0 1 1 6 , 6 2 9

*20,895 *20,895 *Z&895 *20,895 18,161Y&453 25,510 23,493 21,257 18,161

2 7 , 3 0 0 25,510 23,493 21,257 18,1612 7 , 3 0 0 25,510 23,493 21257 18,161

*1z973*18,119*23,605

2729427,294

*12,!&‘3*18,119*23,60525,27225272

*17,738v3.422

2 8 , 0 2 12 8 , 0 2 12 8 , 0 2 1

*18,019 *18,019 *18,019 *18,019*23,681 *23,681 2 3 , 1 5 9 2 1 , 0 5 128,732 26,397 2 3 , 1 5 9 2 1 . 0 5 128,732 26,397 2 3 . 1 5 9 2 1 , 0 5 128,732 26,397 2 3 , 1 5 9 2 1 , 0 5 1

*12,973 *1?.$v3 812973*18,119 *18,119 17,900am 1 9 , 9 2 1 17,90022,028 19,921 17,900=,m 19,921 17,900

*17,738 * 17,738 *17,738*23,422 22,426 20,311

25,676 22426 20,31125,676 22,426 20,31125,676 22,426 20,311

(Table continued 011 next page.)

STD=API/PETRO R P 7G-ENGL L=l=lB - 0 7 3 2 2 9 0 Ob09707 369 -

RECOMMENDED PRACTICE FOR DRILL STEM DESIGN AND OF-ERATING LIMITS 3 7

Table 14-Recommended Make-up Torque’ for Rotary Shouldered Drill Collar Connections (Continued)(See footnotes for use of this table.)

(2) (3)colmeccon

OQppe in

(4)

1

(5)

1 ‘I,

Q (8) (9) (10)

Minimum Make-up Tbrque fi-ltilBole of Drill collar, inche..s

1’/4 2 211, 211,

(11) (W (13)

2134, 3 3%

AFI NC70

API NC77

7

7518

API Full Hole *32,762 *32,762 *32,762*40,99a *40,998 WO.998

47,756 45,190 4153347,756 45,190 41,533

*32,762 *32,762*40,998 *40,998*49,661 *49,661

54515 51,687

*40,49a*49,060

52,11552,115

*40,49a *40,498 *40,49848221 45,680 42,058W=l 45,680 42$058N=l 45,680 42058

API Regular 7’12 *46,399 *46,399 *46.399 *4a399

7% ‘55,627 53,346 50,704 46,9368 57,393 53,346 50,704 46,936a’/, 57,393 53,344 50.704 46,936

H-90’ 711, *%5JJ9 *46,509 *46309 *44,509Ff, *55,708 *55,708 53,629 49,855a 60,321 56,273 53,629 49,8558’1, 60,321 56,273 53,629 49,855

NC61 a *55,131 *55,131 *55,131 *55,131av4 ‘65,438 t65,438 *65,438 61,624av2 7x670 68,398 65,607 61,624a’/, 72,670 68.398 65,607 61,6249 72,670 68,398 65,607 61.624

AFIIF 8 *56,641 *56,641 *56$x1 *56,641 *56.6418’1, s7.133 *67,133 *67,133 63,381 59,0278’12 74,626 70277 67,436 63,381 59.0278’J, 74,626 70277 67,436 63.381 59,0279 74,626 70277 67,436 63 .38 1 59,027911, 74,626 70277 67,436 63,38 1 59,027

API Full Hole SV, *67,789 *67,789 *67,789 *67,789 *67,789 67,184av, *79544 *79,544 *79544 76,706 72.102 67,1849 88,582 83,992 80,991 76,706 72,102 67,1849lJ., 88,582 83,992 80,991 76,706 72,102 67,1849lJ, 88,582 83,992 80,991 76,706 72,102 67,184

9 *75,781 -5,781 *75,781 *75,781 *75,78 1 *75,7a 19’1, *88,8U2 *88,802 *aa,am *aa,ao2 *88,802 *88,8029’12 *1u2,354 *102,354 *m&354 101,107 %J14 90,9849% 113,710 108,841 105,657 lOl,lu7 %214 90,98410 113,710 108,841 105,657 101,107 %214 90,984lOI/, 113,710 108,841 105,657 101,107 96,214 90,984

1 0 *1oa,194 *ma,194 *1oa,194 *108,194 *ma,194 *ma,194loll, *124.051 *x24,051 *124,051 *224,051 *124,051 *124,051lOV, *MO,491 *MO,491 *140,491 140,488 135,119 129,375love 154,297 Ma,%5 145,476 140,488 135,119 129,37511 154297 148,965 145,476 140,488 135,119 129,375

H-W a *53,454 *53,454 +53,454 +53,454 *53,454 *53,454av4 *63,738 *63,738 *63,738 *63,738 60,971 56,382av, *74,47a 72066 69,265 65,267 60,971 56,382

API Regular 8Vz *60,402 *60,402 *60,402 *60,402 *60,402 *60,402a% V2,169 *72,169 *72,169 *72,169 V2.169 *72,169

(Table continued on next page.)

STD.API/PETRO R P 7G-ENGL I~998 - 0 7 3 2 2 9 0 Ob09708 2T5 -

38 API RECXJMMENOEO PRACTICE 76

Table U-Flecommended Make-up Torque’ for Rotary Shouldered Drill Collar Connections (Continued)(See footnotes for use of this table.)

(1) (2) (3) (4) (5) (6) 0 03) (9) (10) (11) (12) (13)COdOll Minimum h&&e-up Tque i&W

Size, OD, B o r e o f D r i l l C o l l a r , i n c h e s

in. ln. 1 l’& IV, 13/d 2 2v4 2=i2 2134~ 3 3%9 *84,442 *84,442 *84,442 84221 7 9 , 5 3 6 7 4 , 5 2 9

H-90’

H-90”

H-W(with low torque &Ice)

@IResular(with low torque &We)

H-90’(with low toquc face)

H-W(with low tque fam)

9 6 , 3 0 1 9 1 , 6 3 39 6 , 3 0 1 9 1 , 6 3 3

v3,017 73,017*86,006 *86,006*99,508 *99,508

*109,345 *109,345‘125,263 *125,263*141,767 *141,767

*113,482 *113,482+130,063 *130,063

*68,06174235

*91,667*106,260

1 1 7 , 1 1 21 1 7 , 1 1 2

8 8 , 5 8 0 842218 8 , 5 8 0 SC-Q1

‘73,017*86,006*99,508

*73,017*86,00699508

*109,345*125,263

1 4 1 , 1 3 4

*109,345*125,263

1 3 6 , 1 4 6

*113,482*130,063

*113,482*130,063

*68,061 6 7 , 2 5 77 1 , 3 6 1 6 7 , 2 5 7

*73,099*86,463

9 1 , 7 8 99 1 , 7 8 9

*73,099*86,4638729287292

*91,667*106-

1 1 3 , 8 5 11 1 3 , 8 5 1

*91,667*1-

1 0 9 , 1 8 81 0 9 . 1 8 8

*11&883*130,672

1 4 7 , 6 1 6

*112,883*130,67214z430

*=so*110,781*129,203

*9zwio*110,781*129,203

7 9 , 5 3 6 7 4 , 5 2 97 9 , 5 3 6 74329

v3.017 73.017*86,006 *86,006*99508 %,285

*109,345 *109,345* 125,263 1 2 5 , 0 3 4

1 3 0 , 7 7 7 1 2 5 , 0 3 4

*113&Z *113,482* 130,063 * 130,063

6 2 , 8 4 5 5 8 , 1 3 16 2 , 8 4 5 5 8 , 1 3 1

*73,099 $73,0998&457 77398 2 , 4 5 7 77298 2 , 4 5 7 77?289

*91,667 *91,6671 0 4 , 1 7 1 9 8 , 8 0 41 0 4 , 1 7 1 9 8 , 8 0 41 0 4 , 1 7 1 9 8 , 8 0 4

*112,883 *112,883* 130,672 * 130,672

1 3 4 8 4 6 1 3 0 , 8 7 1

*!a960 *92,9&l*110,781 *110,781*129,203 *129,203

STD.API/PETRO R P 7G-ENGL 1998 W 0 7 3 2 2 9 0 0609709 L31 m

RECOMMENDED Prwmc~ FOR DRIU Smd DESIGN AND OPERATING Lwms 39

.1%’ 1.0. 1; I.D.

3.5 3.0 2.5 2 .o 1.5 3.5 3.0 2.5 2.0 1.5

TO OBTAIN BENDING STRENGTH RATIO,MEASURE a0. 8, I.D. OF DRILL COLLARAT POINTS SHOWN IN ABOVE ILLUSTRATION

3.5 3.0 2.5 2 .0 1.5 3 .5 3 .0 2.5 2 .0 LBBENDING STRENGTH RATIO BENDING STRENGTH RATIO

Figure 26-Dtill Collar Bending Strength Ratios, I$- and lV,-Inch ID

STD.API/PETRO R P 7G-ENGL 1998 - 0 7 3 2 2 9 0 0 6 0 9 7 3 0 9 5 3 -

40 API RECOMMENDED PRACI-ICE 76

TO OBTAINBENOWG STRENGTH RATIO,YEASUR2 00. 8 I.D. OF DRILLCOLLARAT POlNTS SHOWN IN A80VE ILLUSTRATION

3.5 3.0 2.5 2.0 1.5 3.5 3.0 2.S 2.0 I.5BENMNG STRENGTH RATIO 8ENDlNG STRENGTH RATIO

Figure 27-Drill Collar Bending Strength Ratios, 2- and 2V.,-Inch ID

STD.API/PETRO R P ?G-ENGL L’k3 E 0 7 3 2 2 9 0 0609?Ll, 87T -

REUMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING LIMITS 41

TO OBTAIN BENDING STRENGTH RATIO,MEASURE QD. 8 1.0. OF DRILL COLLARAT POINTS SHOWN IN ABOVE ILLUSTRATION

3.5 3.0 2.5 2.0 I.5 3.5 3.0 2.5 2 .0 I.5BENDING STRENGTH RATIO BENDING STRENGTH RATIO

Figure 28-Drill Collar Bending Strength Ratios, 21/,-inch ID

STD.API/PETRO R P 7G-ENGL I1998 - 0 7 3 2 2 7 0 0609732 72b

42 API REWMMENDED PRACTICE 76

2$.D. 2zlD.

3 5 3-O 2.5 2 . 0 1.5 3.5 3.0 2.5 2.0 1.5

I TO OBTAIN ENDING STRENGTH RATIO,MEASURE QD. 8 I.D. OF DRILL COLLAR

4AT PDtNtS SHOWN IN ABOVE ILLUSTRATION

3.5 3 . 0 2 . 5 2 . 0 I.5 3 . 5 3 . 0 2 . 5 2 . 0 I.5BENDlNG STRENGTH RATIO BENOING STRENGTH RATIO

Figure 29-Drill Collar Bending Strength Ratios, 213/,,-Inch ID

STD.API/PETRO R P 7G-ENGL 1998 - 0 7 3 2 2 9 0 0609733 662 m

RECOMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING LIMITS

3’ I.D. 3 l I.D.

3.5 3.0 2.5 2.0 1.5 3.5 3.0 2.5 2.0 I.5

I ._.- a----.--p. -_-.- _.-_-. -- -~ - - ~- -- ITO OBTAIN BENDING STHLNGTH RATIO,MLASURE 0.~. a I.D. OF DRILL CIULLAK

AT POINTS SHOWN IN ABOVE ILLUSTRATION8

3.5 3.0 2.5 2.0 1.5 3.5 3.0 2 .5 2 .0 1 . 5BENDING STRENGTH RATIO 8ENDlNG STRENGTH RATIO

43

Figure 3O-Drill Collar Sending Strength Ratios, 34nch ID

STD.API/PETRO R P 7G-ENGL Ii998 - 0 7 3 2 2 9 0 ObO97L4 5T=j

44 API RECOMMENDED PFWCTICE 76

3$ I.D. 3$ I.D.

3-5 3.0 2.5 2 .0 I.5 3.5 3.0 2.5 2.0 1.5

I TO OBTAINBENDING STRENGTH RATIO,MEASURE DO. B 1.0. OF DRILL COLLARAT POINTS SHOWN IN ABOVE lLLUSTRATlON

3% 3.0 2.5 2 .0 1.5 3.5 3 .0 2.5 2.0 15BENDJNG STRENGTH RATIO BENDING STRENGTH RATIO

Figure 31-Drill Collar Bending Strength Ratios, 3V,-Inch ID

STD.API/PETRO R P 7G-ENGL 1998 - 0732290 ObCl9735 Y35 m

REWMMENDED PRACTICE FOR DRIU .Sm DESIGN AND OPERATING LIMITS 45

3 9.0. 31’1.0.

-3.5 3.0 2.5 2 .0 1.5 35 3.0 2.5 2.0 I.5

TO OBTAIN BENDING STRENG%l RATIO,MEASURE QD. B I.D. OF DRILL COLLAR ’AT POINTS SHOWN IN ABOVE ILLUSTRATION

3.5 3.0 2.5 2 .0 1.5 3.5 3 0 2.5 2 .0 I.5BENDING STRENGTH RATIO BENDING STRENGTH RATIO

Figure 32-Drill Collar Bending Strength Ratios, 3V,-Inch ID

S T D . A P I / P E T R O R P 7G-ENGL la998 - 0 7 3 2 2 9 0 0609736 371 -

4 6 API RECOMMENDED PRA~~CE 76

6.4.2 For a given tensile load, the stress level is less in thehexagonal section.

6.4.3 Due to the lower stress level, the endurance limit ofthe hexagonal drive section is greater in terms of cycles tofailure for a given bending load.

6.4.4 Surface decarburization (decarb) is inherent in the aforged square kelly which further reduces the endurance limitin terms of cycles to failure for a given bending load. Hexago-nal kellys and fully machined squares have machined sur-faces and are generally tiee of decarb in the drive section.

6.4.5 It is impractical to remove the decarb from the com-plete drive section of the forged square kelly; however, thedecarb should be removed from the comers in the filletbetween the drive section and the upset to aid in the preven-tion of fatigue cracks in this srea. Machining of square kellysfrom round bars could eliminate this undesirable condition.

6.4.6 The life of the drive section is directly related to thekelly fit with the kelly drive. A square drive section normallywill tolerate a gmater clearance with acceptable life than willa hexagonal section. A diligent effort by the rig personnel tomahltain minimum clearance between the kelly drive sectionandthebushingwillminimize this consideration in kellyselection. New roller bushing assemblies working on newkellys will develop wear patterns that are essentially flat inshape on the driving edge of the kelly. Wear patterns begin aspoint contacts of zero width near the comer. The pattern wid-ensasthekellyandbushingbegintow~untilamaximumwear pattern is achieved. The wear rate will be the least whenthe maximum wear pattern width is achievd Figure 33 illus-trates the maximumwidthflatwearpatnznthatcouldbeexpected on the kelly drive flats if the new assembly hasclearances as shown in Table 16. The information in Table 16andFigures33and34~ybeusedtoevaluatetheclearancesbetween kelly and bushing. This evaluation should be madeassoonasawearpattembecomesappatentafteranewassembly is put into service.

Example: At the time of evaluation, the wear pattern widthfor a 5V4-inch hexagonal kelly is 1 .OO inch

This could mean one of the following two conditions exist:

a Ifthecontactangleislessthan8degrees37minutes,theoriginal clearances were acceptable. The wear pattern is notfullv developedb. Ifthecontactangleisgmaterthan8degmes37minutes,the wear pattern is fully developed. The clearance is greaterthan is recommended and should be unmcted

6.5 Techniques for extending life of kellys inch& rema-chining drive sections to a smaller size and reversing ends.

6.5.1 Remachining

Before attempting to remachine a kelly, it should be fullyitqxctd for fatigue cracks and also dimensionally checkedto assure that it is suitable for remilling. The strength of aremachined kelly should be compared with the strength of thedrill pipe with which the kelly is to be used. (See Table 17 fordrive section dimensions and strengths.)

6.5.2 Reversing Ends

Usually both ends of the kelly must be butt welded(stubbed) for this to be possible as the original top is too shortand the old lower end is too smaIl in diameter for the connez-tions to be reversed. The welds should be made in the upsetportions on each end to insure the tensile integrity and fatigueresistance capabilities of the sections. Proper heating andwelding pmcedums must be used to prevent cracking and torecondition the sections where welding has been performed.

6.6 The internal pressure at minimum yield for the drivesection may be calculated from Equation A.9.

7 Design Calculations7.1 DESIGN PARAMETERS

It is intended to outline a step-by-step procedure to ensurecomplete consideration of factors, and to simplify calcula-tions. Derivation of formulas may be reviewed in AppendixA. The following design criteria must be established

a Anticipated total depth with this string.b. Hole size.c. Expected mud weight.d Desired Factor of Safety in tension and/or Margin of Over

e . Desired Factor of Safety in collapse.f . Length of drill collars, OD, ID, and weight per footg. Desired drill pipe sizes, andimpection class.

7.2 SPECIAL DESIGN PARAMETERSIf the actual wall thickness has been determined by inspec-

tion to exceed that in API tables, higher tensile, collapse, andinternal pressure values may be used fat drill stem design

7.3 SUPPLEMENTAL DRILL STEM MEMBERSMachining of the connections to API spec&&ions and the

properheat tmatmentofthema&rialshaUbedoneonallsupple-mental dill stem members, such as subs, stabilizers, tools, etc.

7.4 TENSION LOADING

The design of the drill string for static tension loadsrequim sufficient stmngth in the topmost joint of each size,weight, grade, and classification of drill pipe to support thesubmerged weight of all the drill pipe plus the submerged

S T D . A P I / P E T R O R P 7G-ENGL 199i.i D 0 7 3 2 2 9 0 Ob097L7 2 0 8 D

RECOMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING Llrms 47

Table l~rength of Kellysl

(1) ia (3) (4) (5) (6) 0) (8) (9) (10) (11)

Imemalpres.sure at

Kelly si

andTypem .

LowerFincolmection h4inhudYIeldin M i n i m u m

Tensile Yield Torsional Yield YieldRecom-

Bending

l-Y xxmded LowerFin Drive LowerF5n Drive -Wh DriveBon?. Size and O D -go,-, &il%!tiOl13 section comleuion sec.tion Dr ive Sec t ion section

i n . Style in. in. lb lb &lb ft-lb R-lb Psi

2’/, square

4% sguare

4% ssuare

5% square

3 Hex

3V2 Hex

4’1, Hex

5’1, Hex

St4 Hex

6l-kX

416,000 444,400 9,650 12,300 13,000 29.800

535,ooo 582,500 14,450 19,500 22,300 ~,~

724,000 725200 22200

1,054,000 1,047,ooo 39,350 49,100 60,300 19,500

1.375+200 1,047,ooo 55.810 49,100 60.300 19,500

WW~ 1,703,400

356,CKJO 540,500

7z950 117,000

8.300 20,400 mm 26,700

495,000 710,Oal 13,400 31,400 31JOO 25,500

724,tXIO 1W5~ 22,700 56,600 56.000 25,CGO

%(A~ 1,507,600

1,162,OOO 1,397,lal

1,463,oOu 1,935.m

35,450

46,750

66,350

101,900

95,500

149,800

103.000

99,300

15~500

20.600

20.600

18,200

LAUvaluesbaveasafetyfactorof 1.0audarebasedonI10,OOOpsiminimum tensile yield (quenched and tee) for connections and 90,000 psi minimumtensile yield (normalized and tempered) for the drive section. Fully quenched and tempered drive sections will have higk values tbau those shown. Shearstlengthisbasedoll57.7peEeIltofthe minimum tensile yield strength.Tkarame between pmtedor rubber on kelly saver sub and casing inside diameter should also be checked.PTemile area calculated at mot of thread V., inch from pin shoulder.

STD.API/PETRO R P 7G-ENGL li99B - 0 7 3 2 2 9 0 Ob09738 144 -

4 8 API REWMMENDED PRACIXE 76

2 5 S O .75 1.00 1.25 1.50 1 . 7 5 200 E

Maximum Wear Pattern Width (inches)

2.05'

Note: Tk maxim~WearPattemWidthistheawaxgeoftheWearF%ttemWidthsbasedorlcaldatiollsusillg m i n i m u m and m a x i m u m c l e a r a n c e s a n d c o n t a c t a n g l e sinTable 16andk acclmewitllin5percent

Figure 33-New Kelly-New Drive Assembly Figure 34-New Kelly-New Drive Assembly

SmallSmall

Note:DriveEdgzwiilhaveawideilatpattemwithsmallcmtact angle.

Table 16-Contact Angle Between Kelly and Bushing forDevelopment of Maximum Width Wear Pattern

(1) (2) (3) (4) (5) (6) 0 (9)

2’/, - - - - .OlS 6 ’ 1 0 .107 1659’

3 .015 Y41’ .060 112 .015 5”3Y A07 15”s

3’12 .015 5”16 LKO 10-32’ .015 5”14’ .107 147

4’1, .015 4”48 LKO P-34’ .015 4O45 -123 13O36’

511, .015 4”lY .oHl 8%” .015 4”17’ -123 12”16’

6 .015 4”2’ .060 8”4 - - - -

STD.API/PETRO R P 7G-ENGL L=l=lB - 0332290 0609737 0 8 0 m

REWMMENDED PRACTICE FOR DRILL S TEM DESIGN AND OPERATING Lmms 49

(1) (2) (3)

Table 1 ‘/--Strength of Remachined Kellysl

(4) (5) (6) 0 (8) (9 (10)

original Remachind LowerPhlcomlectioll Tensile Yield Torsional Yield Yield ia BendingKelly size Kelly size GUY LowerPin Drive L.mverF5n Drive llmugh Drive-mdlLpe md’Ilpe BolE Size and OD conlleetion* section co+mcxtioll secticm section

m. 111. m. Style ill. lb. lb. Mb it/lb ftilb

4’1, SquaIC 4square 2vs NC50 6% 1,34WOO 834,400 55,500 36W 47&m(4% w

4’1, square 4square 2’/, NC46 6=iq 1,011,600 834,400 38,300 36,200 47,800(4W

51/, square 5 square 3314 sv, IF 7% 1 ,!a24300 1217,600 92.700 65,000 90200

sv, square 5sq= 3314 sv, FH 7 1,356.800 1,217,600 58,900 65,000 90,200

5V4 Hex 427/32 Hex 3v4 NC46 6’/., 80%~ 1,077,100 30,600 6wfJo 74,Ooo(4 m

5’1, Hex 5 Hex 3’1, NC46 6’1, 809,800 1,1%,800 mm 78,500 83,300(4 w

SV, Hex 5 Hex 3’12 NC50 6% ~,~ 19~9600 4Qm 71,100 78,400(4% w

6 Hex 91, Hex 4 511, FH 7 1,189,500 1443,400 51,300 109,lcKl 119,900

6 Hex 91, Hex 4’18 5’/* IF 7% 1,669,m 1,371,500 8wQo 103.800 116,200

‘AUvalueshaveasafetyfactorofl.Oandarebasedon110,000psi minimu tensile yield (quenched aud tempered) for connections and 90,000 psi minimumtensile yield (nonnaked and tempered) fox the drive section. Fully quenched and tempexed drive sections will have highet values than &se &JWU. shearstrength is based on 57.7 percent of the minimum tensile yield st~.~gth.T’e area dxlated at mot of thread VI inch from pin shoulder.Note: Kelly bushings 811: normally available for kellys in above table.

weight of the collars, stabilizer, and bit. This load may be cal-culated as shown in EQation 1. The bit and stabilizer weightsare either neglected or included with the drill collar weight.

p = wdp x w&J + (L, x %)I Kb (1)

whereP = submerged load hanging below this section of drill

pipe, lb.,L& = lengthof drillpipe,ft.,L, = length of drill collars, ft.,

W, = weight per foot of drill pipe assembly in air,WC = weight per foot of drill collars in air,Kb = buoyancy factor-see Table 11.

Any body floating or immersed in a liquid is acted on by abuoyant force equal to the weight of the liquid displaced. Thisforce tends to reduce the effective weight of the drill stringand can become of appreciable magnitude in the case of theheavier muds. For example, from Table 11, a one-poundweight submerged in a 14 1bJgal. mud would have an appar-ent weight of 0.786 lb.

Tension load data is given in Tables 2, 4, 6, and 8 for thevarious sizes, grades and inspection classes of drill pipe.

It is important to note that the tension strength valuesshown in the tables are theoretical values based on minimum

areas, wall thickness and yield strengths. The yield strengthas defined in API specifications is not the specific point atwhich permanent deformation of the material begins, but thestress at which a certain total deformation has occurred. Thisdeformation includes all of the elastic deformation as well assome plastic @ermanent> deformation. If the pipe is loaded tothe extent shown in the tables it is likely that some permanentstretch will occur and diEculty may be experienced in keep-ing the pipe straight. To prevent this condition a design factorof approximately 90 percent of the tabulated tension valuefrom the table is sometimes used, however, a better practice isto request a specific factor for the particular grade of pipeinvolve4l from the drill pipe supplier.

P, = P, x 0.9 (2)

wherePa = maximum allowable design load in tension, lb.,P, = theoretical tension load from table, lb.,

0.9 = a constant relating proportional limit to yieldstrength.

The diffenmce between the calculated load P and the max-imum allowable tension load represents the Margin of OverPull (MOP).

STD.API/PETRO R P 7G-ENGL I,998 - 0 7 3 2 2 9 0 0 6 0 9 7 2 0 8T2 -

50 API REWMMENDED PFWTICE 76

MOP=P,-P (3)

The same values expressed as a ratio may be called theSafety Factor (SF).

The selection of the proper safety factor and/or margin ofover pull is of critical importance and should be approachedwith caution. Failure to provide an adequate safety factor canresult in loss or damage to the drill pipe while an overly con-servative choice will result in an unnecessarily heavy andmore expensive drill string. The designer should consider theoverall drilling conditions in the area, particularly hole dragand the likelihood of becoming stuck. The designer must alsoconsider the degree of risk which is acceptable for the partk-ular well for which the drill string is being designed. Fre-quently, the safety factor also includes an allowance for slipcrushing and for the dynamic loadiug, which results fromaccelerations and decelerations during hoisting.

Slip crushing is not a problem if slips and master bushingsare maintained. Inspection class also grades the pipe withregard to slip crushing.

Normally the designer will desire to determine the maxi-mum length of a specitic size, grade and inspection class ofdrillpipewhichcanbeusedtodrillacertainwell.Bycom-lining Equation 1 and either Equation 2 or 3, the followingeqlations result:

P,xO.9 WC, LSFxW,,xK,-K = dp (5)

and/or

P,xO.9-MOP WJ, LW,xK, -w,,= dp (6)

Ifthestringistobeataperedstring,i.e.,tow~stofmorethan one size, grade or inspection class of drill pipe, the pipehaving the lowest load capacity should be placed just abovethe drill collars and the maximum length is calculated asshown previously, The next stronger pipe is placed next in thestriagandtheWLterminEquation5ar6isreplacedbyaterm representing the weight in air of the drill collars plus theddl pipe assembly in the lower string. The maximum lengthofthenextstrongerpipemaythenbecalculated.Anexamplecalculation using the above formulas is inchrded in 7.8.

7.5 COLLAPSE DUE TO EXTERNAL FLUIDPRESSURE

Thedrillpipemayatcertaintimesbesubjectedtoanexter-ml pressure which is higher than the internal pressure, This

condition usually occurs during the drill stem testing aud mayresult in collapse of the drill pipe. The differential pressurerequired to produce collapse has been calculated for varioussizes, grades, and inspection classes of drill pipe and appearsin Tables 3, 5, 7, and 9. The tabulated values should bedivided by a suitable factor of safety to establish the allow-able collapse pressure.

where

4 = theoretical collapse pressure from tables, psi,SF = safety factor,P, = allowable collapse pressure, psi.

When the fluid levels inside and outside the drill pipe areequal and provided the density of the drilhng fluid is constant,the collapse pressure is zero at any depth, i.e., there is no dif-ferential pressure. If, however, them should be no fluid insidethe pipe the actual collapse pressure may be calculated by thefollowing equation:

o r

wherePC =L =

wg =Wf =

LWp, = 219.251

net collapse pressure, psi,the depth at which PC acts, ft.,weight of drill@ fluid, lb/gal,weight of dlilliug fluid lbku ft.

03)

(9)

If then is fluid inside the drill pipe but the fluid level is notashighinsideasoutsideorifthefl~dinsideisnotthesameweight as the lluid outside, the following equation may beused:

p _ L w,-(L-Y)W8’c- 19.251

o r

PC =L wf-(L- Y)Wf’

144

whereY = depthtofluidinsidedrillpipe,&,

W,’ = weight of drihing fluid inside pipe, lb/gal,= weight of drilling fluid inside pipe, lbku II.

W)

(11)

STD.API/PETRO R P ?G-ENGL I,998 - 0‘732290 0609721 7 3 9 -

RECOMMENDED PFIACTICE FOR DRIU STEM DESIGN AND Om4mra3 Lwms 5 1

7.6 INTERNAL PRESSURE

Occasionally tbe drill pipe may also be subjected to a netinternal pressure. Tables 3,5,7, and 9 contain calculated val-ues of the di&rential internal pressure required to yield thedrill pipe. Division by an appropriate safety factor will resultin an allowable net internal pressure.

7.7 TORSIONAL STRENGTH

The torsional strength of drill pipe becomes critical whendri l l ing deviated holes, deep holes, reaming, or when the pipeis stuck. This is discussed under Sections 8 and 12. Calcu-lated values of torsional strength for various sizes, grades, andimpection classes of drill pipe are provided in Tables 2,4,6,and 8. The basis for these calculat ions is shown in AppendixA. The actual torque applied to the pipe during dri l l ing is dif-ficult to measure, but may be approximated by the followingequat ion:

T = HPx5,250RPM (12)

where From Equation 5:

T = torque delivered to drill pipe, ft-lbs,H P = horse power used to produce rotation of pipe,

RPM = revolutions per minute.

Note:Thetorqueappliedtothedrillstringshouldnotexceedtheactualtooljoint make-up tonye. The recommnded tool joint make-up toqe is shownin Table 10.

L(P,, x -9) -MOP W, x L,

d p l =- -

wdp, x Kb W dpl

= (225,771 x.9)-50,000 90x63018.37 x .847 - 1 8 . 3 7

= 9846 - 3087 = 6759 feet7.6 EXAMPLE CALCULATlON OF ATYPICALDRILL STRING DESIGN-BASED ON MARGINOF OVERPULL

Design parameters are as follows:

a. Depth-12,700 feet .b. Hole size-7Vs inches.c. Mud weight-10 lb/gal.d Margin of overpull (MOP)-50,000 lb. (assumed for thiscalculation).e. Desired safety factor in collapse-11/, (assumed for thiscalculation).f . Drillcollardataz

1. Ungth&30 feet.2. OD-6’/, inches.3. ID-2V, inches.4. Weight per foot-90 lb.

lf tbe length of drill collars is not known, the following for-mulamay be used:

L, =B i t ,

cosaxNPxk,xW,

w h e r eL, =

Bit,,,,, =a =

NP =

Kb =WC =

L, =

==

length of drill collars, feet,maximum weight on bit, lb,hole angle fi-om vertical, 3 degrees,neutral point design factor determines neutralpoint posi t ion e.g. , .85 means the neutral pointwill be 85 percent of the drill collar string lengthmeasured from the bot tom (.85 assumed for thiscalculation),buoyancy factor, see Table 11,weight per foot of drill collars in air, lb,

40,000.998 x .85 x .847 x 90 ’

6 1 8 feet , closest length based on 30 foot collars ,630 feet or 21 drill collars.

g. Drill string size: weight and grade4V, in. x 1660 lb/ft xGrade E75, with 4*& in., NC46 tool joints, 6V4 in. OD x 3V4in. ID, Inspection Class 2.

It is apparent that drill pipe of a higher strength will berequired to reach 12,700 feet. Add 4V2 in. x 16.60 lb/ft GradeX-95, with 4V2 in. X.H. tool joints, 6V., in. OD x 3 in. ID(18.88 lb/ft) Inspection Class Premium.

Air weight of Number 1 drill pipe and drill collars:

Total weight = (L.+, x W,,) + (L, x WC)

= (6759 x 18.37) + (630 x 90)

= 124,163 + 56,700 = 180,863 lb.

From Equation 5:

L (p,, x -9) - MOPdp2 =

cLdpl x wdp,) + CL, x wc)

wdp2xKb - W W

= (329,542 x .9) - 50,000 180,863- -18.88 x .847 18.88

= 15,420 - 9580 = 5840 feet

S T D . A P I / P E T R O R P 7G-ENGL It998 m 0 7 3 2 2 9 0 0 6 0 9 7 2 2 675 m

5 2 API REWJMMENDED FFIA~TICE 76

~ismoredrillpipethanrequiredto~h12,7oOfeet,so final drill string will consist of the following:

DliI lcollars6’/.” O.D. x 2Va” ID.

No. 1DrlllF’i~4V,” x 16.60 lb,GradeE75,class2

No.2DrillPipe4’/,” x 16.60 lb,chde x-95,E%mliumchss

6 3 0 56,700 %o=

6 7 5 9 1 2 4 , 1 6 3 1 0 5 . 1 6 6

5 3 1 1 1 0 0 , 2 7 2 8 4 , 9 3 0

12700 2 8 1 , 1 3 5 2 3 8 , 1 2 1

Torsional Yield of 4V,” x 16.60 lb x Grade E75 x InspectionClass 2 = 20,902 &lb.

Collapse Pressure of 4$” x 16.60 lb x Grade E75 x Inspec-tion Class 2 = 595 1 psi.

Collapse pressure of 4V2” x 16.60 lb x Grade X-95 x Pxe-mium Inspection Class = 8868 psi.

From Equation 8:

Pressureatbottomofdrillpipe:P,=~,

L = 12,070 feet, W, = 10 lb/gal,

PC’ 12,070 x 1019.251

= 6270 psi

Therefore,thisdrillpipehasalowercollapsepressurethaumay be encotmted in drilling to 12,700 feet Precautionsshould be takeu to prevent damage to the drill pipe when nm-ning the string dry below 10,183 feet, This is de&mined bysolving Equation 8 for maximum length of drill pipe, anddividing by the safety factor in collapse of l’/,:

PC x 19.251L= w + 1.125

8

= 5951 x 19.251 f 1 1251 0

= 11,456 f 1.125 = 10,183 feet

7.9 DRILL PIPE BENDING RESULTING FROMTONGING OPERATIONS

It is generally known that the tool joint on a length of drillpipe should be kept as close to the rotary slips as possible dur-

ing make-up and break-out operations to prevent bending ofthe pipe.

Thereisa maximum height that the tool joint may be posi-tioned above the rotary slips and the pipe to resist bending,while the maximum recommended make-up or break-outtqe is applied to the tool joint.

Many factors govern this height limitation. Several of thesewhich should be taken into most seri&s consideration are:

a The angle of separation between the make-up and break-out tongs, illustrated by Case I and Case II, Figure 35. Case Iindicates tongs at 90 degrees and Case II indicates tongs at180 degrees.b. The minimum yield strength of the pipe.c . The length of the tong handle.d The maximum recommended make-up torque.

HMC=-053 Y$ (VC) (caseD

H = -038 YJ, WC)llyD T cc= n)

(13)

(14)

whereH,,= height of tool joint shoulder above slips, ft.,

Y, = minimum tensile yield stress of pipe, psi,L, = tong arm length, ft.,P = line pull (load), lbs,T = makeup torque applied to tool joint (PA), ft-lb,

UC = section modulus of pips-in3. (see Table 18).

Constants 0.053 and 0.038 include a factor of 0.9 to reduceY, to proportional limit (see 7.3)._ Sample calculation:

Assume: 4V&., 16.60 lb/ft, Grade E drill pipe, with4V,-in. X.H. 6%&~ OD, 3V,-in. ID tool joints.

Tong arm 3V#.Tongs at 90 (Case I).Using Equation 13:

H., = .053 (Ym) WC) wT

,

L = 75,000 psi (for Grade E),

VC = 4.27 in3 (Table 18),

L, = 3.5 R,

T = 16,997 R-lb (km Table lo),

H, =.053(75,000)(4.27)(3.5) = 3 4 ft.

16,997.

STD.API/PETRO R P 7G-ENGL lJ998 - 0 7 3 2 2 9 0 Ob09723 5Ol, m

REWMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING LIMITS 53

Table 18-Section Modulus Values

(2)

P i p e w e i g h tNominal

lbs’ft

4 . 8 5

6 . 6 5

6 . 8 5

1 0 . 4 0

9 . 5 0

1 3 . 3 0

1 5 . 5 0

11.85

1 4 . 0 0

1 5 . 7 0

13.75

1 6 . 6 0

2 0 . 0 0

2 2 . 8 2

2 4 . 6 6

2 5 . 5 0

16.25

1 9 . 5 0

2 5 . 6 0

19.24l

2 1 . 9 02 4 . 7 0

2 5 . 2 0

(3)

Kal. in.

0 . 6 6

0 . 8 7

1 . 1 2

1 . 6 0

1.96

2 . 5 7

2 . 9 2

2 . 7 0

3 . 2 2

3 . 5 8

3 . 5 9

4 . 2 7

5 . 1 7

5 . 6 8

6 . 0 3

6 . 1 9

4 . 8 6

5 . 7 1

7 . 2 5

6 . 1 1

7 . 0 3

7 . 8 4

9 . 7 9

8 Limitations Related to Hole Deviation

8.1 FATIGUE DAMAGE

Most drill pipe failures are a result of fatigue (see 11.2).Drill pipe will suffer fatigue when it is rotated in a section ofhole in which there is a change of hole angle and/or direction,commonly called a dogleg. The amount of fatigue damagewhich results depends on the following:

8.1 .l Tensile Load in the Pips at the Dogleg

Following is an example calculation:

a Data:1. 4’/,-inch, 16.60 lb/ft, Grade E, Range 2 drill pipe (actualweight iu air including tool joints, 17.8 lb@ 73/,-inch OD,21/,-inch ID drill colhux (actual weight iu air 147 lb/f@2. 15 lb/gal (112.21 lbku. ft) mud

3. (buoyancy factor = 0.771)

4. Dogleg depth: 3,000 ft.5. Anticipated total depth: 11,600 ft.6. Drill collar length: 600 ft.7. Drillpipelengthattotaldepthz ll,OOOft.

8. Length of drill collar string, whose buoyant weight isin excess of tbe weight on bit: 100 ft.

b. Solution:Tensile load in the pipe at the dogleg:

[(ll,OOO-3,000) 17.8+100x 14710.771 = 121,124lb

IH max

w/LT P

Case II

Figure SMaximum Height of Tool Joint Above Slips to Prevent Bending During Tonging

S T D . A P I / P E T R O R P 7G-ENGL 1998 - 0 7 3 2 2 9 0 Ob09724 Y’i8 -

54 API RECOMMENDED PFWTICE 76

8.1.2 TheSetveriioftheDogleg

The number of cycles experienced iu the dogleg, as well asthe mechanical dimensions and properties of the pipe itself.

Because tension in the pipe is critical, a shallow dogleg in adeep hole often becomes a source of difhculty. Rotating offbottom is not a good practice since additional tensile loadresults from the suspended drill collars. Lubinsk? andNicholson2 have published methods of calculating forces ontool joints and conditions necessary for fatigue damage tooccur. Referring to Figums 36 and 37, note that it is necessaryto remain to the left of fatigue curves to reduce fatigue dam-age. Frograms to plan aud drill wells to minimize fatiguehave been reported by Schenck3 and Wilson4. Such programsare necessary to reduce fatigue damage.

The curves on Figures 36,37, and 38 (also Figures 41,42,aud 43) are for Range 2 drill pipe, i.e. for joint lengths of 30feet. This length has an effect on the curves. Information isavailable on fatigue of Range 3 (45 feet) drill pipe.14 Thecurves on Figures 36,37, and 38 are independent of tool jointOD, however, the portion of the curve for which there is pipeto-hole contact between tool joints (dashed lines on Figures36 and 38) becomes longer when tool joint OD becomessmaller, and conversely.

The advent of electronic pocket calculators makes it easyto use the following equations instead of the curves in Figures36 and 37.‘~~

wherec =

E===

D =L =

=

c = 432,000 8, tanhKLII: i?ij ?if--

Kc L$EI

(15)

maximum permissible dogleg severity (hole cur-vature), degrees per 100 feet,Young’s modulus, psi,30 x 106 psi, for steel,10.5 x 106 psi, for aluminum,drill pipe OD, inches,half the distance between tool joints, inches,180 inches, for Range 2.

T =

h=Z =

buoyant weight (including tool joints) suspendedbelow the dogleg, pounds.maximm permissible bending stress, psi,drillpipemomentofinertiawithrespecttoitsdiametex, ia4, calculated by Equation 17.

I=& CD”-&,

whereD = drill pipe OD, inches,d = drill pipe ID, inches.

The maximum permissible bending stress, &, is calculatedfrom the buoyant tensile stmss, S, (psi), in the dogleg withEquations 19 and 20 below. S, is calculated with Equation 18:

6, = f (18)

whereA = cross sectional area of drill pipe body, square inches.

ForGradeEG4

8, = 19,500-i 6,--Oh (6,-33,5OOy(670)’

09)

Equation 19 holds true for values of S, up to 67,000 psi.For Grade S-135:2

0,=20001-5( 145,000 >

Equation 20 holds true for values of up to 133,400 psi.The following equation may be used instead of Figure 38:

108,000 Fc=- -XL T (21)

in which F is the lateral force on tool joint (1000,2000, or3000 pounds in Figure 38), and the meaning of the other sym-bols is the same as previously.

8.2 REMEDIAL ACTION TO REDUCE FATIGUE

If doglegs of su@cient magnitude are present or suspected,itisgoodpracticetostringreamthedogleg~Thisreducesthe severity of the hole angle change. With reference to Fig-ure4o,thefatiguelifeofdrillpipewillbedecreasedconsid-embly when it is used in a corrosive drilhng fluid For mauywater-base drilhg fluids, the fatigue life of steel drill stemsmay be in& by maintaining a pH of 9.5 or higher Referto 10.1.4 for description of a corrosion monitoring system.

Several methods are available for monitoring and control-ling the comosivity of drilling fluids. The most commonlyused monitoriug technique is the use of a corrosion ringinserMinthedrillstem.Foradescriptionofthistechniquesee API Recommended Practice 13B-1, Recommended Pmc-tice StMdard Pmcedum for Field Testing Wi.&r-Based Drill-ing F&is.

S T D . A P I / P E T R O R P 3G-ENGL 1998 m 0 7 3 2 2 9 0 Clb09325 38q -

RECOMMENDED PFWXICE FOR DRILL STEM DESIGN AND Otwumffi Lwrs5 5

1

Dogleg Severity-Degrees Per 100 Feet

3 3 4 5 60

0 I I I I I I

In corrosive environments, reduce dogleg savetity to a fraction- (0.6 for very severe conditions) of the indicated value.

5 0

1 0 0

Region of nofatigue damage

I

7001 joint plus drill pipeall Range 2.

I I I I I

Note:Dashed curve corresponds to condition when drill pips contactsthe hole between tool joints, and then the permissible doglegseverity is greater than indicated.

Figure 36-Dogleg Severity Limits for Fatigue of Grade E75 Drill Pipe

STD.API/PETRO R P 7G-ENGL la958 - 0 7 3 2 2 9 0 Ob0972b 2LO -

56 API RECCHMENDED PRMXICE 76

0 1

Dogleg Severity-Degrees Per 100 Feat

2 3 4 5 6

In corrosive environments, reduce dogleg severity to a fraction(0.6 for very severe conditions) of the indicated value.

Region of nofatigue damage

Tool joint plus drill pipeall Range 2.

Figure 37-Dogleg Severity Limits for Fatigue of S-135 Drill Pipe

STD..API/PETRO R P 7G-ENGL I,998 - 0732290 Obll9727 It57 -

REWMMENDED PRACTICE FOR DRILL STEM DESIGN AND OPERATING Ll~rrs 5 7

Dogleg Severity-Degrees Per 1 DO Feet

2 3 4 5 6

Note:Dashed curves correspond to condition when drill pips maycontact the hole between tool joints, and then the permissibledogleg severity may be greater than indicated.

Figure 38-Lateral Force on Tool Joint

STD.API/PETRO R P 7G-ENGL I~998 - 0 7 3 2 2 9 0 Ob09728 093 m

53 API RECXXWENDED PRACTKX 7G

8.3 ESTlYATlON OF CUMULAllVE FAllGUEDAMAGE

Hansford and Lubinsk? have developed a method for esti-mating the cmwlative fatigue damage to joints of pipe whichhave been rotated through severe doglegs (see Figures 39 and40). While insufbcient field checks of the results of thismethod have been made to verify its reliability, it is availableas a simple analytic device to use as a guide in the identiflca-tion of suspect joints. A corm&ion formula to use for otherpenetration rates and rotary speeds is as follows:

96 Life Expended = % Life Expended from

Figure39or4Ox

Actual RPM lOft/hr1OORl’M xActllalft/hr

8.4 IDENTlFlCATlON OF FAllGUED JOINTS

As mentioned, insuhlcient data is available to verify theresults of the method explained in 8.3. However, it is the onlyme&cd presently available for estimating cumulative fatiguedamage and should be used if it is possible to identify andclassify fatigned joints. The difficnlty lies in identifying andnxording each separate joint fatigue history. Joints whichhave been calculated to have more than 100 percent of theirfatigue life expended should be carefully examined and, if notdowngraded or abandoned, watched as closely as possible.Such consideration should be Cnally governed by experiencefactors until such time as the analytical method for fatigueprediction gains mom reliability.

8.5 WEAR OFTOOL JOINTS AND DRILL PIPE

When drill pipe in a dogleg is in tension it is pulled to theinside of the bend with substantial force. The lateral force willin- the wear of the pipe and tool joints. When abrasion isaproblemitisdesirabletolimittheamountoflateralforcetoleas than about 2WCl lb on the tool joints by controlling therate of change of hole angle. Values either smaller or greaterthan 2000 lb might be in order, depending on formation at thedogleg. Figure 38 shows curves for 1000,2000, or 3000 lblateral force on the tool joints; points to the left of thesecurve-s will have leas lateral force, and points to the right morelateral force on the tool joints. Figures 41, 42, 43, and 44,developed by Lubinski, show lateral force curves for bothtool joints and drill pipe for three popular pipe sixes. The firstthreefi~arefor~pipesizes,Range2.Figure44isfor5inch, 19.5 lb per foot, Range 3 drill pipe.

8.5.1 For conditions repmsented by points located to theleft of Curve No. 1, such as point A in Fqum 41, only tooljoints and not drill pipe between tool joints contact the wall ofthe hole. This should not be construed to mean the drill pipe

Percent Fatigue LifeExpended in a 30 Foot lntervai

s I I ’ lhgibg !iev&ty’

For:Drill pipe, 3V..“, 4V2’, and 5’ Grade Esteel; rotary speed, 100 rpm; drillingrate, 10 feet/hour.

Figure 39-Fatigue Damage in Gradual Doglegs(Noncorrosive Environment)

Percent Fatigue LifeExpended in a 30 Foot Interval .--

0 50 1OtJI I I

1 DLgl&sevedty1 DegreesPerlOOFeet

II i ‘4 i i i i

For:Drill pipe, 3V,‘, 4V2’, and 5’ Grade Eti~i;,;bk~;d, 100 rpm; drilling

I

Figure 4O-Fatigue Damage in Gradual Doglegs(In Extremely Corrosive Environment)

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RECOMMENDED PRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS 59

body does not wear at all, as Figure 41 is for a gradual and notfor an abrupt dogleg. In an abrupt dogleg, drill pipe does con-tact the wall of the hole half way between tool joints, and thepipe body is subjected to wear. This lasts until the dogleg isrounded off aud becomes gradual.

8.5.2 For conditions represented by points located onCurve No. 1. theoretically the drill pipe contacts the wall ofthe hole with zero force at the midpoint between tool joints.

8.5.3 For conditions represented by points located betweenCurve No. 1 and Curve No. 2, theoretically the drill pipe stillcontacts the wall of the hole at midpoint only, but with a forcewhich is not equal to zero. This force increases tim CurveNo. 1 toward Curve No. 2. Practically, of course, the contactbetween the drill pipe and the wall of the hole will be along ashort length located near the midpoint of the joint.

8.5.4 For conditions represented by points located to theright of Curve No. 2, theoretically the till pipe contacts thewall of tbe hole not at one point, but along an arc withincreasing length to the right of Curve No. 2.

OneachoftheFigures41,42,43,and44,thereareinaddi-tion to curves No. 1 and No. 2, two families of curves: one forthe force on tool joint, and the other for the force. on drill pipebody. As an example, consider Figure 41; Point B indicatesthat if the buoyant weight suspended below the dogleg is170,000 lb, and if dogleg severity (hole curvatu%) is 10.1degrees per 100 feet, then the force on tool joint is 6000 lb,and the force on drill pipe body is 3000 lb.

8.6 HEAT CHECKING OFTOOL JOINTS

Tool joints which are rotated under high lateral forceagainst the wall of the hole may be damaged as a result offriction heat checking. The heat generated at the surface oftbe tool joint by tiction with the wall of the hole when underhigh radial thrust loads may raise the temperature of the tooljoint steel above its critical temperature. Metalhu@cal exami-nation of such joints has indicated affected zones with vary-ing hardness as much as 3/l,-in. below OD surf=. If theradial thrust load is sufficiently high, surface heat checkingcan occur in the presence of drilling mud alternately beingheated and quenched as it rotates. This action producesnumerous irregular heat check cracks often accompanied bylonger axial cracks sometimes extending through the frill sec-tion of the joint and washouts may occur in these splits orwindows. (See Lubinski, ‘Maximum Permissible Dog Legsin Rotary Boreholes,” Journal of Petdeum Technology,1961.)’ Maintaining hole angle control so that 2000 lb lateralforce is not exceeded will minimize or eliminate heat check-ing of tool joints.

9 Limitations Related To Floating Vessels9.1 All possible steps should be taken to avoid subjectingdrill pipe to fatigue; i.e., to cyclic stresses due to rotation ofthe drill string under bending aud tension. ‘zfivo major factorswhich are specific to drilling from a floater that contribute tofatigue of drill pipe are as follows:

9.1.1 The rotary table is not centered at all times exactlyabove the subsea borehole.

9.1.2 The derrick is not always vertical but follows the rolland pitch motions of the floater.

9.2 This text pertains to prevention of fatigue due to factorb, above. When the derrick is inclined during a part of the rollor pitch motion, the upper extremity of the drill string is notvertical while the drill pipe at some distance below the rotarytable remains vertical. Thus the drill string is bent. As drillpipe is much less rigid than the kelly, most of the bendingoccurs in the first length of drill pipe below the kelly. Thissubject is studied in a paper titled, llte Effect qf Drilling Yes-se1 Pitch or Roll on Kelly and Drill Pipe Fatigue, by John E.Hansford and Arthur Lubinski6

9.3 Based on the Hansford and Lubinski pap$. the follow-ing practices anz recommended to minimize bending an&therefore, fatigue of the first joint of drill pipe, due to roll and/or pitch of a floater.

9.3.1 Multiplane bushings should not be used. Either agamboled kelly bushing, or a one-plane roller bushing is pref-erable.

9.3.2 An extended length kelly should be used to relievethe severe bending of the limber drill pipe through less severebending of the rigid kelly extension. This extension may beaccomplished by any of the following means:

a. For Range 2 drill pipe, use a 54-foot kelly which is ordi-narily used with Range 3 pipe, r&her than the usual 40-footkelly.b. Use a specially made kelly at least 8 feet longer than thestandard length.c. Use at least 8 feet of kelly saver subs between the kellyand drill pipe.

9.3.3 If b, above, is not implemented, avoid rotating offbottom with the kelly more than half way up for long periodsof timeifthemaximum angular vessel motion is more than 5degrees single amplitude. In this text, long periods of timeZlll?:

a. More than 30 minutes for large hookloads.b. More than 2 hours for light hookloads.

9.3.4 If conditions prevent implementing b or c, above, thefirst joint of drill pipe below the kelly should be removedfrom the string at the fh-st opportunity and discarded.

STD.API/PETRO RP ?G-ENGL I~998 - 0 7 3 2 2 9 0 Ob09730 74L W

60 API RECOMMENDED PWCTICE 76

Figure 4l-Lateral Forces on Tool Joints and Range 2 Drill Pipe 3l/,-Inch, 13.3 Pounds per Foot,Range 2 Drill Pipe, 43/,-inch Tool Joints

Dogeg Severlly (Hde Curvahrre)-Degtws Per 100 Feet5 10

I I I I I I I I I I I I I II I 1I

I I I I I I I I I I I I I I

Figure 42-Lateral Forces on Tool Joints and Range 2 Drill Pipe 4V,-Inch, 16.6 PoundsRange 2 Drill Pipe, 6V,-Inch Tool Joints

per Foot,

STD.API/PETRO R P 7G-ENGL 1998 - 0 7 3 2 2 9 0 Ob0973L b&B m

RECOMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING Lwms 61

Figure

Dogleg Severily (Hole curvatum~egreas per 100 Feet5 10

.ateral Forces on Tool Joints and Range 2 Drill Pipe 54nch, 19.5 PoundsRange 2 Drill Pipe, 63/,-inch Tool Joints

per Foot,

Dogleg Sewity (Hde Chwture)-cegrees Per 100 Feet5 10

Figure 44-Lateral Forces on Tool Joints and Range 3 Drill Pipe 54nch, 19.5 Pounds per Foot,Range 3 Drill Pipe, 63/,-inch Tool Joints

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6 2 API RECOMMENDED PRACXICE 76

10 Drill Stem Corrosion and SulfideStress Cracking

10.1 CORROSION

10.1.1 Corroshre Agents

Corrosion may be detined as the alteration and degradationof material by its envkonment. The principal corrosive agentsaffecting drill stem materMs in water-base drilling fluids atedissolved gases (oxygen, carbon dioxide, and hydrogen sul-fide), dissolved salts, and acids.

10.1.1.1 Oxygen

Oxygen is the most common corrosive agent In the pres-ence of moisture it causes rusting of steel, the most commonform of corrosion. Oxygen causes uniform corrosion and pit-ting, leading to washouts, twistoffs, and fatigue failures.Since oxygen is soluble in water, and most drilling fluid sys-tems are open to the air, the drill stem is continually exposedto potentially severe corrosive conditions.

10.1 .1.2 Carbon Dioxide

Carbon dioxide dissolves in water to form a weak acid(carbonic acid) that cormdes steel in the same manner asother acids (by hydrogen evolution), unless the pH is main-tained above 6. At higher pH values, carbon dioxide corrosiondamage is similar to oxygen corrosion damage, but at aslower rate. When carbon dioxide and oxygen am bothpresent, however, the corrosion rate is higher than the sum ofthe rates for each alone.

Carbon dioxide in drill.@ fluids may come iiom themakeup water, gas bearing formation fluid inflow, thermaldecomposition of dissolved salts and organic drilling fluidadditives, or backrial action on organic material in themakeup water or drilling fluid additives.

10.1 .1.3 Hydrogen Sutfide

Hydrogen sul6de dissolves in water to form an acid some-what weak and less corrosive than carbonic acid, although itmay cause pitting, particularly in the presence of oxygen and/or carbon dioxide. A more significant action of hydrogen sul-fide is its effect on a form of hydrogen embrittlement knownas sulfide stress clacking (see 10.2 for details).

Hydrogen sulfkle in drilhng fluids may come from themakeup water, gas-bearing formation fluid in&w, bacterialaction on dissolved sulfaks, or thermal degradation of sulfur-containing drilling fluid additives.

10.1 .l A Dissolved Salts

Dissolved salts (chlorides, carbonates, and sulfates)increase the electrical conductivity of drilling fluids. Sincemost corrosion processes involve electrochemical reactions,

the ind conductivity may result in higher corrosionrates. Concentrated salt solutions ate usually less corrosivethan dilute solutions; however, because of decreased oxygensolubility. Dissolved salts also may serve as a source of car-bon dioxide or hydrogen sulfide in drilling fluids.

Dissolved salts in drilling fluids may come from themakeup water, formation ftuid Mow, drilled formations, ordrilling fluid additives.

10.1 .1.5 Acids

Acids corrode metals by lowering the pH (causing hydm-gen evolution) and by dissolving protective ti. Dissolvedoxygen appreciably accelerates the corrosion rates of acids,and dissolved hydrogen sulfide greatly accelerates hydrogenembritt lement.

organic acids (formic, acetic, etc.) can be formed in dlill-ing fluids by bacterial action or by thermal degradation oforganic drilling fluid additives. Organic acids and mineralacids (hydrochloric, hydrofluotic, etc.) may be used duringworkover operations or stimulating treatments.

10.1.2 Factors Affecting Corrosion Rates

Among the many factors affecting corrosion rates of drillstem materials the more important are:

10.1.2.1 pH

This is a scale for measming hydrogen ion concentration.The pH scale is logarithmic; i.e., each pH increment of 1.0represents a tenfold change in hydrogen ion concentration.The pH of pure water, free of dissolved gases, is 7.0. pH val-ues less than 7 ate mcreasingly acidic, and pH values greaterthan7areincreasin gly alkaline. In the presence of dissolvedoxygen, the corrosion rate of steel in water is relatively con-stant between pH 4.5 and 9.5; but it incmases rapidly at lowerpH values, aud decreases slowly at higher pH values. Alumi-num alloys, however, may show increasing corrosion rates atpH values greater than 8.5.

10.1.2.2 Temperature

~general corrosion rates increase with &teasing temper-atlue.

10.1.23 Velocity

In general, corrosion rates incmase with higher rates offlow.

10.1.2.4 Heterogeneity

L.odizd variations in composition or micmstructure mayincrease corrosion rates. Ringworm cormsion, that is some-times found near the upset areas of drill pipe or tubing that

STD.API/PETRO R P ‘IG-ENGL- I,%98 U 0 3 3 2 2 9 0 0 6 0 9 7 3 3 t+SU =

RWOMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING Lwms 6 3

has not been properly heat treated after upsetting, is an exam-ple of corrosion caused by nonuniform grain structure.

10.1.2.5 High Stresses

Highly stressed areas may corrode faster than areas oflower stress. The drill stem just above drill collars oftenshows abnormal corrosion damage, partially because ofhigher stresses and high bending moments.

10.1.3 Corrosion Damage (Forms of Corrosion)

Corrosion can take many forms and may combine withother types of damage (erosion, wear, fatigue, etc.) to causeextremely severe damage or failure. Several forms of corro-sion may occur at the same time, but one type will usuallypredominate. Knowing and identifying the forms of corrosioncan be helpful in planning corrective action. The forms ofcorrosion most often encountered with drill stem materialsXiE:

10.1.3.1 Uniform or General Attack

During uniform attack the material corrodes evenly, usu-ally leaving a coating of corrosion products. The resultingloss in wall thickness can lead to failure from reduction of thematerial’s load-carrying capability.

10.1.3.2 Localized Attack (Pitting)

Corrosion may be local&d in small, well-defined areas,causing pits. Their number, depth, and size may vary consid-erably; and they may be obscured by corrosion products. pit-ting is difficult to detect and evaluate, since it may occurunder corrosion products, mill scale and other deposits, increvices or other stagnant areas, in highly stressed areas, etc.Pits can cause washouts and can serve as points of origin forfatigue cracks. Chlorides, oxygen, carbon dioxide, and hydro-gen sulftde, and especially combinations of them, are majorcontributors to pitting corrosion.

10.1.3.3 Erosion-Corrosion

Many metals resist corrosion by forming protective oxidefilms or tightly adherent deposits. lf these films or depositsare removed or disturbed by h&b-velocity fluid flow, abrasivesuspended solids, excessive turbulence, cavitation, etc., accel-erated attack occurs at the fresh metal surface. This combina-tion of erosive wear and corrosion may cause pitting,extensive damage, and failure.

10.1.3.4 Fatigue in a Corrosive Environment(Corrosion Fatigue)

Metals subjected to cyclic stresses of sufEcient magnitudewill develop fatigue cracks that may grow until complete fail-ure occurs. The limiting cyclic stress that a metal can sustain

for an infinite number of cycles is known as the fatigue limit.Remedial action for reducing drill stem fatigue is discussed inSection 8.

In a corrosive environment no fatigue limit exists, sincefailure will ultimately occur from corrosion, even in theabsence of cyclic stress. The cumulative effect of corrosionand cyclic stress (corrosion fatigue) is greater than the sum ofthe damage from each. Fatigue life will always be less in acorrosive environment, even under mildly corrosive condi-tions that show little or no visible evidence of corrosion.

10.1.4 Detecting and Monitoring Corrosion

The complex interactions between various corrosive agentsand tbe many factors controlling corrosion rates make it difli-cult to accurately assess the potential corrosivity of a drillingfluid Various instruments and devices such as pH meters,oxygen meters, corrosion meters, hydrogen probes, chemicaltest kits, test coupons, etc. are available for field monitoringof corrosion agents and their effects.

The monitoring system “described in Appendix A of APIRecommended Fractice 13B- 1, Recommended Pm&ice Stan-dard Prvcedure for Field Testing Water-Based Drilling Fluids,can be used to evaluate corrosive conditions and to follow theeffect of remedial actions taken to correct undesirable condi-tions. I’mweighed test rings are placed in recesses at the backof tool joint box threads at selected locations throughout thedrill stem exposed to the drilling operation for a period oftime, then removed, cleaned, and reweighed. The degree andseverity of pitting observed may be of greater signil!cancethan the weight loss measurement..

The chemical testing of drilling fluids (see API Recom-mended practices 13B-1 and 13B-2) should be performed inthe field whenever possible, especially tests for pH, a&ah&y,and the dissolved gases (oxygen, carbon dioxide, and hydro-gen sulfide).

10.1.5 Procurement of Samples for LaboratoryTesting

When laboratory examination of drilling fluid is desired,representative samples should be collected in a 1/Z to 1 gallon(2 to 4 liter) clean container, allowing an air space of approx-imately 1 percent of the container volume and sealing tightlywith a suitable stopper. Chemically resisting glass, polyeth-ylene, and hard rubber are suitable materials for most drill-ing fluid samples. Samples should be analyzed as soon aspossible, and the elapsed time between collection and analy-sis reported. See ASTM D3370, Standard Practices for Sum-pZing Water, for guidance on sampling and shippingpl-OCedureS.

When laboratory examination of corroded or failed drillstem material is required, use care in securing the specimens.lf torch cutting is needed, do it in a way that will avoid physi-cal or metallurgical changes in the area to be examined. Spec-

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64 API RECOMMENDED PRACTICE 76

imens must not be cleaned, wire brushed, or shot blasted inany manna, and should be wrapped and shipped in a waythat will avoid damage to the corrosion products or fmcturesurf-. Whenever possible, both fractum surfaces should besupplied.

10.1.6 Drill Pipe Coatings

Internally coating de drill pipe and attached tool joints canprovide effective protection against corrosion in the pipebore. In the pmence of corrosive agents, however, the corro-sionrateofthedrillstemODmaybeincmased.Drillpipecoating is a shop operation in which the pipe is cleaned of allgrease and scale, sand or grit blasted to white metal, plasticcoated and baked. After baking, the coating is examined forbreaks or holidays.

10.1.7 Corrective Measures to Minimize Corrosionin Water-Base Drill ing Fluids

The selection and control of appropriate corrective mea-sures is usually performed by competent corrosion technolo-gists and specialists. Generally, one or more of the followingmeasures is used, but certain conditions may require morespecialized treatments:

a . Control the drilling flluid PH. When practical to do so with-out upsetting other desired fluid pmperties, the maintenanceof a pH of 9.5 or higher will minimize corrosion of steel inwater-base systems containing dissolved oxygen. In someddling fluids, however, corrosion of ahuninum drill pipeins at pH values higher than 8.5.b. Use appmpriate inhibitors and/or oxygen scavengers tominimize weight loss corrosion. This is pafticularly helpfulwith low pH, low solids drill@ fluids. Inhibitors must becarefully selected and controlled, because different corrosiveagents and different drilling fluid systems (particularly thoseused for air or mist drilling) requim different types of inhibi-tors. The use of the wrong type of inhibitor, or the wrongamoun& may actually increase corrosion.c. Useplasticcoateddrillpipe.Caremustbeexercisedtoprevent damage to the coating.d Use degassers and desanders to remove harmful dissolvedgases and abrasive material.e. Limit oxygen intake by maintaining tight pump connec-tionsandby nGnimi&g pit-jetting.f. Limit gas-cutting and formation fluid inflow by maintain-ing proper drilling fluid weightg.Whenthedrillstringislaiddown,stored,ortransported,wash out all drilling fluid residues with fresh water, clean outall corrosion pmducts (by shot blasting or hydmblasting, ifnecessary), and coat all surfaces with a suitable corrosion pm-ventive (see APl Recommen ded Practice 5C1, ReammendedPractice for Care and Use of Casing and Tubing).

10.1.6 Extending Corrosion Fatigue Life

While generally not affecting corrosion rates, the followingmeasures will extend corrosion fatigue life by lowering thecyclic stress intensity or by increasing the fatigue strength ofthe mate&k

a Use thicker-walled components.b . Reduce high stresses near connections by minimi&g dog-legs and by maintaining straight hole conditions, insofar aspossible.c. M’ * - stress concentrators such as slip marks, tongmarks, gouges, notches, scratches, etc.d Use quenched and tempered components.

10.2 SULFIDE STRESS CRACKiNG

10.2.1 Mechanism of Sulfide Stress CrackingWC)

In the presence of hydrogen sulfide (I-Q), tensile-loadeddrill stem components may suddenly fail in a brittle mannerat a fraction of their nominal load-carrying capability afterperforming satisfactorily for extended periods of time. Failuremay occur even in the apparent absence of corrosion, but ismore likely if active corrosion exists. Embrittlement of thesteel is caused by the absorption and diffusion of atomichydrogen and is much mom severe when H,S is present Thebrittle failure of tensile-loaded steel in the presence of H,S istermed sumle stress clacking (SSC).

10.2.2 Materials Resistant to SSC

The latest revision of NACE Standard m-01-75, SuyideStress Cracking Resisimt MetaUic MaSerial for Oil Field Equipmen.& should be consulted for materials that have been found tobe satisfactory for chilling and well servicing operations.

Other chemical compositions, hardnesses, and heat treat-ments should not be used in sour environments without fullyevaldg their SSC susceptibility in the environment inwhich they will be used. Susceptibility to SSC depends on thefollowingz

10.2.2.1 Strength of the Steel

The higher the strength (hardness) of the steel, the greater isthe snsc@ibility to SSC. In general, steels having strengthsequivalenttohardnessesupto22HRCmaximumareresistantto SSC. If the chemical composition is adjusted to permit thedevelopment of a well ternpen& vy marten&cmicrostru~ by proper quenching and temper@; steelshaving stren,gths equivalent to haldrEsses up to 26 HRC maxi-mumaremsistanttoSSC.Whenstrengthshigherthantheequivalent of 26 HRC are required corrective measures (asshowninalateasection)mustbeused;and,thebigherthetiTreq@ required the greater the necessity for the correctivenleamms.

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RECOMMENDED PRACTICE FOR DRU STEM DESIGN AND OPERATING LIMA 65

10.2.2.2 Total Tensile Load (Stress) on the Steel

The higher the total tensile load on the component, thegreater is the possibility of faihue by SSC. For each strengthof steel used, there appears to be a critical or threshold stressbelow which SSC will not OCCW, however, the higher tbestrength, the lower the threshold stress.

109.2.3 Amount ol Atomic Hydrogen and H2S

The higher the amount of atomic hydrogen and H,Spresent in the environment, the shorter the time before failureby SSC. The amounts of atomic hydrogen and H$ requiredto cause SSC are quite small, but corrective measure s to con-trol their amounts will minimize the atomic hydrogenabsorbed by the steel.

10.2.2.4 Time

lime is required for atomic hydrogen to be absorbed anddiffused in steel to the critical concentration required forcrack initiation and propagation to fail=. By controlling thefactors referred to above, time-to-fail= may be sticienflylengthened to permit the use of marginally susceptible steelsfor short duration drilling operations (see Figure 45).

10.2.2.5 Temperature

The severity of SSC is greatest at normal atmospheric tem-ptxatmm, and decreases as temperaWe increases. At opera&ing temperatures in excess of approximately 135°F (57”(J),marginally susceptible materials (those having hardnesseshigher than 22 to 26 HRC) have been used successfully inpotentially embrittling environments. (The higher the hard-ness of the material, the higher the required safe opemtingtempemture.) Caution must be exercised, however+BC fail-ure may occur when the material returns to normal tempera-ture after it is removed fi-om the hole.

10.2.3 Corrective Measures to Minimize SSC inWater-Base Drilling Fluids

The selection and control of appropriate corrective mea-sures is usually performed by competent corrosion technolo-gists and specialists. Generally, one or more of the followingmeasures is used, but certain conditions may require morespecialized treatments:

a Control the drilling fluid PH. When practical to do so with-out upsetting other desired fluid properties, maintain a pH of10 or higher.

Note: In some drilling fluids, aluminum alloys show slowly in-g corm-sionratesatpHvalueshighertban8.5;andtheratemaybecomeexcessiveatpH values higher thau 10.5. lltemfore, in drill strings umtaining aluminumdrill pipe, the pH should not exceed 10.5.

b. Limit gas-cutting and formation fluid inflow by maintain-ing proper drilling fluid weight.c. Minhize corrosion by the corrective measures shown in10.1.7.

Note: while use of plastic coated drill pipe can minimbe corrosion, plasticcoating does not pmtect susceptible drill pipe fmm SSC.

d. Chemically treat for hydrogen sulfide inflows, preferablyprior to encountetig the sulfide.e. Use the lowest strength drill pipe capable of withstandingthe required drilling conditions. At any strength level, properly quenched and tempered drill pipe will provide the bestSSC resistance.f. Reduce unit stresses by using thicker walled components.g. Reduce high stresses at connections by maintainingstraight hole conditions, insofar as possible.

. . .h.- stress concentrators such as slip marks, tongmarks, gouges, notches, scratches, etc.i. After exposure to a sour environment, use care in trippingout of the hole, avoiding sudden shocks and high loads.j. After exposure to a sour environment, remove absorbedhydrogen by aging in open air for several days to severalweeks (depending upon conditions of exposure) or bake at400” to 600°F (204” to 316°C) for several hours.

Note: Plastic coated drill pipe should not be heated above 400°F (204°C) andshould be checked subsequently for holidays and disbanding.

The removal of hydrogen is hindered by the presence ofcorrosion products, scale, grease, oil, etc. Cracks that haveformed (internally or externally) prior to removing the hydra-gen will not be repaired by the baking or stress relief opera-tiOllS.

k. Limit drill stem testing in sour environments to as brief aperiod as possible, using operating procedures that will mini-mize exposure to SSC conditions.

10.3 DRILLING FLUIDS CONTAINING OIL

10.3.1 Use of Oil Muds for Drill Stem Protection

Corrosion and SSC can be minimized by the use of drillingfluids having oil as the continuous phase. Corrosion does notoccur if metal is completely enveloped and wet by an oil envi-ronment that is electrically nonconductive.

Oil systems used for drilling (oil-base or invert emulsionmuds) contain surfactants that stabilize. water as emulsifieddroplets and cause preferential oil-wetting of the metal.Agents that cause cormsion in water (dissolved gases, dis-solved salts, and acids) do not damage the oil-wet metal.Therefore, under drilling conditions that cause serious prob-lems of corrosion damage emsion-corrosion, or corrosionfatigue, drill stem life can be greatly extended by using au oilmud.

260I- - - - - - - - 300,000 psi nominal

240

220

-9 - n 270,000 psi nominal tensile strength-tempered martenSite

- - 230,000 psi nominal tensile strength-tempered martensite

- I l - m . 190,000 psi nominal tensile strength-tempered martensite

- 190,000 psi n o m i n a l t e n s i l e strength-bainlte200 .

- - - 150,000 psi n o m i n a l t e n s i l e strength-tempered m a r t e n s i t e

180 I n n - n l - I 9 - l l 142,000 psi nomlnal t e n s i l e strength-tempered martensite

-II- 75,000 psi nominal tensile strength-peatiite

I1 4 0

8

1 2 0 88

1 0 0 .

I l

+i@q$=

01 I I I I I I

0 . 1 0.5 1 5 1 0 50 100 5 0 0 1 0 0 5000 10,000 100,000

Note:Time to Rupture, Minutes

Batelle Charging Condition A:Electrolyte: 4 percent by weight of H2S0, in water.

Poison: 5 drops per liter of cathodic poison composed of 2, phosphorous dissolved in 40 ml C&.Cumnt Density: 8 ma/in*.

Figure 45-Delayed-Failure Characteristics of Unnotched Specimens of an SAE 4340 Steel During CathodicCharging with Hydrogen Under Standardized Conditions

a-J

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RECWMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING LIMITS 6 7

10.32 Monitoring Oil Muds for Drill StemProtection

An oil mud must be properly prepared and maintained toprotect driU stem from corrosion and SSC. Water will alwaysbe present in an oil mud, whether added intentionally, incor-pmted as a contaminant in the surface system, or fromexposed drilled formations. Corrosion and SSC may occur ifthis water is allowed to become free and to wet the drill stem.Factors to be evaluated in monitoring an oil mud include:

10.3.2.1 Electrical Stability

This test measures the voltage required to cause current toflow between electrodes immersed in the oil mud (see APIRecommended Practice 13B-2, Recommended Practice Stan-dard Procedure for Field Tes t ing Oi l -Based Dri l l ing Fluids ,for details). The higher the voltage, the greater the stability ofthe emulsion, and the better the protection provided to thedrill stem.

10.3.2.2 Alkalinity

The acidic dissolved gases (carbon dioxide and hydrogensullide) are harmful contaminants for most oil muds. Moni-toring the alk&nity of an oil mud can indicate when acidicgases am being encountered so that corrective treatment canbeinstituted.

10.3.2.3 Corrosion Test Rings

Test rings placed in the drill stem bore are used to monitorthe corrosion protection tiorded by oil muds (see API Rec-ommended Practice 13B-2 for details). A properly fimction-ing oil mud should show little or no visual evidence ofcorrosion on the test ring.

1 1 Compressive Service Limits for DrillPipe (see also Appendices A.14 andA.1 5)

11 .l COMPRESSIVE SERVICE APPLICATIONS

11 .l .l Whenever drilling high angle, extended reach, orhorizontal well bo=s it is desirable to use compressivelyloaded portions of the drill string. Drilling with drill pipe incompression causes no more damage to the drill pipe thanconventional drilling operations as long as the operatingconditions do not exceed the compressive service limits forthe pipe.

11 .1.2 Drill strings are subject to compressive service con-ditions whenever significant portions of the borehole exceedthe critical sliding hole angle as defined as follows:

e,=arctatl~ ,G)

where(3, = critical sliding hole angle,f = coefficient of friction.

11 .1.3 The critical sliding hole angle is the angle abovewhich drill string components must be pushed into the hole.Although many factors affect the coefficient of frictionbetween the drill string components and the wall of the hole,the type of drilling fluid used has the greatest impact (seeTable 19). Water-based drilling fluids generate the highestcoefficient to friction and produce critical hole angles ofabout 71 degrees. Synthetic-based drilling fluids provide thelowest coefficients of friction and produce critical hole anglesof about 80 degrees.

11.1.4 Operating sign&ant lengths of the drill string incompression can cause the pipe to helically buckle andinduce pipe curvatures larger than the curvature of the holeand may cause unacceptable bending stresses. Rotating drillpipe iu curved portions of the hole generates cyclic bendingstresses that can also cause fatigue failures. The most effec-tive and efficient drill string design for extended reach andhorizontal holes is the lightest weight drill string that canwithstand the operating environment. Using heavier compo-nents or thicker wall tub&us often increases the operatingloads without reducing the bending stresses.

Table 19-Effect of Drilling Fluid Type onCoefficient of Friction

Billing Fluid

Water-base mud

Oil-base mud

Synthetic-base mud

‘Qpicd Coeffitient Critical Hole Angieof l+iction hz=-

0.35 71

055 76

0.17 80

11.2 DRILL PIPE BUCKLING IN STRAIGHT,INCLINED WELL BORES

11.2.1 Overview

11.2.1 .l The curves shown in Figures 46 through 66 givethe approximate axial compressive loads at which sinusoidalbuckling is expected to occur in drill pipe in straight,inclined wellbores. If the drill pipe is being row limitingthe drill pipe compressive load to below the estimated buck-ling load shown in these curves will significantly reduce thedanger of fatigue damage to the pipe. Conversely, rotatingdrill pipe while it is buckled can lead to rapid fatigue damageand failure.

11.2.1.2 These curves are based on the equations of Daw-son and Paslay.= They are reproduced here with permissionfrom Standard DS-1, Drill Stem Design and Znspection.28 Theassumptions behind these curves include:

a Pipe weight is new nominal with X-grade tool jointdimensions (where applicable). If more than one tool joint is

(Text continu& on page 78.)

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Figure 47-Approximate Axial Compressive Loads at which Sinusoidal Buckling is Expected to Occur

STD.API/PETRO R P 7G-ENGL L=l=lB - 0 7 3 2 2 9 0 0 6 0 9 7 3 9 979 m

RECOMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERAnNG LIMITS 69

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Figure 48-Approximate Axial Compressive Loads at which Sinusoidal Buckling is Expected to Occur

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Figure 49-Approximate Axial Compressive Loads at which Sinusoidal Buckling is Expected to Occur

STD.API/PETRO R P 7G-ENGL 1998 - 0 7 3 2 2 9 0 0 6 0 9 7 4 0 690 m

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Figure W-Approximate Axial Compressive Loads at which Sinusoidal Buckling is Expected to Occur

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Figure 51-4pproximate Axial Compressive Loads at which Sinusoidal Budding is Expected to Occur

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Figure 52-Approximate Axial Compressive Loads at which Sinusoidat Buckling is Expected to ( :ur

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Figure 53-Approximate Axial Compressive Loads at which Sinusoidal Buckling is Expected to mur

STD.API/PETRO R P 7G-ENGL L998 - 0732290 Oh09742 4b3 m

72 API REKMENCJED PFWCTICE 7G

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Figure 54-Approximate Axial Compressive Loads at which Sinusoidal Budding is Expected to 0cc1

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STD.API/PETRO R P 7G-ENGL L998 - 0 7 3 2 2 9 0 0609743 3 T T -

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Figure 56--Approximate Axial Compressive Loads at which Sinusoidal Buckling is Expected to &cur

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Figure 57-&Proximate Axial Compressive Loads at which Sinusoidal Buckling is Expected to &cur

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Figure W-Approximate Axial Compressive Loads at which Sinusoidal Buckling is Expected to Occur I

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Figure 59-Approximate Axial Compressive Loads at which Sinusoidal Budding is Expected to Occur

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6 10 12 14 16 16 2 0 2 2 2 4Hole size (inches)

Figure GO-Approximate Axial Compressive Loads at which Sinusoidal Buckling is Expected to Occur

I I.-...j.....; . . . . !......I . . . . i . . !......I . .I . l..... l...... i ..-

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j ; j i i, I, . : :,.... i

., . . i : ! i ! /

08 10 1 2 14 16 16 2 0 2 2 2 4

Hole size (inches)

Figure 61-Approximate Axial Compressive Loads at which Sinusoidal Buckling is Expected to Occur

STD.API/PETRO A; 7G-ENGL 1998 m 0 7 3 2 2 9 0 Ob0974b 0 0 9 -

7 8 API RECQMMENDED PFWXICE 76

:::: G.....! . . . . ..I . . . . . + . . ..I) . . ...! . . . . . f . . ...) . . . . i . . . . !- . . . . 4

5%inch. 19.20 Drf-L ,

12 ppg mud

.

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f$$h\

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8 lb Ii 14 16 18 20 22 24Hole size (inches)

Figure 62-Approximate Axial Compressive Loads at which Sinusoidal Budding is Expected to 0cc1

Figure

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I Ie l b 12 14 18 1 8 2 0 2 2 2 4Hole size (inches)

63-Approximate Axial Compressive Loads at which Sinusoidal Budding is Expected to Occur

ur

S T D . A P I / P E T R O R P 7G-ENGL L998 - 0 7 3 2 2 9 0 0 6 0 9 7 4 7 T45 m

RECXMMENDED PRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS 7 7

7oooo

10000

0

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8 10 12 14 18 1 8 2 0 22 2 4Hole size (inches)

Figure 64-Approximate Axial Compressive Loads at which Sinusoidal Buckling is Expected to Occur

10 12 14 16 18Hole size (inches)

2 0 2 2 2 4

Figure 65-Approximate Axial Compressive Loads at which Sinusoidal Buckling is Expected to Occur

STD.API/PETRO R P 7G-ENI;L I,998 m 07322qO 0609748 981 -

76 API RECOMMENDED PRACTICE 7G

-300 .:::f ::::::i

-ii

. . . . . . . I . . . . . . I......: . . . . .

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16 12 14 16 18 20 22 24Hole size (inches)

Figure 66-Approximate Axial Compressive Loads at which Sinusoidal Buckling is Expected to Occur

used on a particular pipe, the most common one was selected.Tool joint diameter is the minimum for Premium class.Radial clearance is the distance between the tool joint ODand the hole.b. Pipe wall thickness is new nominal.c. The wellboreisstraight.d The effects of tonpe are neglected.e. Mud weight is 12.0 lb/gal.

11.2.2 Compensating for Different Mud Weightlf the actual mud weight is not 12.0 lb/gal, criticzd buckling

load may be adjusted by the following form&x

WhfS?F-z adjusted critical buckling load (lb@,

Fd = critical buckling load from curve (lbs),fmv = (buoyancy f&ctor/O.817)0~ (see below),

Mud Weight Mudweight

0 f, WIZN f,8.0 1 . 0 4 14.0 0.989.0 1 . 0 3 1 5 . 0 0 . 9 7

1 0 . 0 1 . 0 2 16.0 0.961 1 . 0 1 . 0 1 1 7 . 0 0 . 9 51 2 . 0 1 . 0 0 1 8 . 0 0 . 9 41 3 . 0 0 . 9 9 1 9 . 0 0 . 9 3

11.2.3 Using the Drill Pipe Buckling Curves

Enter the curve for the correct pipe size and weight at thehole diameter. Read vertically to intersect the hole angle, theuhorizontally to read critical buckling load. Compensate thevalue obtained for mud weight beiug used.

11.2.3.1 Example

How much compressive load may be applied to Sinch,19.50 lb/ft drill pipe in a 12V&ch horizontal hole before thedrill pipe buckles? Mud weight is 9.0 lb/gal.

11.2.3.2 Solution:

Reading from the figure for the drill pipe in question (Fig-ure 60), the critical buckling load is about 28,200 pounds.Adjusting to 9.0 lb/gal mud:

Fm = 28,200 lbs (1.03) = 29,000 lbs

11.3 CRITICAL BUCKLING FORCE FOR CURVEDBOREHOLES--‘*=

The critical buckling force of compressively loaded dfillpipe is also significautly influenced by the curvature of theborehole. In angle building intervals the upward curvatme ofthe borehole increases the critical buckling force. In tumiugintends the hole curvature also increases the buckling forceof the drill pipe. Table 20 shows the hole curvature rates thatprevent buckling for a range of pipe and hole sizes.

STD.API/PETRO R P 7G-ENGL I,998 - 0 7 3 2 2 9 0 0609749 BLB -

RECOMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING LIMITS 79

Table 2O-Hole Curvatures that Prevent Buckling

Hole DrillPipe Drill F’ipe Nominal Tool Joint AxialLoad

Size OD lD weigh OD SMlbs 10 Mlbs EMlbs 24mnbs 2sMlb.s 3oMlbs 4oMlbs 5oMlbs

4 . m 2.375 1.815 6.7 3.125 4.9 6.2 7.4 9.9 12.3

4.750 2.875 2.151 10.4 4.125 0.4 0 . 8 1.2 1.6 2.0 2.4 3.2 3.9

6.000 2.875 2.151 10.4 4.125 1.2 2.4 3.5 4.7 5.9 7.1 9.5 11.86.000 3.5wl 2.764 13.3 5.000 0.3 0.6 1.0 1.3 1.6 1.9 2.6 3.2

6.750 3.500 2.764 13.3 5.000 0.6 1.1 1.7 2.3 2.8 3.4 4.5 5.66.750 4.m 3.340 14.0 5.250 0.3 0.7 1.0 1.3 1.7 2.0 2.7 3.4

7.875 4.aKl 3.340 14.0 5.250 0.6 1.2 1.8 2.4 3.0 3.5 4.7 5.97.875 4.500 3.826 16.6 6.250 0.2 0.5 0.7 1.0 1.2 1.5 2.0 2.5

8.750 4.500 3.826 16.6 6.250 0.4 0.8 1.1 1.5 1.9 2.3 3.0 3.88.750 5.Ocm 4.276 19.5 6.375 0 2 0.5 0.7 1.0 1.2 1.4 1.9 2.48.750 5.500 4.778 21.9 7.m 0.1 02 0.3 0.4 0.5 0.6 0.8 0.98.750 5.500 4.670 24.7 7.250 0.1 0.2 0.3 0.4 0.5 0.6 0.8 1.0

9.875 5.ocm 4.2769.875 5.500 4.7789.875 5.500 4.6709.875 6.625 5.%5

19.521.924.725.2

19.521.924.725.2

6.375 0.4 0.7 1.1 1.4 1.8 2.1 2.8 3.67.5cQ 0.2 0.4 0.5 0.7 0.9 1.1 1.4 1.87.250 0.2 0.4 0.5 0.7 0.9 1.1 1.4 1.88.000 0.1 0.2 0.3 0.3 0.4 0.5 0.7 0.8

12.25012.25012.25012.250

11.3.1

5smo 4 2 7 65.500 4.7785.500 4.6706.625 5.%5

6.375 0.6 1.2 1.8 2.4 3.0 3.6 4.8 6.07.500 0.4 0.7 1.1 1.4 1.8 2.1 2.9 3.67.250 0.3 0.7 1.0 1.3 1.7 2.0 2.7 3.48.am 0.2 0.4 0.6 0.8 1.0 1.1 1.5 1.9

Example ing of the tool joints, as well as the axial compressive load onthe pipe and the curvature of the hole.

Will 5inch drill pipe buckle in a lO-degrees-per-lOO-footbuild curve of a horizontal well? The hole size is 8.75 inchesandthemaxim urn required bit load is 30,000 pounds.

11.3.2 Solution

Table 20 shows that 5-inch, 19.5 lb/ft drill pipe in an 8.75-inch hole will not buckle in hole curvatures greater than 1.4degrees per 100 feet witb a 30,000 pound load.

11.4 BENDING STRESSES ON COMPRESSIVELYLOADED DRILL PIPE IN CURVEDBOREHOLES33p34

Rotating compressively loaded drill pipe in curved portionsof the borehole generates cyclic bending stresses that, if largeenough, may cause fatigue damage. Compressive’ loadingmay also cause a portion of the pipe body to contact the wallof the hole. In abrasive formations, pipe body contact canerode the body of the pipe and further magnify the bendingstresses. The maximum bending stress caused by compres-sively loading drill pipe in curved boreholes is tie&d by thesize of the tool joints, the size of the pipe body, and the spac-

The application of compressive loads on tool jointed drillpipe in curved boreholes progresses through three stages.Under light loads, the maximum bending stress occurs in thecenter of the pipe span but only the tool joints are in contactwith the wall of the borehole. As loading is increased, thecenter of the pipe comes into contact with the wall of thehole. Under this loading condition the maximum bendingstress occurs at two positions that are located on either side ofthe point of pipe body contact As the load is furtherincreased, the length of pipe body contact increases frompoint contact to wrap contact along a length of pipe located inthe center of the joint.

Figures 67 through 74 provide solutions to the bendingstress, pipe body contact, and lateral contact loads for themost common sizes of 6V,-inch to 23/,-inch drill pipe. Themare four plots for each size of drill pipe. The plot in figures67-74 (figures a) show the maximum bending stress as afunction of axial compressive load for a range of hole curva-tures. The type of loading is shown by the style of the plottedlines. For no pipe body contact, the bending stress curve isshown as a solid line. For point contact the bending stressrelation is shown as a dashed line and for wrap contact the

(Text continued on page 96.)

S T D . A P I / P E T R O R P ?G-ENGL 1’398 - 0 7 3 2 2 9 0 Ob09750 53T -

80 API REIZOMMENDED PFUCI-ICE 76

6.625~in. 25.2 Wft Drill Pipe, &in. Tool Joint10 ppg mud, go-degree 12.25-in. hole

4 0

3 5

30

2 5

2 0

15

10

5

0

30 40 50 60 7 0

Axlal compressive load-1000 lb.

Figure 67a-6ending Stress and Fatigue Limits

STD.API/PETRO R P 7G-ENGL I,998 - 0 7 3 2 2 9 0 ObO=l75l, 476 -

REWMMENDED PRACTICE FOR DRIU !ZSM DESIGN AND OPERATING LIME 61

6

4

2

0

10

5

0

6.625-in. 25.2 Ib/ft Drill Pipe, 8in. Tool Joint10 ppg mud, go-degree 12.2~in. hole

lOd/h

0 10 2 0 3 0 4 0 5 0 7 0Axial compressive had-1 000 lb.

2odol

Figure 67b-Lateral Contact Forces and Length

STD.API/PETRO RP 7G-ENGL I,998 m 0732290 0609752 302 W

8 2 API RECC~WAENDED PFSACIICE 76

3 0

2 5

wCL

15

M-in. 21.9 lb/f! Drill Pipe, 7.5in. Tool Joint10 ppg mud, 90-degree 9.87~in. hole

10 20 30 40 50 60 7 0

Axial compressive load-1000 lb.

Figure 88a-Bending Stress and Fatigue Limits

STD.API/PETRO R P 7G-ENGL I,998 - 0 7 3 2 2 9 0 Ob09753 249 -

REC~OMMENDED PFUCTICE FOR DRIU STEM DESIGN AND OPEFWT~NG LIMITS 6 3

5.5~in. 21.9 Ib/ft Drill Pipe, 7.5~in. Tool Joint10 ppg mud, 90-degree 9.875-in. hole

2odnl

lOd/h

5

;

I I I‘-‘~,....(....&

I I I f v2odh1... 1*,, ,,,I10 2 0 io

I I I a

io’ 1 I I Ily

6 0 7 0Axial mmpressive load-l 000 lb.

Figure 68b-Lateral Contact Forces and Length

STD.API/PETRO R P 7G-ENGL 1998 - 0 7 3 2 2 9 0 Db09754 LB5 -

5 4 API RECOMMENDED PFUCTI~IE 76

40

35

30

25

20

15

10

5

0

5in. 19.5 Wft Drill Pipe, 6.375in. Tool Joint10 ppg mud, g&degree 8.50~in. hole

20 30 40 50 50Axlal axnp~~ssiwa load-1000 lb.

Figure 69a-Bending Stress and Fatigue Limits

S T D . A P I / P E T R O R P 7G-ENGL I1998 - 0 7 3 2 2 9 0 0609755 OLL m

RECXMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPEFIATING Lwrs 66

d3E84IL

Sin. 19.5 Ib/ft Drill Pipe, 6.375in. Tool Joint10 ppg mud, go-degree MO-in. hole

10I

t ’I

3 1 I -.-- - --..

$5- I I I I

0

0 10 20 30 40Axial compressive load-l 000 lb.

Figure 69b-Lateral Contact Forces and Length

S T D . A P I / P E T R O R P ?G-ENGL L998 - 0732290 0609756 T58 -

6 API RECOMMENDED PFIACIICE 76

40

35

30

25

20

15

10

5

0

4.5-in. 16.6 IbBI Drill Pipe, 6.25-in. Tool Joint10 ppg mud, go-degree 8.50-in. hole

i A-i i i i i i i i -4 - t I L LA +-i-77- -

20 30 40 50Axial ComplBssive load-1000 lb.

Figure 70a-Bending Stress and Fatigue Limits

STD.API/PETRO R P 7G-ENGL 1998 D 0 7 3 2 2 9 0 0609757 =l=lY W

RECOMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERAmNG LIMITS 8 7

8

0

4.5-in. 16.6 Ib/ft Drill Pipe, 6.25-in. Tool Joint10 ppg mud, go-degree 8.50-in. hole

II I I I I I I I I I I I i II I I I II I t t II

10

5

0 #I3-

3odfh

2om

lOd/h

0 10 2 0 ioAxial compressive load-l 000 lb.

4i 5il

3odn-l

2odh

Figure 7Ob-Lateral Contact Forces and Length

STD.API/PETRO RP 7G-ENGL la998 - 0 7 3 2 2 9 0 0 6 0 9 7 5 8 8 2 0 -

88 API REWMMENDED PRACTICE 7G

2 5

4.0-in. 14.0 Ib/ft Drill Pipe, 5.25-in. Tool Jointwith 10 lb/gal mud in a 6.75in. hole

I I I I I I I I I I I , ,I , , 1 I I I

. . lol I I I I I II I I I III I I I I II:J ’ ’ ’ ’ I I I 1 1 J I I I I I J I

0 10 20 30Axial compressive luad-1CKMl lb.

40 50

Figure 71 a-Bending Stress and Fatigue Limits

S T D . A P I / P E T R O R P 7G-ENGL 1996 - 0 7 3 2 2 9 0 0609759 767 m

RECOMMENDED PRACTICE FOR DRIU S-EM DESIGN AND OPERATING LIMITS 8 9

4.0-in. 14.0 Wft Drill Pipe, 5.25in. Tool Jointwith 10 lb/gal mud in a 6.75-in. hole

3odh

2odh

1odh

6 I I I I I I I I I I I I I I I I I I II I I i I

3odm

10

1 3od/hs” 5 2odlh

1odnl0

0 1 0 2 0 3 0Axhl compressive load-l 000 lb.

40 50

Figure 71 b-Lateral Contact Forces and Length

STD.API/PETRO RP 7G-ENGL L=l=l8 m 0 7 3 2 2 9 0 0 6 0 3 7 6 0 4 8 9 -

0 API REWMMENDED PRAC~CE 7G

40

35

30

25

20

15

10

5

0

3.5in. 13.3 Wft Drill Pipe, 4.75in. Tool Jointwith 10 lb/gal mud in a &in. hole

I I I I I I II II& IIII n I I I

0 10 20 30 40Axlal ampImsive l&1000 lb.

Figure 7%-6ending Stress and Fatigue Limits

STD.API/PETRO R P 7G-ENGL I,998 - 0732290 ObO=l7bl, 3L5 m

RECXJMMENDED PRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS 9 1

3.5~in. 13.3 IbAt Drill Pipe, 4.75-in. Tool Jointwith 10 lb/gal mud in a 6-in. hole

6

4odRl

*P

i

43odn-l

2

58 zodhi i 2

1odih

0

15

10

5

0

I I I I I I II I I I I I I

1 I I I I 1 I

2 0 3 0

Axial compressive load-l 000 lb.

Figure 72Hateral Contact Forces and Length

STD.API/PETRO R P 7G-ENGL I,998 - 0732290 Ob097b2 251 -

2 API REWMMENDED PRACI-ICE 76

40

35

30

25

20

15

10

5

0

2.875in. 10.4 Wft Drill Pipe, 4.125-in. Tool Jointwith 10 lb/gal mud in a 4.7~in. hole

0 5 10 15Axialc0mpre&ve load-1000 lb.

20 25

Figure 73a-Bending Stress and Fatigue Limits

STD.API/PETRO R P 7G-ENGL 1998 D 0 7 3 2 2 9 0 0609763 198 -

REWMMENDED PRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS 93

2.875in. 10.47 Ib/ft Drill Pipe, 4.125-in. Tool Jointwith 10 lb/gal mud in a 4.75in. hole

6

I Icn 5od/hP

4

4

$4odth

8

83odfh

P 22odfh

1odh

0

15

10

5

0

t

-3 0 4 0 50 ‘al 7b

Axial compressive load-l 000 lb.

Figure 73b-Lateral Contact Forces and Length

S T D . A P I / P E T R O R P 7G-ENGL I,998 m 0 7 3 2 2 9 0 Ob097b4 024 m

94 API RECOMMENDED PRACTICE 7G

40

35

30

25

20

15

10

5

0

2.375in. 6.65 Wft Drill Pipe, 3.125~in. Tool Jointwith 10 lb/gal mud in a 3.67~in. hole

.

. . . :

. 1 .

. * .

. - !

. . .

. , ;

0 5 10 15 20 25AxialaxnpressiW3 load-l 000 lb.

Figure 74a43ending Stress and Fatigue Limits

STD.API/PETRO R P ?G-ENGL I,998 m r3732290 0609765 TbO -

REWMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING LIMITS 9 5

2.375-in. 6.65 Ib/ft Drill Pipe, 3.125in. Tool Jointwith 10 lb/gal mud in a 3.875-in. hole

6ocnl

4od/h3odh2odRl

1odh

15

10

5

0

4odnl

3odh

2odh

1odh

1 0 1 5

Axial compressive load-l 000 lb.2 5

Figure 74Hateral Contact Forces and Length

STD.API/PETRO RP 7G-ERGL J,=Jqa m 07322qo Obnq7bb 9T7 m

96 API RECOMMENDED PFIACTICE 76

plotted stress is shown as a dotted line. The plots also includethe f&gue endurance bending stress limits from Section 11.5.The plots assume a 10 lb/gal mud, 9O-degree hole angle, anda defined hole size. The mud density, hole angle, and holesize do not tiect the bending stresses unless the pipe buckles.On most of the plots the critical buckling force is onlyexceeded for cases with zero or negative build rate. The bend-ing stresses for buckled pipe are independent of the hole cur-vature and generally follow curves in which the bendings t r e s s i n - more rapidly with increased axial load thanfor the constant hole curvature cases.

The plots in Figures 67-74 (figures b) show the pipe bodyconfacf length and the lateral contact forces between the pipebody and the tool joints with the wall of the hole.

11 A.1 Example

An Br/,-inch horizontal well will be drilled with 5-inch19.50 lb/ft drill pipe with 6Y,-inch tool joints in an Bl/,-inchhole with 10 lb/gal mud The maximum hole curvatute willbe 16 degrees per 100 feet. The horizontal interval will bedrilled with surface rotation with loads up to 35,000 pounds.What grade of drill pipe is required for this example?

11 A.2 solution

11.4.2.1 Figure 69a shows the bending stresses and fatiguelimits for 5-&h, 19.5 Wft drill pipe, with 63/s-inch tool jointsin a 9Odegree, B1/&ch hole with 10 lb/gal mud For a holecmvatum of &degrees-per-lOO-feet and an axial compms-sive load of 35,000 pounds, the maximum bending stress is24,000 psi. A slightly higher bending stress of 25,000 psi isprodud by a 24,000 pound axial load. The maximum bend-ing sttesses exceeds the fatigue endurance limitsforAHGrade E75, X95, and D55 pipe, but is less than the fatigueendurance limits for grades G105 and S135 pipe. Figure 69bshows that at 35,000 pound axial load, the tool joint contactforces would be about 2,600 pounds with a 16 degrees per1OOfootcurvammrate.ThepipebodycontaCtfomewillbe

about 600 pounds under a 35,ooO pound axial load. For thiscurvatureratethecontactwillbeatthecenterofthespan.

11.4.22 The maximum bending stresses for point andwrapcontactaredirectlypmportionaltotheholecurvaunesandmdialcleamncesbetweenthepipebodyandthetooljoints. This allows us to use the existing bending stress plotsto e&mate the bendiug stresses for tool joint dimensionsother than used in preparhg the plots. No adjustment is nec-essary unless the loading condition produces point or wrapcontact- If this is the case, we can compute an adjustment fac-torfromtheactualsizeofthet~ljointanduse~tocom-pte an equivalent hole curmtumtideterminethecorrectbendingstress.

11.4.3 Example

Determbe the maximum bending stresses for Cinch, 14lb/l3 drill pipe with 53/g-inch tool joints in 2Odegreesper-lOO-foot hole curvature, and a 20,000 pound axial eompres-sive load.

11 A.4 Solution

Figure 71a shows the bending stresses for 4-&h, 14 lb/ftdrill pipe, with 5l/&ch tool joints. The actual tool joint out-side diameter is 53/,-inch or i/,-inch larger. Figure 75 showsthe hole curvature adjustment factors for various sixes of drillpipe as a function of the ditkence in the tool joint outsidediameters. For an actual tool joint, i/,-inch larger than nomi-nal, Figure 75 shows that with 4-inch drill pipe the curvatureadjustment factor is 1.1. To determine the maximum bendingstress for the l/s inch larger tool joint in a 2O-degrees-per-lOO-foot hole curWure at 20,000 pound load, multiply the actualhole cmvature by the adjustment factor, 2Odegrees-per-lOO-feet times 1.1 = 22-degrees-per-loo-feet, Using 22degrees-per-lOO-feet at 20,000 pounds on Figure 71a, the bendingstress for 53/,-inch tool joints is 24,500 psi.

11.5 FATIGUE LIMITS FOR API DRILL PIPE

R. E? Morgan and M. J. Roblin35 developed a method ofmeasuring fatigue limits from small drill pipe samples. Theirtechnique preserves the effect of the “as produced’ drill pipehot finish surfaces. They reported on the testing of AHGrades E75, X95, G105, and S135 as well as an experimentalhigh strength tubular identified as V180. Their test programshowed that the fatigue endurance limits for drillpipe corre-late well with the tensile strength of the pipe. Table 21 showssome of the results of their test program.

Table 21-Youngstown Steel Test ResutW

Avaage J!mllmmceIimitAPI A P I API Tknsile. .Mlmmlml Yllld Tensile SkeqthM” M e d i a nYd strell& strength of-kst -Ikst nst

Gla&s~Maximum-sampl~ valle v a l u e

ksi ksi ksi ksi ksi ksi

E75 7 5 1 0 5 1 0 0 1 2 3 3 0 3 2

x95 95 1 2 5 1 0 5 1 3 2 3 2 3 5

G105 1 0 5 1 3 5 1 1 5 1 4 4 3 4 38

5 1 3 5 1 3 5 1 6 5 1 4 5 1 6 7 3 6 4 0

*Youugstom Sheet and l-the Company 1969 ASME -ce?uOklahoma

Casn~hasutilizedtheirtestresultstodeterminethemin-imtun fatigue endurance limits for Am apipe that meetstheAPI minimum strength requirements. See Table 22.

STD.API/PETRO R P ? G - E N G L L998 - 0 7 3 2 2 9 0 0609767 8 3 3 m

RECOMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING Lltms 97

1.30

FF1.20

1.10

I I

it-

-

5

-0.125 0 . 0 0 0 0.125

Actual TJ minus nominal TJ-in.

0 . 2 5 0 0.375

Figure 75-Hale Curvature Adjustment Factor To Allow for Differences in Tooljoint ODs

S T D . A P I / P E T R O R P 7G-ENGL L998 - 0 7 3 2 2 7 0 ObO=l768 7 7 T m

98 /iPt RECQMMENDED PRACTICE 76

TaMe 22-Fatigue Endurance Limits CompressivelyLoaded Drill Pipe

A P I APIM i n i m u m MinimumTensile M” Fatigue

Yield Strength =wm EhduranceIimit

ksi ksi ksi

E75 7 5 1 0 0 22.0

x95 9 5 1 0 5 23.1

Cl05 1 0 5 1 1 5 25.3

s135 1 3 5 1 4 5 31.9

11.6 ESTIMATING CUNlULATlVE FATIGUEDAMAGE

An interesting alternative to operating below the fatigueendumuw limits for drill pipe is to monitor the cumulativefatigue damage caused by rotatiug in high curvature intervalsof the borehole and retire the pipe before faihues occur. Theconcepts for tracking the cumulative fatigue damage havebeen well developed by Hansford aud Lubinski.37J8 The keytowanls successful use of this technique is establishing theappmpriate stress versus revolutions to failure curves for thevarious grades of API drill pipe. Figures 76 and 77 provide.e&mates of the median expected failure limits found by Mor-gan and Robliu and au estimate of the minimum failum limitsof API drill pipe that has been manufactured to average APIpropedes. We would expect that half of the drill pipe exposedto the limits shown in Figure 76 would fail. The minimumfailure limits in Figure 77 should avoid fatigue failures ontypical API drill pipe. The mediau failure limits are based onan exponential nAationship that connects the average tensilestrength of the tested specimens representing one revolutionto failure with the median fatigue endurance limits represent-ing one million cycles to failure. The average tensile strengthvalues and the median fatigues endurance limits from Table21 were used to develop the stress versus revolutions to fail-ure curves shown in Figure 76.

Theequationisofthefornu S = z

wheres = bendingstresslimi~psi,

23 = tensile sttmgtb of pipe, psi,N = revolutions to failure,x = a lkactional exponent of about D. 1.

Thecurvesofminimum fail~hmitsarealsobasedoutheMorgan and Roblin data Their report includes a table thatdefines the typical yield and ultimate tensile strengths for nor-malizedGradeE75,normakedandtemperedGradesX95aud G105, and quenched tempered Grade S135 API drillpipe. Using Casner’s defmed 0.22 ratio we computed the

Table 23-Values Used in Preparing Figure 77

ExpededUltimate hhimumFat&ueStrength and Fat igue stress Limit for

‘Isrpical StmsLimitforChe 1,~,~Yield Stmgth Revolution RWOhltim

ksi ksi ksi

E75 87.5 121.5 26.7

x 9 5 103.0 131.5 28.9

G105 124.0 149.5 32.9

s135 150.0 159.0 35.0

fatigued endurance limits for these tensile strengths. The SNcurve was computed by using the exponential relationshipdescribed above with the tensile strength equal to the fatigueendurance limit for one revolution and the fatigue endurancelimit values to represent the stress limit for one million revo-lutions. The values used to prepare Figure 77 are s * ;din Table 23.

The cumulative fatigue damage is de&mined by countingthe revolutions of pipe in highly curved portions of the bore-hole where the stresses exceed the fatigue endurance limits.If, for example, the revolutions iu a particular section of holerepresent 20 percent of the predicted revolutions to failure forthat dogleg severity it is judged that 20 percent of the fatiguelife has been consumed Figures 76 and 77 can be used tojudge inspection levels and ultimate retirement levels. Theultimate life can be judged from the plot of the medianfatigue limits of Figure 76. The appropriate minimum inspec-tion levels can be judged from the minimum fatigue limits ofFigure 77. After exposure to this level of fatigue, mspectionand removal of damaged joints can extend the remaiuingstring life to or beyond the expected mediau life levels.

Figmes 78 through 80 am plots of the bending stresses for31/,-inch, 2’/&ch, and 23/,-inch drill pipe in highly curvedboreholes. The bending stresses dekrmined from these plotsare used to determine the total number of revolutions that thepipe can withstand from Figures 76 and 77. These are thencompared to the observed number of revolutions to determmethe level of fatigue damage. The ratio of the revolutions to thepredicted median revolutions to failure defines the fraction ofthe drillplpefatigue life consumedin drilling through the highcurvatute hole.

11.6.1 Example

An example of the cumulative fatigue damage calculationsis given by the following. Consider drilling a 500-foot hori-zontal hole below a lOO-foot mdius build curve with 3’/,-inchs135 drill pipe. Drill pipe will be rotated at 30 RPM with10,600 WOB, and is expected to drill at 15 feet per hour. Theequivalent build rate is given by:

PJ

Maximum bendlng stress-ksi

8 8 8 21

Iv/

I

I

8

STD.API/PETRO R P 7G-ENGL L=l=ltl D 0 7 3 2 2 9 0 0 6 0 9 7 7 0 3 2 8 -

loo API RE~IJMMENDED PRACTICE 76

75

70

65

60

40

35

30

25

-

1000

-

\

-

\

-

\-

\-

-

-

-

-

-

\

\

1\

-

-

-

-

\

\

-

\

t

-

-

-

10,ooo

Revoluticns to failum

100,000

Figure 774inimum Failure Limits for API Drillpipe Noncorrosive Service

STD.API/PETRO R P 7G-ENGL la998 - 0 7 3 2 2 9 . 0 0 6 0 9 7 7 1 264 m

REWMMENDED PRACTICE FOR DRIU SIEM DESIGN AND OPERmNG Lwrs 101

B - 5730R

whereB = build rate, degrees/100 R,R = build radius, ft.

For this case: B 5730= - = 57.3 degreesZ1OOft.100

11.6.2 Solution

Figure 78a shows that at 10,ooO pound axial compressiveload and a 57-degrees-per-100-foot build rate the maximumbending stress is 50,000 psi. Figure 76 predicts that half of theS135 pipe will fail under a 50,000 psi bending stress after110,000 revolutions. The minimum failure limits of Figure 77pre4lict that s135 pipe can be rotated 39,uOO revolutions with-out faihlre.

The number of revolutions of exposure is given by:

N _ 6OxLxRPMROP

whereN = revolutions of exposure,L = length of high curvature hole, R,

RPM = rotaq speed rev/mill,R O P = penetrat ion rate , ft/hr.

The length of L of our 90 degree build curve is equal to:

L=;xR=;xlOO = 157ft.

Therefore, the number of revolutions of exposure for thepipe that is rotated through the build curve is equal to:

N = 60x157~3015 = 18,850 revolutions

The cumulative damage can be computed by comparingthe revolutions of exposure to the 110,000 revolutionsrequired to cause half of the pipe to fail. This suggests that 17percent of the fatigue life of the affected pipe has been con-sumed in drilling one well. Comparing the revolutions ofexposure to the minimum fatigue limit of 39,000 revolutionsevaluates the risk of a failure. For this case, the 18,850 revolu-tions of exposure represents 48 percent of the minimumfatigue life expected for the S 135 pipe. This suggests that twowells could be drilled with this string before inspecting anddowngrading or removing fatigue damaged joints from ser-vice. Continued use of the string will require removing signif-icant portions of the affected pipe in order to prevent failures.

11.7 BENDING STRESSES ON BUCKLED DRILLPIPE

The bending stresses on buckled drill pipe must accountfor both the mechanics of buckling and the additional bend-ing caused by the axial load and the tool joints. The curvatumproduced by buckling is given by:

BFxh,x57.3x12x 100

but = 2xExZ

B but =

17190 x F(D, - QJExZ

whereB&C = curvature of buckled pipe, “/lo0 ft.,

F = axial load, lb.,DA = hole diameter, in.,D, = tool joint OD, in.,h, = radial clearance

D,-Dtj .= -,m.,2

Z = atea moment of menial of pipe, in.4,E = Young’s modulus, psi

= 30 x 106 psi for steel.

This curvature can be used in place of the hole curvature inthe equations covenxl in Section 11.4.

12 Special Service Problems12.1 SEVERE DOWNHOLE VIBRATION

Downhole vibration is inevitable. In many cases, low levelsof vibration go undetected and are harmless. However, severedownhole vibration can cause driUstring fatigue failure(washout/twistoE), crooked drillstrings, premature bit fail-ure, and reduced penetration rates. The main sources of exci-tation are provided by the interaction of the bit with theformation and the drillstring with the wellbore. The drillstringresponse to these excitation sources is very complex.

Vibration can induce three components of motion in thedrillstring and the bit, namely: axial (motion along drillstringaxis), torsional (motion causing twist/torque) and lateral (sideto side motion). All three dynamic motions may coexist andone motion may cause another.

While theories exist, there is no general agreement on howto predict (calculate) when damaging vibrations will occur.However, by observing the symptoms of severe downholevibrations, probable mechanisms may be determined andappropriate corrective actions taken.

Severe downhole vibration is often accompanied by symp-toms belonging to more than one mechanism This fact makesthe detection of the primary mechanism more diflicult For

(Text continued on page 108.)

STD.API/PETRO R P 7G-ENGL 1998 D 0 7 3 2 2 9 0 0 6 0 9 7 7 2 1TO -

1 0 2 API RECXJMMENMD PFWTICE 76

3.5 in. 13.3 Ib/ft Drill Pipe, 4.75 in. Tool Jointwith 10 lb/gal mud in a 6 in. hole

aP

20Axial Mlmpressive load-1000 lb.

Figure 78a-Bending Stress for High Cuwatures

STD.API/PETRO R P 7G-ENGL 1998 - 0 7 3 2 2 9 0 0 6 0 9 7 7 3 0 3 7 -

RECOMMENDED PRACTICE FOFI DRIU STEM DESIGN AND OPERATING LIMITS 103

3.5 in. 13.3 Ib/ft Drill Pipe, 4.75 in. Tool Jointwith 10 lb/gal mud in a 6 in. hole

dfh

dnl

10

6 6oclh

6

20 3 0 4 0

Anal compressive load-l 000 lb.

Figure 78b-Lateral Contact Forces and Length

1 0 4

STD.API/PETRO R P 7G-ENGL L998 - 0732290 0609374 T73 m

API RECOMMENDED PFIACTICE 76

2.875 in. 10.4 IMt Drill Pipe, 4.125 in. Tool Jointwith 10 lb/gal mud in a 4.75 in. hole

1 0 0

-

0 3b 1

!

I

,I

. 1 I I I!

0 5 10 1s d-- - - -:Axial eompmssive ha&l 000 lb.

Figure 79a-Bending Stress for High Curvatures

STD.APIiPETRO R P 7G-ENGL I,998 - 0 7 3 2 2 9 0 IJb09775 90T -

REWMMENDED PRACZTICE FOR DRIU S TEM DESIGN AND OPERATING LIMITS 105

6

cneT$B.aa

2.875 in. 10.4 Ib/ft Drill Pipe, 4.125 in. Tool Jointwith 10 lb/gal mud in a 4.75 in. hole

lOOd/h

6odn-l

‘6odh

,4odh

2odlll

10

6

II II

5 10 15 2 0 2 5Axial compressive load-l 000 lb.

1OOdlh

6odh

6odh

4odm

2odm

1OOdJl-I6od/h6ode-l

40 d/h

20 dhl

Figure 79b-Lateral Contact Forces and Length

STD.API/PETRO R P ?G-ENGL 1998 - O&90 0609776 846 -

106 A P I RE C O M M E N D E D PRACITCE 76

2.375 in. 6.66 Wft Drill Pipe, 3.260 in. Tool Jointwith 10 lb/gal mud in a 4.00 in. hole

0 I I I II I I 1

I I i i i i I

Figure 60a-Bending Stress for High Curvatures

STD.API/PETRO R P ?G-ENGL 1998 m 0 7 3 2 2 9 0 0b09777 7 8 2 m

RE~~MMEIUCED PRACTICE FOR DRIU S TEM DESIGN AND Ow3mNG LIMITS 107

6

6

2

0

2.375 in. 6.65 Ib/ft Drill Pipe, 3.250 in. Tool Jointwith 10 lb/gal mud in a 4.00 in. hole

4odlh

12Odh

5 10 15 2 0Axial compressive load-1000 lb.

12OdRI6odn-l

4odh-l

Figure Bob-Lateral Contact Forces and Length

STD.API/PETRO R P 7G-ENGL 1998 W 0 7 3 2 2 9 0 0609778 bL9 m

108 API RECOMMENDED PRACTICE 76

example, an increase in MWD shock counts, which is indica-tive of BHA lateral vibration, can be caused by BHA Whirl,Bit Bounce, or other mechanisms. Additional clues, such asbit tooth breakage, for this example, are required for the iden-tification of the primary vibration mechanism.

There are a number of mechanisms which can cause severedownhole vibration. For mechanisms, tbeir symptoms, andmethods of control ale described below:

a. Slapstick:1 . Mechanism-Non-uniform bit rotation in which the bitslows or even stops rotating momentarily, causing theddlstrhg to periodically torque up and then spin fme.This mechanism sets up the primsry torsional vibrationsin the string.2 . Sympto-surface torque fhtctuations >15 percent ofaverage (below 1 Hz or stalling), increased MWD shockcounts, cutter impact damage, drillstring washouts/twist-offs, connection over-torque or back-off.

Note: 1 Hzisonecyclepersecond.

3. Actions-reduce WOB and increase RPM, consider aless aggressive bit, modify mud lubricity, reduce stabilizerrotational drag (change blade design or number of blades,use non-rotating stabilizer or roller reamer), adjust stabi-lizer placement, smooth well profile, add rotary feedbacksy-

b. Drillstringwhirlz1. Mechanism-the BHA (or drillpipe) gears around theborehole. The violent whirling motion slams the drill-string against the borehole. The mechanism can causetolsionalandlateralvibrations.2 Synqeo- washouts/twist-offs, local&dtool joint and/or stab&er wear, increased average torque,5 to 2OHz lateral vibrations even if bit off-bottom3. Actions-hft bit off bottom and stop rotation, thennzduce RPM, avoid drill collar weight in excess of 1.15 to1.25 times WOB, use packed hole assembly, reduce stabi-lizer rotational drag, adjust stab* placemen& modifymud properties, consider drilhng with a downhole motor

c. Bit whirl:1. Mecbanism-+ccenhic rotation of the bit about a pointother than its geometric center caused by bit/wellbomgearing (analogous to a planetary gear). This mechanisminduces high freqwncy lateral and torsional vibration ofthe bit and driR&ing.2 synlptoms-cutter impact damage, uneven bit gaugewear, over-gauge hole, reduce ROP, 10 to 50 Hz lateral/torsional vibrations.3. Actions-lift bit off bottom and stop rotation, thenIF&W RPM and increase WOB, consider changing bit(ilatter profile, anti-whirl), use slow RFM when taggingbottom and when reaming, pickoff bottom before stop-

ping rotation, use stabilized BHA with full gauge near-bit. .

-0rreamer.d Bit bounce:

1. Mechanism-large weight-on-bit fluctuations causingthe bit to repeatedly lift off and impact the formation. Thismechanism often occurs when drilling with roller conebits in hard formations.2. Symptoms-large axial 1 to 10 Hz vibrations (shakingof hoisting equipment), large WOB fluctuations, cutter and/or bearing impact damage, fatigue cracks, reduced ROR3. Actions-run shock sub or hydraulic thruster, adjustWOB/RFM, consider changing bit style, change length ofBHA

e. Other mechanismsome field data and theoretical stud-ies indicate that catain “critical speeds” exist which exciteresonant vibrations. previous editions of Recommended Frac-tice 7G gave formulas and graphs for predicting these criticalspeeds. However, severe vibrations have been routinely mea-sured at RPM other than those give by these simplecalcuItiOllS.

12.2 TRANSITION FROM DRILL PIPE TO DRILLCOLLARS

Frequent failure in the joints of drill pipe just above thedrill wllars suggests abnormally high bending stresses inthese joints. ‘Ibis condition is particularly evident when thehole angle is increasing with depth and the bit is rotated offbottom. Low rates of change of hole angle combined withdeviated holes may result in sharp bending of the first joint ofdrill pipe above the collars. when joints ate moved from thislocation and rotated to other sections, the effect is to loseidentity of these damaged joints. When these joints later failthmugh accumulation of additional fatigue damage, everyjoint in the string becomes suspect One practice to mducefailures at the transition zone and to improve control over theclamapedjointsistousenineortenjointsofheavywallpipe,or smaller dill collars, just above the collars. These joints aremarked for idem&ation, and used in the transition xone.Theyambqectedmomfiequentlythanregulardrillpipetoreduce the likelihood of service failures. The use of heavywall pipe reduces the stress level in the joints and ensureslonger life in this severe service amditior~

12.3 PULLING ON STUCK PIPE

It is normally not considered good practice to pull on stuckdrill pipe beyond the minimum tensile yield strength for thesize, grade, weight, and classification of the pipe in use (seelhbles 4,6, and 21). For example, assuming a string of 5-in.,19.5 lb/ft Grade E drill pipe is stuck, the following approxi-mate values for maximum hook load would apply:

Premium class: 311,535 lbsClass 2: 270,432 lbs

STD.API/PETRO R P 7G-ENGL L998 m 0 7 3 2 2 9 0 0609779 5 5 5 m

REPMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING LIMITS 109

The stretch in the drilI pipe due to its own weight sus-pended in a fluid should be considered when working withdrill pipe and the proper formulas to use for stmtch when freeor stuck should be used.

12.3.1 Example I (see A.6 for derivation):

Determine the stretch in a 10,000 foot string of drill pipefreely suspended in 10 lb/gal drilling fluid

L?e =9.625 x 10’

[65.44 - 1.44 WJ (22)

10,0002 Allowable hookloads and torque combinations for stuck drill

= 9.625 x lo7[65/M- 1.44 x lo] strings may be determined by use of the following formulaz

where= 53.03 in.,

& = length of free drill pipe, feet,W, = weight of drilling fluid, lb/gal,

e = stretch, inches.

12.3 .2 Example II (see A.4 for derivation):

Determine the free length in a 10,000 foot string of 4V,-in.OD 16.60 lb/ft drill pipe which is stuck, and which stretches49 in. due to a differential pull of 80,000 lbs.

L1

= 735,294 x e x W,,P (23)

735,294 x 49 x 16.60=80,000

= 7476 ft.,

where& = length of free drill pipe, feet,

e = differential stretch, inches,Wd, = weight of drill pipe, pound.5 per foot,

P = differential pull, pounds.

12.4 JARRING

It is common practice during fishing, testing, coring andother operations to run rotary jars to aid in freeing stuckassemblies. Normally, the jars are run below several drill col-lars which act to concentrate the blow at the fish. It is neces-sary to take the proper stretch to produce the required blow.The momentum of the moving mass of drill collars andstretched drill pipe returning to normal causes the blow afterthe jar hammer is tripped. A hammer force of three to fourtimes the excess of pull over pipe weight is possible depend-ing on type and size of pipe, number (weight) of drill collars,drag, jar travel, etc. This force may be large enough to dam-age the stuck drill pipe and should be considered when jarringoperations are planned.

12.5 TORQUE IN WASHOVER OPERATIONS

Although little data are available on torque loads duringwashover operations, they am significant. Friction and dragon the wash pipe cause considerable increase s in torque onthe tool joints and drill pipe, and should be considered whenpipe is to be used in this type service. This is particularly truein directionally drilled wells and deep straight holes withsmall tolerances. (See 12.6.)

12.6 ALLOWABLE HOOKLOAD AND TORQUECOMBINATIONS

0.0961673QT = D (24)

whereQT = minimum torsional yield strength under tension,

lb-ft.,J = polar moment of inertia:

= 2 (D4 - da) for tubes,

D = outside diameter, inches,d = inside diameter, inches,

Y, = minimum unit yield strength, psi,S, = minimumunit shearsttength,psi:

(S, = 0.577 YJ,P = total load in tension, pounds,A = cross sectionarea.

An example of the torque which may be applied to the pipewhich is stuck while imposing a tensile load is as follows:

Assume:

a 3V2-in. OD 13.30 lb Grade E drill pipe.b. 31/2-iu. IE tool jOhtS.

c. Stuck point: 4OBO feet.d Tensile pull: 100,000 pounds.e. NewdrilIpipe.

IUlDl:

QT =o.0961~5x 9-00

C& = 17,216 lb-ft.

For further iuformation on allowable hookloads, torqueapplication, and pump pressure use, see Stall and Blenkam:Allowable Hook Load and Tonpe Combinat ions For StuckD r i l l Smhgs.12

S T D . A P I / P E T R O R P 7G-ENGL L998 - 0 7 3 2 2 9 0 Ob09780 2 7 7 m

110 API RECOMMENDED PIWTICE 7G

12.7 BIAXIAL LOADING OF DRILL PIPE

The collapse resistance of driR pipe wmxted for the effectof tension loading may be calculated by reference to Figure81 and the use of formulas and physical constants containedin 12.8, 12.9, 12.10, and 12.11.

12.8 FORMULAS AND PHYSICAL CONSTANTS

The ellipse of biaxial yield stress shown in Figure 46 is foruse in the rauge of plastic collapse only, and gives the relationbetween axial stress (psi) in terms of average yield stress (psi)and effective collapse resistance in terms of nominal plasticcollapse resistance. This relationship is depicted in the fol-lowing formulaZ

12 + rz + z2 = 1, having solutions as follows:

r+ A/4-3r2z=-2 ,md (1)

r = z+J4-3z22 * (2)

where

r= Effective collapse resistance under tension @si) ,Nominal plastic collapse resistance (psi)

(3)

Total tensile loading (pounds)’ = Cross section area x Average yield strength * (4)

Average yield strengths in psi are as follows:GradeE75 . . . . . . . . . . 85,000Gradex95 . ..*..... 110,000GradeGl05 . . . . . . . . 120,000Grades135 . . . . . . . . 145,000

12.9 TRANSlTlON FROM ELASTlC TO PLASTICCOLLAPSE

Mat&al in the elastic range when under no tensile load,transfers to the plastic range when subjected to sufficientaxial load. Axial loading, below the transition load. has noefTect on elastic collapse. At transition point, the collapseresistance under tension equals the nominal elastic collapse,and also equals a tension factor (r) times collapse resistanceas calculated from the nominal plastic formula.

Methods Determine values for both elastic and plastic col-lapse fmm applicable formulas in Appendix A, substitute informula (3). 12.8 and solve for r. Then, solve formula (1),12.8, for z. For the total tension (transition) load, substitutevalue of z in formula (4). 12.8.

12.10 EFFECT OF TENSILE LOAD ON COLLAPSERESISTANCE

The effect of tensile load applies only to greater than tran-sition load on normally elastic items, and to any load on plas-tic collapse items. In either case, the value determined fromthe plastic collapse formula (Appendix A) is to be mod&d.

Method: Substitute the tensile load value in formula (4),12.8, to fmd a value for z. Substitute this value in formula (2),12.8, to permit solution for r. Next, substitute the value of r informula (3), 128, to obtain the effective collapse resistanceunder tension.

12.11 EXAMPLE CALCULATlON OF BIAXIALLOADING

An example of the calculation of drill pipe collapse resis-tance, corrected for the effect of tensile load is as follows:

Given: String of 5-&h GD, 19.50 lb per ft, Grade E Premium Class drill pipe.

Required: Determine the collapse resistance corrected fortension loading during drill stem test, with drill pipe emptyand 15 lb per gal. mud behind the drill pipe. Tension of50,000 lb on the joint above the packer

Solution: Find reduced cross section area of Premiumclass drill pipe as follows:

a Nominal OD = 5 inches, nominal wail thickness = 0.362inches.b. Nominal ID = 4.276 inches.c. Reduced wall thickness for premium.d Glass = (0.8)(0.362) = 0.28% inches.e . Reduced OD for premium class = 4.8552 inches.f. Cross-sectional area for premium.g. Class=reducedODarea-nominallDarea= 18.5141- 14.3603 = 4.1538 sq. inches.h. Tension load on bottom joint = 50,000 + 4.1538= 12037 psi.i . Average yield sttength for Grade E drill pipe = 85,000 psi.j. Percent tensile stress to average yield strength

12,037 x 1oo=-

85,000= 14.16 percent

k Enter Figure 81 at 14.16 percent on upper right horizontaJscale and drop vertically to k&rsect right-hand portion of theellipse. Fkuceed horizontally to the left and in&sect Nominalcollapse Resistance (center vertical scale) at 92 percent.L Minimum collapse re&ance for premium class (Table 5)= 7041 psi.m.comXtedcollapseresistarlceforeffectofteusion= (7041)(.92) = 6478 psi.

CAVZ’ZON: No safety factors are included in this examplecalculation

STD.API/PETRO R P i’G-ENGL L998 - 0 7 3 2 2 9 0 0609783 L O 3 -

RE~~M~IENDED PRAIZI-ICE FOR DRIU STEM DESIGN AND OPmmNG LIMITS 111

STDeAPI/PETRO R P ?G-ENGL 1998 m 0732290 0609782 04T m

112 ApI REcDMMENDED PRACnCE 76

13

13.1

Identification, Inspection andClassification of Drill StemComponentsDRILL STRING MARKlNG ANDlDENTlFlCAllON

sections of drill string man- in accordance withAPI Specification 7 are identified with the markings shown inFigure 82. It is recommended that drill string members notcovered by Specification 7 also be stencilled at the base of thepin as shown in Figure 82. It is also recommended that drillstring members be marked using the mill slot and groovemethod as shown in Figure 83.

13.2 INSPECTlON STANDARDS-DRILL PIPEANDTUBING WORK STRINGS

Thmugh efforts of joint committees of API and IADC,inspection standards for the classification of used drill pipehave been established. The procedure outlined in Table 24 wasadopted as tentative at the 1964 Standardization Conferenceand was revised and approved as standard at the 1968 Stan-dardization Conference. Additional revisions were made at the1970 Standardization Conference to add premium Class. Atthe 1971 Conference, it was determined that the drill pipeclassification procedure be removed ti-om an appendix to APISpeciscation 7 and placed inAP Recommended Practice 7G.At the 1979 Standardization Conference, Table 25 was revisedto also cover classification of used tubing work strings.

The guideiines established in this recommended practicehavebeeninuseforseveralyears.Useofthepracticeandclass&ation guide have appaxently been successful whenappiied in general application. There may be situations whereadditional il3spedons are required

13.2.1 Limitations of Inspection Capability

Most fail- of drill pipe result f?om some fixm of metalfatigne. A fatigue fail= is one which originates as a result ofrepeakd or fluctuating stresses having maximum vahles lessthanthetensilesttengthofthemateriaLFatiguef&tuxesareprognssive, beginning as minnte cracks that grow under theaction of the flucmatiq stress. The rate of propagation isrelated to the appiied cyciic loads and under certain condi-tions may be extremely rapid. The faihn-e does not normallyexhibit extensive plastic deformation and is therefore dif3icultto detect until such time as considerable damage hasoccumxLThereisnox4xptedmeansofinspe&ngtodeter-mine the amout of iicammlated fatigue damage or theremaining iife in the pipe at a given stress 1eveL

Presently accepted means of inspection are limited to loca-tion of cracks, pits, and other surface marks; measurement oflxmining wail thickness; measlmment of outsi& diametecand caicnlation of remaining cross sedionai area. Recentindustrystat&icsconfhmthatamajorpenx&geoftube

body in-service fail= occur near the upset runout or withinthe slip area Special attention to these critical failure areasshould be performed during inspection to facilitate crackdetection in drill strings which have been subjected to abnor-mally high bending stresses. Drill pipe which has just beeninspected and found fnze of cracks may develop cracks aftervery short additional service through the addition of damageto previously auxmmIated fatigue damage.

13.2.2 Drill String Cracks

A crack is a single line rupture of the pipe surface. The ruptnre shall (a) be of sufiicient length to be shown by magneticiron particles used in magnetic particle inspection or (b) beidentifiable by visual inspection of the outside of the tubeand/or optical or ultrasonic shear-wave inspection of theinside of the tube. Drill pipe tubes, tool joints, and drill collarsfound to contain cracks should be considered unfit for furtherdriliing service. Shop repair of some tool joints and drill col-lars, containing cracks, may be possible if the unaffected areaof the tool joint body or drill collar permits.

13.2.3 Measurement of Pipe Wall

Tube body conditions will be classified on the basis of thelowest wall thickness measurement obtained and the remainingwall requirements contained in Table 24. The only acceptablewall thickness measurements are those made with pipe-wallmicrome~ ultrasonic instrumenti, or gamma-ray devicesthat the operator can demonstrate to be within 2 percent accu-racy by use of test blocks sized to approximate pipe wall thick-ness. When using a highly sensitive ultrasonic inslnunen~ caremust be taken to ensure that detection of an incltion or lami-nation is not interpreted as a wall thickness measurement

13.2.4 Determination of Cross Sectional Area(Optional)

Detmmine cross sectionai zma by use of a direct indicatingmstrument that the operator can demonstrate to be within 2percent acaracy by use of a pipe section approximately thesameasthepipebeinginspecte&Intheabsenceofsuchaninstrume* integrate wall thickness rLWWlEmentstakenatl-inch intervals around the tube.

13.2.5 Procedure

Used drill pipe should be class&xl accord& to the procedme of ‘Ihble 24 and as ill~trated in Figure 84, dimension A.Hook loads at minimum yield strength for New, Premium andCiass 2 drill pipe are listed in Table 26. Values recommendedfor minimum OD and make-up turque of weld-on tool jointsusedwiththeNew,premiumandclass2~pipearelistedin Table 10. hn * allowable hook loads for New, Pre-mium and Class 2 tubing work strings (also class&d inaccordance with Table 24) are listed in Table 27.

(Text axahc!d On page 122.)

STD.API/PETRO R P 7G-ENGL 1998 D 0 7 3 2 2 9 0 Ob09783 TBb m

RECOMMENDED PRACTTCE FOR DRIU STEM DESIGN AND OFEFIATING LIMITS 113

Sample markings at base of pin

1 2 3 4 5

22 6 7 0 N E

1 Tool Joint Manufacturer’s Symbol:ZZ Company (fictional for example only)

2 Month Welded:5-June

3 Year Welded:70-l 970

4 Pipe Manufacturerb Symbol:N-United States Steel Company

5 Drill Pipe Grade:E-Grade E75 drill pips

Notes:Tool joint manufacturer’s symbol, month welded, year welded, pipe mauufactumr, and drill pipe grade symbol shall bc stenciled at the base of the pin as

shown above. Pipe mauufachuer symbol and drill pipe grade symbol applied shall be as represented by manufactumr. Supplier, owner, or user shall bcindicated on documents such as mill certitication papers or purchase orders.TOOL JOINT MANUPACIWRER’S SYMBOL

Refer to the eleventh edition 1993 of the IADC Drilhng Manual* (Section B-l-9) for a list of Tool Joint Manufacturer’s symbols.

*Available fi-omz International Association of Drilling Contractors @DC) P.O. Box 4287, Houston, TX 77210.

Month and Year Welded&g&J year

1 through 12 Last two digits of year

Drill Pipe Grade

svmbolB75.................Ex95.................xG105 . . . . . . . . . . . . . . ..G5135.................s

Heavy Weight Drill Pipe(Double stencil pipe grade symbol.)

The ‘tnanuf~ may be either a pipe mill or processor. SeeAPI S@ficzUion 5D, Spec$Icafion for Drill Pipe.

These symbols are provided for pipe manufactureridentification and have been assigned at pipe manufacturers’requests. Manufacturers included in this list may not be currentAPI Specification 5D licensed pipe manufacturers. A list ofcurrent licensed pipe manufactumrs is available in the CompcsireList of hianujkcturers, (Licensed for Use of the API Monogram).

Pipe milk may upset and heat treat their own drill pipe, or theymay have this done according to their own specificatious. In eithercase,themill’sassignedsymbolshouldbe~oneachdrillstringassembly since they are the pipe manufacturer.

Pipe processors may buy “green” tubes and upset and heat treatthese according to their own specifications. In this case, theprocessor’s assigned symbol should be used on each drill stringassembly since they are the pipe. manufacturer.

Pipe Manufacturers(Pipe Mills or Processors)

Active

Mill

Algoma

British SteelSeamIess nlks LID

DalmineKawasaki

NipponNKK

Maunesmam

SymbolX

B

DH

IK

M

Reynolds Alumiuum RA

slmlitomo SSiderca SD

TamSa Tus Steel N

Vallourec VUsed U

Processor SymbolOrantTFw TFW

ChllSW

Plih

OMSPI

MiIl SymbolAllIlW A

America SeamIess AIB&W WcmzI CJ&L J

Lone Star LOhio 0Republic RTI Zlllbemuse Tu

voest VAwheeling Pitlsburgh PYoungstowu Y

Figure 824vlarking on Tool Joints for Identification of Drill String Components

STD.API/PETRO R P ?G-ENGL 1998 W 0 7 3 2 2 9 0 0609784 9l,2 -

114 API RECOMMENDED PFWTICE 76

Nomarkirq.s

Standard weight grade E75 drill pipe

t+l%‘+l

Standard weight grade G105 drill pipe

--_----Standard weight grade X95 drill pipe

I+14Standard weight grade S135 drill pipe

Heavy weight grade E75 drill pipe Heavy weight grade G105 drill pipe

r-1-L +_---- - -Heslvy weight grade X95 drill pipe Heavy weigM grade SK% drill pipe

Drill pipe Weight Code

(1) (2) (3) (4) (1) (2) (3) (4)

S i z e O D NomidWei&t Walllhidmss Weightcode S i z e O D NomidWci&t wall T h i c k n e s s W@lltCOCkiuha bP=fi inches NWllbS inches bperfi inclx!s NUOlbS

231, 4.85 .190 1 4vz 2 0 . 0 0 A30 36.65. 280 2 2282 .500 4

24.66 .550 52% 6.85 .217 1 2 5 . 5 0 575 6

10.4W .362 25 16.25 .2% 1

3’12 9.50 254 1 19.50 .362 213.30+ 368 2 2 5 . 6 0 .soo 315.50 A49 3

511, 19.20 .304 14 11s 262 1 2 1 . w .361 2

14.w .330 2 2 4 . 7 0 .415 315.70 .3&J 3

6% 2520. .330 24y, 13.7s 271 1 2 7 . 7 0 362 3

16.e .337 2

T .- -sstadard~flxdrillpipcti.

Figure 83-Recommended Practice for Mill Slut and Groove Method of Drill String Identification

STD.API/PETRO R P ?G-ENGL 1998 D Oi’32290 0609785 859 m

RECoMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPEFIATING LIMITS 115

Table 24-Classification of Used Drill Pipe(All sizes, weights and grades. Nominal dimension is basis for all calculations.)

Premiumclass’lb0 white Bands

One center fun& Mark

Class2Yellow Bands

TWO Center Punch h4arks

Class3Orange Bands

Three CenterpLmch Marks

L EXTERIOR CONDlTIONs”

A.ODwemWall

B. Dents and mashes

Re.maikg wall not lessthan80%

Remaining wall not lessthan7096

Dim xeductioll not llialmterreductionnotoyer 3% of OD over 4% of ODDiameter reduction not Diarfa?w Nduction notomr 3% of OD over 4% of OD

AnyimperfectionsmdamagesexcedingCLASS2

cnlshing, neddw

c. slipamMechanicaldamagecuti, gages’

D. Stressinduceddiametervaliadons1. S-M

2. string shot

E. Corrosion, cuts, and gouges1. Corrosion

2. Cuts and gougesIangitudinal

TNUSverSe

E Cracks’

Depth not to exd 10%of the average adjacentWtllF

-leductionnotover 3% of ODDlaumerincNasenotowz3W of OD

Remaining wall not lessthanso%

Remaining wall not lessthan8096Remaining wall not lessthanm%

None

Depthnottoexceed209boftheavcrageadjacentWEIllS

Diameter reducbm notover 4% of ODI)lametainmr.asenotover 4% of OD

Remaining wall not lessthan 70%

Remaiuing wall not lessthan 70%Remaining wall not lessthanSO%

None None

lI. INTERIOR CONDITIONS

A. Chwive pittingWall

B. ?XrosionandwearWall

c. cracw

Remainiug wall not less Remaining wall not lessthan809bmeasuredtium than 70% measured fkombaseofdcxpestpit base of deepest pit

Remainiug wall not less Remaining wall not lessthan80% than 70%

NO% None NOIE

The pmnium classilication is mumunended for service whexe it is anticipated that torsional or tensile limits for Class 2 drill pipe and tubing work strings will bcexceeded. These limits for premium class and Class 2 ddll pipe are specified iu Tables 4 and 6, respectively. Premium Class shall be identified with two whitebands, plus one center punch mark on the 35 degree or 18 degree shoulder of the pin end tool jointNmaining wall shall not be less than the value iu LE.2, defects may be ground out providing the re maining wall is not reduced below the value shown in LE. 1 ofthis table and such grinding to be approximately faired into outer contour of the pipe.%I any classiiicatim whem cm&s or washouts appear, the pipe will be identified with the red band and considered uufit fa kther drilling service.4An API Reammznded practice 7G inspedon caunot be made with drill pipe rubbers on the pipe.$Average. adjacent wall is determked by measuring the wall thickness on each side of the cut or gouge adjacent to the deepest penetration.

STD.API/PETRO R P 7G-ENGL 1998- 0 7 3 2 2 9 0 Ob097itb 7 9 5 m

116 API RWOMMENDED PRACTICE 76

t0 Ic I II

i II

i -i- -l \

m

L.:

III,J

STD.API/PETRO R P ? G - E N G L 1998 - 0 7 3 2 2 9 0 Ob09787 b2L m

RECXMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING L~~rrs 117

-

Table 25-Classification of Used Tubing Work Strings

(1)

F’ipe Body Condition

L BXTBRIORCONDITIONS

AODwearWall

B. Dents and mashes

crushing, necking

c. sliparea,tongareallx32hanicaldamageCubs, gouges3

D. Stress induceddiametervariations1. snetckd

2. string shot

E Corrosion, cuts, and gouges1. Corrosion

2. Cuts and gouges

Transverse

E Cracks’

(2)critid service class’

One White Band

c-N= a9

Remaining wall not lessthan 87V,%

DiameterductionIlotover 2% of ODDimwerleductionnotover 2% of OD

Depthnottoexazed10%oftheaverageadjacentWdP

Diameter reduction notover 2% of ODDiameteer increase notover 2% of OD

Remaining wall not lessthan 87’/,%

p ’ . gwal lnot lessthan 87’/*%Remaining wall not lessthan 87Vz%

None

(3) (4)

Fnmiumclass2 Class2-ho White Bands Blue Bands

Remaining wall not less Rmaining wall not lessthan802 than70%

Diameter reduclion not Diameter reduction notover34bofOD over 4% of ODDiameter ledudion not DianMer reduction notover3% of OD over496ofOD

Depthnottoexceed 10% Depth not to exceed 20%oftheakerageadjacent of the average adjacentWdl5 w a l l 5

Diarmter reduction not Diameter reduction notover38ofOD over4LRbofODDiameterincreasenot Diameterincreasenotover396ofOD over 4% of OD

Remaining wall not less RemainmgwaLlnotlessthan 80% than7096

Remaining wall not less Rr. ’ - gwal lnot lessthan 80% than70%Remaining wall not less RG ’ . gwallnotlessthan 80% than8096

None NOne

IL INTERIOR CONDITIONS (Tube and Upset)

A. Conosive pittingWal l

B. Erosion and wearWdl

c. DriilExternal upsetInt&malups&

D. Cracw

Remaining wall not lessthan 87VsoRb measuredfiombaseofdeepestpit

Remaining wall not lessthan 87’/,%

API dimensmns VI6 mchless than specitied boredID

None

Remaining wall not lessthan8046measuredfiombase of deepest pit

Remaining wall not lessthan8096

AFT dimensions ‘I,, inchless than speciEed tunedID

None

Remaining wall not lessthan7o%measuredr5ombase of deepest pit

Remaining wall not lessthaIl70%

API dimensions ‘I,, inchless than spe!cifierl breedID

None

The dical service classilication is mco mmended for service where new or like new specitications apply. Critical service classification tubing work strings shallbe identified with one white band.The premium classi6cation is recommen ded for service where it is anticipated that torsion or tensile limits for Class 2 tubing work strings will be exceeded Pm-mium classification tubing work strings shall be identified with two white bands.%maining wall shall not be less than the value in LE.2. Defects may be ground out providing the nuknin g wall is not reduced below the value shown in LE. 1of this table and such grinding to be approximately thired into outer contour of the tubing.%I any classifi&on where cracks or washouts appear, the tubing will be identitied with the red band and considered unfit for further service.sAverage adjacent wall is determined by measuring the wall thickness on each side of the cut or gouge adjacent to the deepest penetration.6Applicable to Lutemal Upsets which have been bored.

S T D . A P I / P E T R O R P 7G-ENGL 19913 D 0 7 3 2 2 9 0 ObO978B 5b8 -

118 API %COMMENDED i%ACTlCE 76

Table 26-Hook-Load at Minimum Yield Strength for New, Premium Class (Used), and Class 2 (Used) Drill Pi

~1~valuesinthistable~~yY~dataforthesampipesizeandclapslistedin‘l!+blcs2,4,6,8,and9becamcofdiff- iIlroundingprocerloles~iUcalcalations.)

(1) (2) (3) (4) (3 (6) 0 (8) 0 (10) (11) (12) (13 (14) (15) (16) (17) (18)

NCW h?miumclass class2

i n i n qin 462.2990 0 . 1 5 2 1.0252 78.61

in. iu sq.in. %22610 0.133 0.8891 68.17

iamill. in. i n sq.iu2’/, 4.85 2375 0.190 1.995 1.3042

psi l b

75000. 97817.95om. 123902

105cm. 136944.135m. 176071.

75ooO. 138214.95000. 175072.

lO5ooO. 193500.135000. 248786.

75000. 135902.95000. 172143.

105000. 190263.135mO. 244624.

75ooo. 214344.95ooo. 271503.

105000. 3um82135000. 385820.

75000. 194264.95om 246068.

105m. 271970.135ooO. 349676.

75ooo. 271569.95ooo. 343988.

lo5OOo. 380197.135ooo. 488825.

7m. 322775.95ooo. 4Qaa48.

105Oal. 451885.135aIO. 580995.

75alO. 230755.95ooo. 292290.

lO5aOo. 323057.13u)(10. 415360.

7moO. 285359.95oaL 361454.

105mO~ 399502135mo- 513646.

75mo. 324118.95oal. 410550.

105000. 453765.135000. 583413.

75ooo. 270034.95ooo. 342043.

105cm. 37aw7.135oaO. 486061.

lb76893.97398.

107650.138407.

107616.136313.150662193709.

106946.135465.149725.192503.

166535.210945.233149.299764.

152979.193774.2 1 4 1 7 1 .275363.

2 1 2 1 5 0 .268723.297010.381870.

250620.31745235OMa.4 5 1 1 1 5 .

182016.2 3 0 5 5 4 .254823.327630.

224182

2a3%3.313854.4433527.

l b

66686.84469.9 3 3 6 0 .

120035.

92871.117636.130019.167167.

92801.117549.129922.167043.

143557.181839.200980.258403.

132793.168204.185910.239027.

183398.232304.256757.330116.

215967.273558.302354.388741.

158132200301.221385.284638.

2vs 6 .65 2375 0 .280 1 .815 1 .8429 22630 0.224 1.4349 77.86 2.2070 0.1% 1.2383 67.19

27/, 6 .85 2875 0 .217 2441 1 .8120 2.7882 0 . 1 7 4 1.4260 78.69 27448 0 . 1 5 2 1.2374 68.29

2’/* 10.40 2875 0 .362 2 .151 28579 2 . 7 3 0 2 0.290 22205 77.70 26578 0 . 2 5 3 1.9141 66.97

3’12 9 .50 3 .500 0 .254 2992 2.5902 3.3984 0.203 20397 78.75 3.3476 0 . 1 7 8 1.7706 68.36

3112 13.30 3.500 0.368 2.764 3.6209 3.3528 0.294 28287 78.12 3.2792 0 . 2 5 8 24453 67.53

3v* 1550 3500 0 .449 2602 43037 33204 0.359 3.3416 77.65 3.2306 0 . 3 1 4 287% 66.91

4 11.85 AOOO 0.262 3.476 3.0767 3.8952 0 . 2 1 0 24269 78.88 3.8428 0.183 21084 68.53

4 14.00 4.orm 0.330 3.340 3.8048 3.8680 0.264 29891 78.56 3.m 0.231 2.5915 68.11

219738.278335.307633.395526.

4 15.70 4.ooO 0.380 3.240 4.3216 3 . 8 4 8 0 0.304 3.3847 78.32 253851.321544.355391.4 5 6 9 3 1 .

28434 78.97 213258.270127.298562383865.

3.7720 0.266 29298 67.80

4vz 13.75 4.54x 0.271 3.958 3.6005 4 . 3 9 1 6 0.217 43374 0 . 1 9 0 24719 68.65

STD.API/PETRO RP 7G-ENGL 1998 - 0 7 3 2 2 9 0 0609789 4T4 W

RECOMMENDED PRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS 119

Table 2Hook-Load at MinimumYield Strength for New, Premium Class (Used), and Class 2 (Used) Drill Pipe (Continued)

(1)

4'1,

(2) (3) (4) (5) (6) 0’) (‘3) (9) (10) (11) w (13 04) (19 (16) (17) (18)NCW r . class class2

WJ

lblft ill. in. in. sq:in psi l b in. iu. q. in I lb in in sq. ill. 46 l b

16.60 4.500 0.337 3.826 4.4074 7m. 330558. 4.3652 0.270 3.4689 78.70 260165. 4.2978 0.236 3.0103 68.30 225771.

95oaI 418707. 329542. 285977.

105OW. 462781. 364231. 3 16080.

135Oal. 595004. 468297. 406388.

20.00 4.500 0.430 3.640 5.4981 75OOO. 412358. 4.3280 0.344 4.3055 78.31 322916. 4.2420 0.301 3.7267 67.78 279502

95om. 522320. 409026. 354035.

105OOo. 577301. 452082 391302.135cm. 742244. 581248. 503103.

22.82 4.5OO 0.500 3.500 6.2832 75ooo. 471239. 43ooo 0.400 4.9009 78.00 367566. 4.2OOO 0.350 4.2333 67.37 317497.

95oaJ. 5%9!33. 465584. 402163.105cOo. 659735. 514593. 4444%.

135m. 848230. 661620 571495.

16.25 5.OOO 0.2% 4.408 4.3743 75ooo. 328073. 4.8816 0.237 3.4554 78.99 259155. 4.8224 0.207 3.0042 68.68 225316.95mo. 415559. 328263. 285400.

105OOo. 459302. 362817. 315442

13xKn. 590531. 466479. 405568.

19.50 5.OOO 0.362 4.276 5.2746 75OL-0. 395595. 4.8552 0.29O 4.1538 78.75 3 11535. 4.7828 0.253 3.6058 68.36 270432

95000. 501087. 394612. 34254.8.

105000. 553833. 436150. 378605.

135mo. 712070 560764. 4 . 8 6 7 7 8 .

25.60 m o o 0.500 4.ooo 7.0686 75om. 530144. 4.8ooo 0.403 5.5292 78.22 414690. 4.7OOO 0.350 4.7831 67.67 358731.

95ooO. 671515. 525274. 454392105om 742201. 580566. 502223.

135ooo. 954259. 746443. 645715.

19.20 5soo 0.304 4.892 4.9624 75000. 372181. 5.3784 0.243 3.9235 79.06 294260. 5.3176 0.213 3.4127 68.77 255954.95ooO. 471429. 372730. 324208

105OOO. 521053. 411965. 358335.

135ooo. 669925. 529669. 460717.

21.90 5.500 0.361 4.778 5.8282 75OOO. 437116. 5.3556 0.289 4.5971 78.88 344780. 5.2834 0.253 3.9938 68.52 299533.

95OOO. 553681. 436721. 379409.

105OOO. 611963. 482692. 419346.

135ooO. 786809. 620604. 539160.

24.70 5.500 0.415 4.670 6.62% 75ooo. 497222. 5.3340 0.332 5.2171 78.69 391285. 5.2510 0.290 4.5271 68.29 339533.9SOOO. 629814. 495627. 430076.

1OSooO. 696111. 547799. 475347.

135000. 894999. 704313. 611160.

25.20 6.625 0.33O 5.965 6.5262 75ooo. 489464. 6.4930 0.264 5.1662 79.16 387466. 6.4270 0.231 4.4965 68.90 337236.

95000. 619988. 490790. 427166.

105000. 685250. 542452. 472131.135000. 881035. 697438. 607026.

27.70 6.625 0.362 5.901 7.1227 75om 534199. 6.4802 0.290 5.6323 79.08 422419. 6.4078 0.253 4.8994 68.79 367455.95OOO. 676652. 535064. 465443.

105000. 747879. 591387. 514437.135OCQ. %1558. 760354. 661419.

STD.API/PETRO R P 7G-ENGL I,998 m 0 7 3 2 2 9 0 lJb09790 LLb m

120 API RECOMMENDED PRAc-mx 76

Table 27-Hook-Load at Minimum Yield Strength for Ney, Premium Class (Used), and Class 2 (Used)Tubing Work Stnngs

~ooklosdvaluesin~~~~sliglrtlY~tmsiledataforthesamepipesizeandClasSlistedin‘Igbles~4,6,8,and9becauseofdiffaenasin~~usedincalc ’ *’ .)

(1) (2) (3) (4) Q (6) 0 (8) 0 (10) (10 (12) (13 (14) (15) (16) (17) (18)

NCW premiumclass clam2

iJLwftiu in in. sq.lu psi l b in iu sq.ilL % l b in in. sq.in % l b

c 1.20 1.050 0.113 0.824 0.3326 55m. 18295. l.al48 0.090 0.2597 78.07 14283. 0.9822 0.079 0.2244 67.47 12343. k

75m. 24948. 19477. 16832

80000. 26611. 20775. 17954.105ooO. 34927. 27267. 23564.

‘1. 1.50 1.050 0.154 0.742 0.4335 55m. 23842. 0.9884 0.123 0.3349 77.25 18418. 0.9576 0.108 0.2878 66.39 15829.. 75000. 32512 25115. 21585.

tloom. 34679. 26790. 23024.105000. 45516. 35161. 30219.

1.80 1.315 0.133 1.049 0.4939

1.315 0.179 0.957 0.6388

1.660 0.140 1.380 0.6685

1.660 0.191 1.278 0.8815

1.660 0.198 1.264

I.900 0.145 1.610

1.900 0219 1.462

2063 0.156 1.751

2.375 0.190 1.995

2.315 0.218 1.939

0.9094

0.7995

1.1565

0.9346

I.3042

1.4773

105000.

105(mo.

8cQw.mooo.

105OW.

27163.37041.39510.51857.

1.2618 0.106 0.3862 7820

35135.4791251106.67077.

1.2434 0.143 0.4950 77.48

36769.50140.53482701%.

1.6040 0.112 0.5250 78.53

48481.66110.70517.

92554.

1.5836 0.153 0.6868 77.92

50018.68256.72753.95489.

1.5808 0.158 0.7078 77.83

43970. 1.8420 0.116 0.6290 78.68

105000.

55000.75oal

105000.

55000.75mO.

105000.

55oal75cm.80000.

lQMo0.

55mO.75mO.80000.

105000.

63957.83943.

63610.86741.92523.

121437.

51403.70095.74768.98133.

71733.97817.

104339.136944.

81249.110794.118181.155112

1.8124 0.175

0.125

0.152

0.174

0.9011

0.7354

1.0252

1.1579

77.92

78.69

78.61

78.38

2124228966.30897.40552

27222.37122395%.51970.

28873.39373.41998.55122

37776.51513.54947.72118.

38930.53087.56626.74322

34595.47175.

50320.66045.

49562.67584.72090.94618

40450.55158.

56388.76893.8#)19.

107650.

63686.86844.92634.

121581.

1.2352 0.093 0.3340 67.64

1.2076 0.125 0.4260 66.69

1.5760 0.098 0.4550 68.07

1.5454 0.134

0.139

0.101

0.153

0.109

0.133

0.153

0.5930 67.27

15412 0.6107 67.16

1.8130 0.5457 68.26 30016.

1.7686

1.9694

22610

22442

0.7779 67.26

0.6382 68.28

0.8891

1.0027

68.17

67.88

1837225053.26724.35075.

2343231953.34083.44734.

25027.34128.36403.47779.

32613.

47437.

62261.

33590.

64126.

43660.57304.

42787.58345.62235.81684.

35099.4786251053.6MM.

4a903.66686.7113293360.

55150.75205.80218.

STD.API/PETRO R P 7G-ENGL I,998 - 0 7 3 2 2 9 0 0609793 0 5 2 -

REKWUIMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING L~~rrs 121

Table 27-Hook-Load at Minimum Yield StrenTubing WoP

for New Premium Class (Used), and Class 2 (Used)Strings (continued)

(1) (2) (3) (4) (5) (6) (71 (8) (9) w-9 (11) (12) (13 (14) (15) (16) (17) (18)New F%emiwnclsss class2

irLltdftin. in. in SC&in psi l b ill. in. q.in 96 l b in. in. SC&in 5% l b

zv, 5.95 2375 0.254 1.867 1.6925 55ooo. 93087. 2.2734 0.203 1.3216 7 8 . 0 8 72686. 22226 0 . 1 7 8 1.1422 67.49 6282O.

75OOO. 126936. 99117. 85663.

8 o o o 0 . 135399. 105725. 91374.

1oSoal. 177711. 138764. 119928.

23/s 6.50 2875 0 . 2 1 7 2.441 1.8120 55ooo. 99661. 2.7882 0 . 1 7 4 1.4260 78.69 76427. 27448 0 . 1 5 2 1.2374 68.29 880%75000. 135902 106946. 92801.

80000. 144%2 114076. 98988.

105OOO. 190263. 149725 129922

271, 8.70 2875 0 . 3 0 8 2 . 2 5 9 2 . 4 8 3 9 55ooO. 1 3 6 6 1 2 2.7518 0 . 2 4 6 1.9394 78.08 106667. 2.6902 0 . 2 1 6 1.6761 67.48 92186.

75OOO. 186289. 14545s. 125709.

80000. 198708. 155152 134089.1OSoco. 260805. 203637. 175992

2’/. 9.50 2875 0 . 3 4 0 2.195 2.7077 55OCQ. 148926. 2 . 7 3 9 0 0 . 2 7 2 2.1081 7 7 . 8 5 115945. 2 . 6 7 1 0 0 . 2 3 8 1.8192 67.18 lMHJS3.7 5 o o o . 203080. 1581%. 136436.

8oollO. 216619. 168647. 145532

lo5ooo. 284313. 221349. 191011.

2’1. 10.70 2875 0 . 3 9 2 2.091 3.0578 5Som 168180. 27182 0.314 23690 77.47 130296. 26398 0 . 2 7 4 20391 64.68 112151.75000. 229337. 177676. 152933.

8oom 244626. 189522 163128.1OSOOO. 321072 248747. 214106.

2’la 11.00 2875 0.405 2.065 3.1427 55ooo. 172848. 2.7130 0.324 2.4317 77.38 133744. 2.6321) 0.283 20917 66.56 llSO42

7 5 o o o . 235702. 182378. 156875.

80000. 251415. 194536. 167334.

105ooO. 329983. 255329. 219626.

3’1, 12.80 3.500 0.368 2 . 7 6 4 3.6209 SSOO.

75Gin8oooO.

105ooo.

199151.271569.

380197.

3.3528 0.294 28287 78.12 155577. 3.2792 0 . 2 5 8 24453 67.53 134492.212150. 183398.226293. 19.5624.297010. 25675-I.

3’12 12.95 3 . 5 0 0 0.375 2 . 7 5 0 3.6816 55OW. 202485. 3.3500 0 .300 28746 78.08 158101.75ow. 276117. 215592.8oooo. 294524. 229965.

lO5OOO. 386563. 301828.

3 .2750 0.2.63 2.4843 67.48 136637.186323.198745.26O853.

3’/* 15.80 3.500 0.476 2.548 4.5221 55om 248715.75om 339156.8oooO. 361767.

1oSOOO. 474819.

3.3096 0.381 3.5038 n.48 192708. 3.2144 0.333 3.0160 66.69 165879.262783. 226198.280302. 241278.367897. 3 16678.

3’1, 16.70 3.500 0 . 5 1 0 2 . 4 8 0 4 . 7 9 0 6 55000. 263484. 3.2960 0.408 3.7018 77.27 2035%.75000. 3592%. 277631.aoom. 383249. 2%140.

105000. 503015. 388684.

3.1940 0 . 3 5 7 3.1818 66 .42 17SCNIl.238638.254547.334093.

4v, 15.50 4.500 0 . 3 3 7 3.826 4.4074 55OOO. 24240!?. 4 . 3 6 5 2 0.270 3.4689 78.70 19O788. 4.2978 0.236 3.0103 68.30 165565.75ooo. 330558. 260165. 225771.lmoo. 352595. 277Scm 240823.

1oSOoO. 462781. 364231. 316080.

4’12 19.u) 4.500 0 . 4 3 0 3 . 6 4 0 5.4981 55OW.75om.aoom

1OSOOO.

3023%. 4 . 3 2 8 0 0 . 3 4 4 4.3055 78.31 236805. 4 . 2 4 2 0 0.301 3.7267 67.78 204968.412358. 322916. 279502.439848. 344443. 298135.577301. 452082. 391302.

S T D . A P I / P E T R O R P 7G-ENGL 1998 - 0-?322=lO Clb09792 T99 m

122 API RECOMMENDED PRACTICE 7G

13.2.6 Inspection Classification Marking 13.3.2.1 Required Inspections

A permanent mark or marks signifying the classi6cation ofthe pipe (for example, refer to Table 24, Note 1) should bestamped as follows:

Following are required inspections:

a. On the 35degree or 18-degree sloping shoulder of the pinend tool joint

b. Gr in some other low-stressed section of the tool jointwhere the marking will normally carry through operations.

c. Cold steel stenciling should be avoided on outer surface oftube body.

a Outside diameter measurement-measure tool joint out-side diameter at a distance of 1 inch from the shoulder anddetermine classillcation from data in Table 10. Minimumshoulder width should be used when tool joints are worneccentrically.b. Shoulder conditiowheck shoulders for galls, nicks,washes, fins, or any other matter which would affect thepressure holding capacity of the joint and conditions whichmay tiect joint stability. Make certain joint has a minimum1/32 in. x 45 degree OD shoulder bevel.

d One center punch denotes Pmmium, two denote Class 2and three denote Class 3. 13.3.2.2 Optional Inspections

Following are optional impections:13.3 TOOL JOINTS

13.3.1 Color Coding

The ~Iassification system for used drill pipe outlined inTable 24 includes a color code designation to identify the drillpipe chss. The same system is recommended for tool jointclass ident&ation. In addition, it is recommended that thetool joint be identifted as (1) field repairable, or (2) scrap orshop mpahable. This color code system for tool joints and fordriil pipe is shown in Figure 85.

13.3.2 Inspection Standard

a Shoulder width-using data in Table 10, determine mini-mum shoulder width acceptable for tool joint in class asgoverned by the outside diameter.b. visual thread inspection-the thread protie is checked todetect over-torque, insuEcient torque, lapped threads, andstretching. Threads are visually impeded to detect handlingdamage, corrosion damage and galling.c. Box swell and/or pin stretch-these are indications ofover-toquing and their presence greatly affects the futureperformance of the tool joint The lead gauge is the only stan-dard method for measing pin stretch. On used tool joints, itis recommended that pins having stretch which exceeds 0.006inch in 2 inches should be recut All pins which have beenstretched should be inspected for cracks.

The following recommended inqection standard for usedtool joints was initially included as an appendix to API Speci-fication 7. It was moved to API Recommended Practice 7Gby conunittee action at the 1971 Standardization Conference.

It is recommended that box counterbores (Qc), API Speci-fication 7, Table 25, be checked. If the Qc diameter is morethan 0.03 1 inch (l& inch) outside the allowed tolerance, thenthe box should be recut.

Tool joint condition bands

Classification paint bands

Stencils for permanent matking forclassification of drill pipe body

lb01 Johtandlkill NIUllbCTdCdOIPipecLassificatoll OfBands

Ren.tilmlclass . . . . . . . . . . . . . ..mwhiteclass2 _...............*.... OneYdowc l a s s 3 . . . . . . . . . . . . . . . . . . . ..olbechmgescrap . . . . . . . . . . . . . . . . . . . . . . . . . OneRed

‘End Joint colorcone of Bands

ScraporShopRepaimble . . . . . . . . . . . . F&dFieldRepair&le. . . . . . . . . . . . . . . . . . . chell

Figure 85-Drill Pipe and Tool Joint Color Code Identification

STD=API/PETRO RP 7G-ENGL 1998 - 0732290 0609793 925 -

RECOMMENDED PRACTICE FOR DRIU S TEM DESIGN AND OPERmNG LMTS 123

d. Magnetic particle inspection--if evidence of pin stretch-ing is found, magnetic particle inspection should be made ofthe entire pin threade4l area especially the last engaged threadarea,todetermineiftransversecracksatepresen~

In highly stressed drilling envimnments or if evidence ofdamage, such as cracking is noted, magnetic particle inspec-tion should be made of the entire box thmaded area, espe-cially the last engaged thread area, to determine if transversecracks are present.

Longitudinal or irregular orientation of cracking may occuras a result of friction heat checking (see 8.6). In that casemagnetic particle inspection of both box and pin tool jointsurfaces, excluding any hardband area, should be performed,with an emphasis on detection of longitudinal cracks-

For crack detection, the wet fluorescent magnetic particlemethod is preferred for tool joint impections. Tool jointsfoundtocontaincracksinthethreadedareasorwithinthetool joint body, excluding any hardband area, should be con-sidered un8t for further drilling service. Shop repair of somecracked tool joints may be possible if the unaffected area ofthe tool joint body permits.e. Minimum tongspace-refer to Figure 86. The criteria fordetermining the minimum tong space for tool joints on useddrill pipe should be based on safe and efficient tonging opera-tions on the rig floor, primarily when manual tongs ate in use.In this regard, there should be sufficient tong space to allowfull engagement of the tong dies, plus an adequate amount oftong space remaining to allow the driller and/or floorhand tovisually verity that the mating shoulders of the connection areunencumbered to allow proper make-up or break-out of theconnection without damage.

It is also recommended that any hard banded surfaces ofthe pin or box tool joint tong space be excluded from the areaof tong die engagement as stated above when minimum tongspace is determined. This practice will ensure that optimumgripping of the tongs is achieved and that damage to tong diesis minimized. In the case where tool joint diameters havebeen worn to the extent that the original hard banding hasbeen substantially removed, the user may include this area indetermining the minimum tong space.

The use of other types of tongs, or devices designed for thepurpose of making and breaking co~ections may require adifferent minimum tong space than what would be deter-mined for manual tongs. In this case, the user should applythe criteria necessary to ensure that the intent of this recom-mendation is satisfied.

Such minimum tong space should not be construed as ameans by which tool joints ate acceptable or not with regardto the strength or integrity of the connection as otherwisespecified in this recommended practice.

13.3.3 General

a Gaugjng--thread wear, plastic deformation, mechanicaldamage and lack of cleanliness may all contribute to errone-ous figures when plug and ring gauges are applied to usedconnections. Therefore, ring and plug standoffs should not beused to determine rejection or continued use of rotary shoul-dered connections.b. Repair of damaged shoulders-when refacing a dam-aged tool joint shoulder, a minimum of material shouldbe removed. It is a good practice to remove not more than‘/,,-inch from a box or pin shoulder at any one refacingand not more than l/,,-inch cumulatively.

It is suggested that a benchmark be provided for the deter-mination of the amount of material which may be removedfrom the tool joint makeup shoulder. This benchmark shouldbe applied to new or recut tool joints after facing to gauge.The form of the benchmark may be a 3/1,&ch diameter circlewith a bar tangent to the circle parallel to the makeup shoul-der, as shown in Figure 86. The distance from the shoulder tothe bar should be $, inch. Variations of this benchmark orother type benchmarks may be available from tool joint man-ufactums or machine shops.

13.3.4 Coverage

Figure 84, dimension A, indicates the length coveredunder the drill pipe classification system recommended in13.2.5. Figure 84, dimension B, indicates the length coveredunder the tool joint inspection standard in 13.3.2. The lengthnot covered by inspection standards is indicated under aCAU77ON heading by dimension C, Figure 84.

Figure 86-Tong Space and Bench Mark Position

STD.API/PETRO R P ? G - E N G L 3998 W 0 7 3 2 2 9 0 0609794 BbL W

124 API RE-ENDED PFUUTTICE 76

13.4 DRILL COLLAR INSPECTION PROCEDURE

The following inspecuon pmcedum for used drill collars isrecommended

a. Visually inspect frill length to determine obvious damageand overall condition.b. Measure OD and ID of both ends.c. Thoroughly clean box and pin threads. Follow immedi-ately with wet fluorescen t magnetic particle inspection fordetection of cracks. A magnifying minor may be used incrack detection of the box threads. Drill collars found to con-tain cracks should be eonsidemd unfit for further drillingservice. Shop repair of cracked drill collars is typically possi-ble if the unaffected area of the drill collar permits.d Use a pmtile gauge to check thmad form and to check forstretched pins.e . Check box counterbole diameter for swelling. In addition,useastraightedgeonthecrestsofthethreadsintheboxchecking for rocking due to swelling of the box. Somemachine shops may cut box counterbores huger than APIstandards, therefore, a check of the diameter of the counter-bore may give a misleading rest&f. Check box and pin shoulders for damage. All field repair-able damage shall be mpaired by refacing and beveling.Excessive &mage to shoulders should be repaired in mputa-ble machine shops with API standard gauges.

13.5 DRILL COLLAR HANDLING SYSTEMS

13.51 While the recent incread usage of grooved drillcolIatshashelpedsavetimeintripping,ithasintroducedsome potential dangem to rig floor operations. These pmb-lemscanbeminin&dbystrictadhemncetoregularlysched-uledilLpxtions.

136.2 When the elevator shoulder on a drill collar is new itis squaxz and has sufiicient area in contact with the elevator(See Fii 87 and 88, and Table 28 for suggested dimen-sionsonnewctrillcollarsandelevators.)Asthecollarisusedfor drilling, however, it wears as shown in Figure 89. Elevatoreontactareais~ by collar OD wear and elevatorspreading load is increased by angle and radius buildup on thedlarand camsponding wtxx on the elevator seat Elevatorcapacity is drastically rednced by spmading action as most alldrill collar elevators are intended for use with square shouldersonly. As an example, with V,,-inch wear on the collar OD, i&-inch radius worn on the comer, and a Sdegree angle on theshoulder, elevator capaoity csn be reduced by as much as 40 to60 pereen& depending on collar size and elevator design.

13.5.3 Before this danger point is reached, the collar andelevator should be shopped and the shoulders brought back toa squam condition. Be very sure the elevator shoulder radiuson the drill collar is cold worked when shoulder is mworked.(See Section 14 for welding procedure limitations.) The top

bore of the elevator should also be checked and corrected atthis time as excessive slack between collar groove diameterand elevator bore decmases shoulder support ama and canalso let too much load shift to the elevator door

13.54 The following irqection pmcedum for drill collarhandling systems is m-commended

a Thoroughly clean and examine elevator adapter for cracks,b. Check links (commonly called bails) for cracks and mea-sure them eye to eye to be certaiu they are within 1 inch ofbeing the same length.c. Thom@Iy clean and examine drill collar elevator forcracks with magnetic particle inspection. Make certain thatelevator safety latch works easily and works every time.Cheek top seat of elevator to be certain it is square. Checkelevator top bore as follows:

1. Center-latch elevator-latch elevator, then wedge frontand back of eievator open and measure at largest part oftop bore straight across between link arms. This methodwill measure total wear in born (of which there wilI bevery little), and wear on hinge pin and latch mrfaces. Wearshould not be allowed to go above ‘/,,-inch on elevatorsfor 55/&ches and smaller drill collars, and V&rich fordrill wllars larger than 5V,-inches.2. Side-door elevators-latch elevator, then wedge latchopen.. Measure top bore from front to back. Use samewear allowance as for center-latch elevators.

d Check elevator shoulder on drill collar to be certain it issquare. (See 13.4 for inspection pmcedum for the drill cohar.)e. Examine drill collar slips for general condition and forwrrect size range for the collars being rnn. Look for cracks,missing cotter keys, loose liners, dull liner teeth, bent backtapers (from catching on drill collar shoulder), and benthandles.f. Examine safety clamp for general condition. Look forcracks, missing cotter keys, galled or stripped thEads,mmded-off nuts or wrenches, dull teeth, broken slip springs,and slips that do not move up and down easily.

Figure 874rill Collar Elevator

-

STD.API/PETRO R P 7G-ENGL 1998 m 0 7 3 2 2 9 0 0609795 7T8 m

RECOM~.~ENDED PRACTICE FOR Dwu STEM DESIGN ANo OPEwnNo Lw4n-s

1116’ maximum

Figure 88-Drill Collar Grooves for Elevators and Slips

Table 28-Drill Collar Groove and Elevator Bore Dimensions

(1)

Drill collarO D R a n g e s

4 to 4s/s

(2) (3) (4) (9 (6) 0 (8)

Gmove- ElevamBoresBasedonDxillCollarOD BasedonDrillCollarOD

Ekv. Oroove s l i p Gluove +o +%DepthA’ R c Depth B’ D2 Top Bore -‘Ia BottomB0re-E

%2 ‘h 4 ” 3fM 3’/~o OD minus Vls O D p l u s ‘IDOD minus ‘IsOD minus ‘I2O D m i n u s 9/,6O D m i n u s %,

O D p l u s VaOD p l u s V8O D p l u s ‘laO D p l u s ‘I8

- Notes:‘4udimemionsininchesunlessotherwisespecitied.Tllesedimensionsarenottobe~tNedasbeingApIstandard.‘AandBdimensionsare~mnominalODofnewdrillcollat.Sngle C and D dimasions are reference and approximate.

Original elevatorshoulder

i- Original drillI collar size

Worn drill collard iamete r

w Radius

m Elevator groove

Figure 8-Drill Collar Wear

13.6 KELLYS

The following inspection pmcedum is recommended forused kellys: Ia. Follow all steps listed in 13.4 for drill collar inspectionprocedure-b. Examine junction between upsets and drive section forcracks .c. Check comers of drive section for narrow wear surfaceparticularly on hexagonal kellys. If wear surface does notextend at least 1/s across flat, the kelly drive bushings shouldbe adjusted if possible and/or examined for wear.d Kelly straightness can be checked either of two ways:

1. By watching for excessive swing of the swivel andtraveling block while drilling, or2. By placing square kellys on level supports (one at eachend of drive section), stretching a heavy cord from oneend of a vertical face of the square to the other, measuringdeflection, rolling kelly 90 degrees, and mpeating proce-dure. On hexagon kellys, use the same method exceptkelly will need to be placed in 12O-degree V-blocks so 1side face of drive section is vertical and deflection mea-surements taken on three successive sides (turning kellythrough 60 degrees each time). I

STD.API/PETRO R P ?G-ENGL l1998 - 0 7 3 2 2 9 0 ObO979b 634 -

126 API RECOMMENDED PFW-IICE 7G

13.7 RECUT CONNECTIONS

The following is recommended for recut comiections:

a When rotary shouldered connections are inspected andfound to require recutting, the recut connection should complywith the requirements of the section entitled ‘Gauging Rrac-tice, Rotary Shouldered Connections” of API Specification 7.b. It is recommended that a benchmark be applied to therecut cmneetion as suggested in 13.3.3.b.

13.8 PIN STRESS RELIEF GROOVES FORRENTALTOOLS AND OTHER SHORTTERMUSAGETOOLS

Following am recommemlations for pin stress reliefgrooves for rental and other short term usage tools:

a Labomtory fatigue tests and tests under actual service con-ditions have demonstrated the beneficial effects of stressrelief contours at the pin shoulder. It is recommended that.,where fatigue failures at points of high stress are a problem,relief grooves be provided- Rental components such as subs,drilling jars, vibration dampeners, stabilizers, reamers, etc.,are usually employed for relatively short periods of timebefore being returned to service centers for inspection andrepair. Connection repairs are made primarily because of gall-ing, shoulder leaks and handling damages while repairscaused by fatigue failures are secondary in occurrence.

Providers of short term usage rental tools have been reluc-tant to take advantage of the benefits of stress relief groovesbecause of the material loss in repairing shoulder and threaddamage. Refacing the pin shoulder and reconditioning thethreads is restricted by the tolerauce on the groove width perAPI SpeciIication 7.b. To encourage the use of stress relief grooves on pins ofshort term usage tools, the following is recommended. Fortools returned to a service facility after each well, such as

rental tools, a modified pin stress relief groove is recom-mended. It is recommended that the modified pin stress reliefgroove conform to Figum 90. Dimensions for DRG are foundin Table 16 of API Specification 7.c. Recommended initial width of the modified stress reliefgroove is 3/4 (+Vi6, 4) inches. After reworking for damagedthreads and shoulders, the width of the modified stress reliefgroove should not exceed 1 ‘I4 inches.d. Technical data-stress at the root of the last engagedthread of the pin depends on the width of the stress reliefgroove (SRG). Table 29 shows caIculated relative stresses foran NC50 axisymmetric finite element model with 61/,-inchbox OD and 3-inch pin ID. A pin with no stress relief grooveis the basis for comparison.

Table 294vlaximum Stress at Root of Last EngagedThread for the Pin of an NC50 Axisymmetric Model

Load condilion Note1 Note2

SRGwidth,i n c h e s StreSS StIess stress S t r e s s

% 8 4 % 8 2 % 8 3 % 8 1 %

1 7 0 % 5 6 % 6 3 % 5 3 %

lVe 7 5 % 6 3 % 7 3 % 64%No SRG lCKI% 100% 100% 100%

Notes:1. Make-up only at 562,000 pounds axial force on shoukler.2.1,125,000poundsaxiaItensionappliedto -on which cllllses shoul-der sqaration.3.4~~lentstressisequalto0.707[(q-~+(q-qy+(q-q~~whem CT,. q, and u, are principle stress.4.Ineachcsse~equivalentstressattherootoftheLestEngagedThtradhasex~theyieldstrengthbecausethese6niteelementcalcula-ti~hanbeenmadeforliacarelasticmataialbehaviotThebehaviorofanactd pin is elastic-plastic.

Figure 9O-Modified Pin Stress-Relief Groove

-

-

STD.API/PETRO R P i’G-ENGL Ii998 m 07322=lO Oh09797 5 7 0 m

REWWENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING Lwrs 127-- I

Note that the least stress is expected for a groove width of 1inch. Consequently, in operations where fatigue failures are aproblem, a groove width of 1 inch is recommended. (See Fig-ure 16 of API Specitication 7.)

14 Welding on Down Hole Drilling Tools14.1 Usually the materials used in the manufacture of downhole drilling equipment (tool joints, drill co&us, stabilizersand subs) are AISI-4135,4137,4140, or 4145 steels.

14.2 These axe alloy steels and are normally in the heattreated state, these materials are not weldable unless properprcmxhms are used to prevent cracking and to recondition thesections where welding has been performed.

14.3 It should be emphasized that areas welded can only bereconditioned and cannot be restored to their original statefree of met.allurgicaI change unless a complete heat treatmentis performed after welding, which cannot be done in the field

15 Dynamic Loading Of Drill PipeNote: For quantitative results, see Refemnce 15, Appendix C.

15.1 When running a stand of drill pipe into or out of thehole, the pipe is subjected not to its static weight, but to a

- dynamic load.

15.2- The dynamic load o&hates between values which amgreater and smaller than the static load (the greater valuesmay exceed the yield), which results in fatigue, i.e., shorten-ing of pipe life.

15.3 Dynamic loading may exceed yield in long strings,such as 10,000 feet.

15.4 Dynamic loading increases with the length of drill col-lar string.

15.5 In the event the smallest value of the dynamic loadtries to become negative, the pipe is kicked off the slips, andthe string may be dropped into the hole.

15.6 The likelihood of dynamic loading resulting in ajumpoff (kicking of the slips) increases as the drilI pipestring becomes shorter and the collar string becomes longer.

15.7 For a long drill pipe string, such as 10,ooO feet, ajumpoff is possible only if drill pipe, after having beenpulled from the slips, is dropped at a very high velocity, suchas 16 ft/sec.

15.6 Dynamic phenomena are severe only when dampingis small, which may be the case in exceptional holes, inwhich there are no doglegs, the deviation is small, the cross-sectional area of the annulus is large, and the mud viscosityand weight are low.

15.9 In case of small damping, the running time of a standof drill pipe should not be less than 15 seconds.

16 Classification Size and Make-UpTorque for Rock Bits

16.1 A classification system for designating roller conerock bits according to the type of bit (steel tooth or insert), thetype of formation drilled, and mechanical features of the bit,was developed by a special subcommittee within the Intema-tional Association of DrilIing Co&actors QADC). The sys-tem was accepted by IADC in March 1987 and approval byAPI was pmposed by the IADC subcommittee. FollowingAPI task group review it was recommended that API acceptthis system of classification for bit designation. The taskgroup recommendation was adopted by the Committee onStandardization of Drilling and Servicing Equipment andsubsequently approved by letter ballot. It was further deter-mined that the appmved form be included in API Recom-mended Practice 7G.

16.2 Bits’ may be classified and designated by an alpha-numeric code on the bit carton with a series of three numbersand one letter keyed to the classification system shown inTables 30 and 31.

16.3 Series numbers 1, 2, and 3 are reserved for milledtooth bits in the soft, medium, and hard formation categories.Series numbers 4.5,6,7, and 8 are for insert bits in the soft,medium, hard, and extremely hard formations.

16.4 Qpe numbers 1 through 4 designate formation hard-ness subclassification from softest to hardest within eachseries classification.

16.5 The seven column listings under the heading, Fea-tures, include seven features common to the milled tooth andinsert bits of most manufacturers. Columns 8 and 9 have beenremoved and reserved for future bit development.

16.6 The form is designed to include only one manufac-turer’s listing on each sheet, and to allow each specific bit des-ignation in only one classi6cation position. It is recognizedhowever, that many bits will drill efficiently in a range of typesand perhaps in more than one series. Particular attention istherefore invited to the note on the form which contains astatement of this principle. It is the responsibility of the manu-facturer and user to determine the range of efficient use in spe-cific instances.

16.7 In using the form shown in Table 30, in conjunctionwith Table 3 1, the manufacturer assigns to each bit designthree numbers and one letter that correspond with a specii?cblock on the form The sequence to be followed is:

Fii number designates Series.Second number designates Qpe.Third number designates Feature.Letter designates additional features, as shown in Table 31.

STD.API/PETRO R P ? G - E N G L L998 - 0 7 3 2 2 9 0 0609796 407 m

128 API RECOMMENDED PFWCTICE 76

STD.API/PETRO R P 7G-ENGL L998 = O - 7 3 2 2 9 0 Ob09799 3 4 3 m

RECOMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING Lwms 1 2 9

Table 31 -lADC Bit Classification CodesFourth Position

Table 32-Flecommended Make-up Torque Rangesfor Roller Cone Drill Bits

Thefollowingcodesareusedinthe4thpositionofthe4-characterIADcbit classiflcatiollcodetoindicateadditioxuddesignfeatures:

CodeFeature COdeFeature

A Airapplicmion’ NB 0C CentexJet PD DeviationControl 0E ExtendedJ& R Reinforaxl Welds”F S Standard Steel Tooth Model’G Ex&aGauge/BcdyI’mection TH UI VJ JetDe&xtion WK x r2hiselhlseltsL Y conicalInsertM z otherInseltshapes

‘Journal bearing bits witb air cimulatim nozzles.2Full extension (welded tubes with nozzles). F%tial extensions should benoted elsewhere.“For percllssion applicalions.%illed twth bits with none of tbe extra features listed in tbis table.As an example, a milled tcuth bit designed for the softest series, softest type

colln~on

23/* API REG

274 API REG

3’1, API REG

4’1, API REG

6v*APlREG

75/* API REG

MinimumMake-up Toque

ftllb

3ooo

4Mo

7mO

12ONl

MaximumMake-up Torque

ft/lb

3500

5500

scoo

14CQO

32000

av, API REG

Note:

- in that series, witb standard gauge, and no exma featms. wilI be designatedl-l-l-sonthebit~.Themanufacturerwillalsolistthisbitdesignationiutbisblackontlxform

Basis of calculations for nxommended make-up torque assumed the useofatbreadcompomdcontaining4Oto6Opemmtbyweightof6mlypowdenxi metallic zinc or 60 percent by weight of finely powderedmetallic l& with not moxe than 0.3 percent total active sulfur, appliedthoroughly to all thnxds and sbouldem (see the caution regarding tbe useof bazanious materials in Appendix G of API Speci6cation 7). Due to theimgular geometry of the ID boxe in rollex cone bits, torque valves axebased on Amated cross-sectional areas and have been proven by fieldexpelien~.

16.8 Classification forms are available fkom: International 16.10 Common sizes for roller bits are listed in Table 34.Association of Drilling Contractors (TADC), F!O. Box 4287, Sizes other than those shown may be available in limited cut-Houston, Texas 77210. ting structure types.

16.9 Recommended torque for roller cone bits is shown inTable 32. Recommended torque for diamond drill bits isshown in Table 33.

Common sizes for fixed cutter bits are listed in Table 35.Sizes other than those shown may be available in limited cut-ting structure types.

STD.API/PETRO R P 7G-ENGL I,998 m 0 7 3 2 2 9 0 OblJ9800 995 -

130 API ~COhMENDED t+ACTlCE 76

Table 33-Fkommended Minimum Make-up Torquesfor Diamond Dri l l Bits

Bit SubPinID O D Make-Up-e

conneclion i n in fvlb

23/* API RBO 1 3 1791*

3v, 2419

3114 3085*

2718 A P I REG I’/, 311, 3cn3*

3’f, 4 6 1 7

3’18 4 6 5 8

3v, API REG 1’12 4v* 5171*

411, 6306*

411, 7 6 6 0

4’12 API RBG 2’/4 51/, 12451*

-% 16476*

6 1 7 5 5 1

6’1, 1 7 7 5 7

711, 37100*

7% 3 7 8 5 7

8 3 8 1 9 3

av, 3 8 5 2 7

WI, 482W

tP/4 5?704*

9 5 9 9 6 6

9’1, 6 0 4 3 0

9’12 6 0 8 9 5

+kNXXT~@nesfoUowedbyauastehkindicatethattheweakermemberfathecmeqamhgoutside~(OD)dboreistbeBOX.FaaU~taquevalue-stbe~memberisthePlN.

Basisof-for-ded~uptolKpleassnmedtheuseofathmadcmpomdcmaihg40to6O~bywtightuf6nelypow-deredmecalliczincoe6operceatbyweightof~lypowdaedmetalliclea4witllnotmlxethr00.3percenttotalactivesulfur,appliedthorwghytoauthdsimdsllodhs (referencetbe~UZ7ON~gtbeuseofhazard-ousm&eridaiaAppendixGofAPISpecificatim7)andusingtbe-ScrewJeckformulainksanda~tstresrof50,000psiintbeboxorpin.wlmkverisweakeL

NOIdtOKJlErangeiS tabdatdvaluepllls 10pexcentHigktorqueval-ueSIMybeUSdlmda- calditioaa

rt*APIREG 3314

Table 34-Common Roller Bii Sizes

S i z e o f B i t , Size of Bi&i n ln.

-

Table 35-Common Fiied Cutter Bit Sizes

STD.API/PETRO R P 7G-ENGL I,998 - 0 7 3 2 2 9 0 0 6 0 9 8 0 3 821 -

A.1 Torsional Strength of EccentricallyWorn Drill Pipe

Assume 1: Eccentric hollow circular section (see FigureA-1).Refereuce: Form&s for Stms & Strain, Roark, 3rd Edition.

-+I+-L- d

D 4-IFigure A-l-Eccentric Hollow Section of Drill Pipe

T _ ND4412xl6xDxF’ (A.11

where

F = I++!%+ 32N2q2(l-N2) (l-N2) (1-p)

+ 4SN2( 1 + 2N2 + 3ti + 2N6)e3 ,( 1 - N ’ ) (1-d) (1-N6)

N = iUD,

4 ;*=-

T = torque, ft-lbs.,SS = minimum shear strength, psi,D = outside diameter, in.,d = insidediameter, in.

Assume 2: The internal diameter, d, remains constant andat the nominal ID of the pipe throughout its life.

Assume 3: The external diameter D is d + t nominal + fminimum; i.e., alI wear occurs on one side. This diameter isnot the same as diameter for uniform wear.

Note Torsional yield strengths for Premium Class, Table 4, arui Class 2,Table6werecalculated~Equationkl,usingtheassunoptioathatwearislmifolm cm the eaernal surface.

A.2 Safety FactorsValues for various performan~ properties of drill pipe are

given in Tables 2 through 7. The values shown are minimumvalues and do not include factors of safety. In the design ofdrill pipe strings, factors of safety should be used as are con-sidered necessary for the particular application.

A.3 Collapse Pressure for Drill PipeNote: See API Buktin 5C3 for derivation of equations in k3.

The minimum collapse pressure given in Tables 3,5, and7 are calculated values determiued from equations in APIBulletin X3. Equations A.2 through A.5 are simplified equa-tions that yield similar results. The D/r ratio determines theapplicable formula, since each formula is based on a specificD/t ratio range.

For minimum collapse failure in the plastic range withminimum yield stress limitations: the external pressure thatgenerates minimum yield stress on the inside wall of a tube.

-

APPENDIX A-STRENGTH AND DESIGN FORMULAS

(A-2)

Applicable D/t ratios for application of Equation A.2 are asfollows:

Dlt Ratio

E75 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..13.6oandles s

X95...............................................12.85andles s

G105..............................................12.57andles s

S135..............................................11.92andl ess

For minimum collapse failure in the plastic range:

P, = Ym[(&)-Bj-c (A.31

Factors and applicable D/t ratios for application of Qua-tion A.3 are as follows:

FomuIa Factors

A B C Dlt Ratio

E75 3.054 0.0642 1806 13.60 to 22.91x95 3.124 0.0743 2404 12.85 to 21.33G105 3.162 0.0794 2702 12.57 to 20.70s135 3.278 0.0946 3601 11.92to 19.18

1 3 1

I . , . r. .-

STD.API/PETRO R P 7G-ENGL 1998 - 0 7 3 2 2 9 0 Ob09802 7bB -

1 3 2 API RE~CIMMENDED PRACTICE 76

-

For minimum collapse fm in conversion or lransitionzone hetweenelastic andplasticrange:

Pc = Y&&)-B] (A-4)

Factors and applicable D/t ratios for application of Equa-tion A.4 are as follows:

FolDllhFactas

A B D/r Ratio

E75 1.990 0.0418 22.91 to 32.05x 9 5 2.029 0.0482 21.33 to 28.36G105 2.053 0.0515 20.70 to 26.89s135 2.133 0.0615 19.18 to 23.44

For minimum collapse failure in the elastic range:

P, = 46.95 x lo6(D/t)[(D/t) - 112

64.5)

Applicable D/t ratios for application of Equation A.5 are asfollows:

orade D / t R a t i o

E75 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32.05 and greater

x95 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28.36 and greater

G105 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .26.89mdgreater

s135 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23.44and~

wherePC = minimumcollapse~,psi*D = nominal outside diameter, in.,*t = nominal wall thickness, in.,Y,=material minimum yield strength, psi.

N&S:~llapspmssnmsforusddrillpi~tned . lbyadjustinglhenomi-naloutside~,D,andwallthickness,t,asifthewearisunifonnontheOUtSi&OftbL?pipebOdy~theti~diameta~coostaat values ofDandt~eachclaasofuseddrillpipefollaw.~valuesare~obe~~~~~Equationk2,A3,A4,orA5,dependingontbeD/tratio,tDlkmmlm? c&apse plessule.

Remiutn Qasp: t = (0.80) (mmiwd wall), D = nomid OD - (0.40) (nomidwall)

Class 2 t = (0.70) (nominal wall), D = nominal OD - (0.60) (nominal wall)

A.4 Free Length of Stuck PipeThe relation between differential stretch and f&e length of

astuckstringofsteelpipeduetoa~~tialpullis:

L1 =EXeX W,,

40.8P ’ (A-6)

wherer, = lengtlloffRedrillpipe,fL,E = modulus of elasticity, lbrm.?e = differentialstretc~ in.,

W, = weight per foot of pipe, lb&t.,P = difbential pull, lbs.

Where E = 30 x 106, this formula becomes:

A.5 Internal PressureAS.1 DRILL PIPE

2Y tPi=*,

where

L _ 735,294xexw&l1- P (A-7)

(A.@ IPi = internal pressllre, psi,Y, = material minimum yield strength, psi,

t = remaining wall thickness of tube, iIL,D = nominal outside diameter of tube, in.

Notes:l.ID&lMl pmsmesfmewdriUpipeinTable3wemd .u ’ albyusingthen~wallthickoessfortintheabove~~tmdmultiplyingbythe~-tar 0.875 due to pexmissiile wall thickness tolerance of miuus 12’4 percent2.htemalpressuxesforuseddrillpipewercdetermhedbyadjustingthenominalwallthichKssacoordingbfootnotesbelowTable5and7andusingthe nominal outside diametm, in the above &pation A&

A s . 2 KELLYS

Pi = LVhz - (Dm - 20’1

A3 ( DpL)4 + (D, - 2t)4 ’(A-9) 1

wherePi = intelllalpressure,psi,Y, = material minimum yield strength, psi,

Dm. = didance across drive section flak% in.,t = minimumwall,iIL

Note:Tbe-ontistheIhilINmWtdltbiCklleSSOftbe4in~Ulandmustbedeteminedineachcflsethroughtheuseofan~tllic~gaugemsimilardevi~.

A.6 Stretch of Suspended Drill PipeWhenpipeisfreelysuspendedinafluid,thestretch~to

its own weight is:

e = &i [W,-2Wf(1-p)], w-10)

wheree = stmst&in.,

4 = lengthoffreedrillpipe,R,

STD.API/~ETRO R P 7G-ENGL L998 m 0 7 3 2 2 9 0 0609803 b T 4 m

REC~MMENDELI PRACTICE FOR DRIU STEM DESIGN AND OPERATING LIMITS 133-

E = modulus of elasticity, psi,W, = weight of pipe material, lbku ft.,w, = weight of fluid, Ibku ft.,m = Poisson’s ratio.

For steel pipe where W, = 489.5 lbku ft. E = 30 x 106 psiand p = 0.28, this formula will be:

L12e = - [489.5 - MIW,],72 x lo7

(A.1 1)

or

e = L129.625 x lo7

[65&l- 1.44W,], (A.12)

whereW, = weight of fluid, lbku ft.,

Wg = weight of fluid, lb/gal.

A.7 Tension

whereP=Y,A, (A.13)

P = minimum tensile strength, lbs.,Y, = material minimum yield strength, psi,A = cross-section area, sq. in. (Table 1, Column 6, for

drill pipe)-

A.8 Torque Calculations for RotaryShouldered Connections (see TableA-l and Figure A-2)

A.8.1 TORQUE TO YIELD A ROTARYSHOULDERED CONNECTION

Ty =

where5 = turning moment or torque required to yield, ft-lbs.,Y, = material minimum yield strength, psi,p = leadofthu%&in.,f = coefficient of friction on mating surfaces, threads

and shoulders, assumed 0.08 for thread com-pounds containing 40 to 60 percent by weight ofhnely powdered metallic zinc. (Reference the cau-tion regarding the use of hazardous materials inAppendix G of Specitkation 7.),

q = Vz included angle of thread (Figures 21 or 22,Speciiication 7), degrees,

R = C+[C-(Lpc -.625)xtprx l/12 ]t 4 9

Figure A-2-Rotary Shouldered Connection

STD.API/PETRO R P 7G-ENGL I,998 - 0 7 3 2 2 9 0 0 6 0 9 8 0 4 5 3 0 -

134 API RECOMMENDED PFMCI-ICE 76

4 = length of pin (Specikuion 7, Table 25, Column9), in.3

R, = I/., (OD + Q,), in.The maximum value of R, is limited to the valueobtained from the calculated OD where A, = Ab,

A = cross-section area A, or A,, whichever is smaller,qin.

where

A,= a [(C-By--P] = without relief grooves,

o r

AP = z [(Dx2 - ZP] = with relief grooves,

whereDRG =

C=

ID =

B =

H =

s, =

tpr =

diameter of relief groove (Spec&ation 7, Table16, Column 5), in.,pitch diameter of thread at gauge point (Specika-tion 7, Table 25, Column 5), in.,inside diameter, in.,

2H( 1z - s, + tpr x ‘f* x 1112,

head height not truncated (Specification 7, Table26, Column 3), in.,root truncation (Spec&ation 7 , Table 26, Column51, ill-9taper (Speci6cation 7, Table 25, column 4), in&L,

A,= f loDZ-<a-wl,

PiT4 T3I I Pin yield

-where

OD = outside diameteqin.,12, = box counterbore (SpecZcation 7, Table 25,

Column 1 l), in.,E = lpr x 3/s x VI2

A.8.2 MAKE-UPTORQUE FOR ROTARYSHOULDERED CONNECTIONS

T = SA12

whereA = A, or AP whichever is smaller, AP shall be based on

pin connections without relief grooves, sq. in.,S = recommended make-up stress level. psi.

A.89 COMBINEDTORSION AND TENSION TOYIELD A ROTARY SHOULDEREDCONNECTION

Figure A-3 shows the limits for combined torsion and ten-sion for a rotary shouldered connection. The connectionnomenclature is de&xl in A.&l. The loads considered in thissimplified approach are torsion and tension. Bending andinternal pressure are not include4& nor is the contribution ofshear stress due to torsion. A design factor of 1 .l should beused to provide some safety margin. This safety margin maynot be suflicient for cases involving severe bending or ele-vated temperatum. (See 4.5.)

The failure criteria is either torsional yield or shoulder separation.

Applied Torsion

Figure A-3-Limits for Combined Torsion and Tension for a Rotary Shouldered Connection

S T D . A P I / P E T R O R P 7G-ENGL l1998 D 0 7 3 2 2 9 0 0 6 0 9 8 0 5 4 7 7 -

REWMAEIUDED PRACTICE FOR DRIU STEM DESIGN AND OPEFWT~NG Lwms 135

The end points for tbe limits lines are defined by five equa-tions:

Pl = 2 A ,c-1

Tl = (&)4(&+%+&f)

T2 = (&$&+~+Rsf)

T3 = (i334(&+%)

Depending on the conn~on geometry, Z3 may be greateror smaller than T4. The same is true for Zl and 72.

The line (0,O) to (T4, PI) represents shoulder separationfor low makeup torque. The line (Z&O) to (23, Pl) representspin yield under the combination of torque and tension. Theline (Zl, 0) to (?“l, Pl) represents box yield due to torsion.The horizontal line from Pl represents maximum tensionload on the pin.

A.9 Drill Pipe Torsional Yield StrengthA.9.1 PURE TORSION ONLY

Q=O.O961673Y,

D v

w h e r eQ = minimum torsional yield strength, ft-lb.,Y, = material minimum yield strength, psi,

.I = polar moment of inertia

= &(04-(P)fortubes

= 0.098175 (0” - &),D = outside diameter, in.,d = inside diameter, in.

A.9.2 TORSION ANDTENSION

0.096167.IQT= D

yz _ P*m-g*

w h e r eQT = minimum torsional yield strength under tension,

Mb.,

J = polar moment of inertia

= &(p-@)fortubes

= 0.098175 (D - &),D = outside diameter, in.,d = insidediameter,in.,

Y, = material minimum yield strength, psi,P = total load in tension, lbs.,A = crosssectionarea,sq.in.

A.10 Drill Collar Bending Strength RatioThe bending strength ratios in Figures 26 through 32 were

determined by application of Equation A.17. The effect ofstress-relief features was disregarded.

whereBSR =

z, =zp =D =d =b =

R =

o w8 (D4--b4)

D

o w8 W4-&

R

D”-b4D=

R4-d’ ’R

(A.17)

bending strength rat io,box section modulus, cu. in.,pin section modulus, cu. in.,outside diameter of pin and box (Figure AA), in.,inside diameter or bore (Figure A-4), in,tlmad mot diameter of box threads at end of pm(Figure A-4), in.,thread root diameter of pin threads 3/4 inch fromshoulder of pin (Figure A-4), in.

To use Equation A.17, fbst calculate:Dedendzm, b, and R

De&r&m = t -f,,

w h e r eH = tbread height not truncated, in.,f, = root truncation, in.

(A.18)

b = c- tpr(L,,- -625)1 2

+ (2 x dedendum) , (A.19)I

STD.API /PETRO RP ?G-ENGL L998 - 0?322=lO 060980b 3 0 3 -

1 3 6 API RECOMMENDED PF~ACI-ICE 7G

I-Pin length, Lpc

7

I T

Figure A4-Flotary Shouldered Connection Locationof Dimensions for Bending Strength

Ratio Calculations

whereC = pitch diameter at gauge point, in.,

tpr=taper,inSft.

R=C-(2x&&h)-(tprx’/,x’/,~ (A.20)

An example of the use of Equation A. 17 in determining thebending stxength of a typical drill collar connection is as fol-lows:

Detemine the bending strength ratio of Qill collar NC46-62 (6V., OD x 213/,J ID connection.

D = 6.25 (Specification 7, Table 13, Column 2),d = 2’V = 2.8125 (Specification 7, Table 13, Col-

d3).C = 4.626 (Spe&cation 7, Table 25, Column 5),

Taper = 2 (Specification 7, Table 2.5, Column 4),I+ = 4.5 (Specification 7, Table 25, Column 9),

H = 0.216005 (Specification 7, Table 26, Column 3),f, = 0.038000 (Speci&&on 7, ‘lhble 26, Column 5).

First calculate dedeudum, b, and R

Dedendum = f -f, = F - .038000 = .07OcMI25

b _ C- tpr(L,,- .625)12

+ (2 x dixsmlh)

b = 4.626 - 2(4.5 - .625) + (2 x .0700025)1 2

b = 4.120,R = C-(2x&&~)-(~rx’/,x’/,z)R = 4.626 - (2 x .0700025) - (2 x V8 x ‘/&R = 4.465.

Substituting these values in Equation A. 16 de&, ’ thebending strength ratio as follows:

B S R (NC46-62) = Dy

R4-d4R

(6.25)4- (4.120)46.25

= (4.465)4- (2.8125)44.465

= 2.64:1

A.1 1 Torsional Yield Strength of KellyDrive Section

The torsional yield strength of the kelly drive section val-ues listed in Tables 15 and 17 were derived i&u the follow-ing equation:

y = O-577 Y,[0.200(a~ - b3)]12 ,

whereY, = tensile yield, psi,a = distance across flats, in.,b = kellylmre,in.

A.12 Bending Strength, Kelly DriveSection

The yield in bending values of the kelly drive section listedin Tables 15 and 17 were de&mined by one of the followingequations:

a. Yield in bending through comers of the square drive sec-tion, YBc f&lb:

YY,,, (0.118 u4- 0.069 b>

BC = 12a

b. Yield in bending thmugh the faces of the hexagonal drivesection YBp, ft-lb:

yBP

= Y,,, (0.104a4- 0.085 b>12a

A.1 3 Approximate Weight of Tool JointPlus Drill Pipe

Approximate Weight of Tool Joint Plus DrilI PipeAssembly, lb/ft =

Approximate Adjusted + Approximate Weightweight of Drill Pipe x 29.4 of Tool Joint >

Tool Joint Adjusted Length + 29.4,

m-21)

STD.API/PETRO R P 7G-ENGL I~998 m II732290 Ob09807 24T m

RECOMMENDED PmcncE FOR DRIU STEM DESIGN AND OPERATING LIMITS 137

whereApproximate Adjusted Weight of Drill Pipe, lb/ft =

Plain End Weight + Upset Weight29.4

(A.22)

Plain end weight and upset weight are found in API Speci-fication 5D.

Approximate Weight of Tool Joint, lbs =0.222 LQY - &) + 0.167 (03 - Dm3) - 0.501 &(D -DA

(A.23)

Dimensions for L, D, d, and DTE are in API Speci6cation 7,Figure 6 and Table 7.

Adjusted Length of Tool Joint, ft =L + 2.253 (D - DTE)

1 2(A.24)

A.14 Critical Buckling Force for CurvedBoreholes272WfJ31s~

A.14.1 The following equations define the range of holecurvatures that buckle pipe in a three dimensionally curvedborehole. The pipe buckles whenever the hole curvature isbetween the minimum and maximum curvatures defined bythe equations.

ifF < 4xExfb 12xh,xR,

pipe not buckled ,

SF 2 4xExZb 1 2 x h,xR,’

w _ 12xh,xF,2cq - 4xExZ ’

B vmar = ~[(We~-(~~,“‘-Wmx sin*],

whereFb = critical buckling force (+ compressive) (lb),

B,,+., = minimum vertical curvature rate to cause buck-ling (+ building, - dropping) (O/l00 ft),

B VlllOX = maximum vertical curvature rate that bucklespipe (+ building, - dropping) (o/l00 ft),

Kq = equivalent pipe weight requhed to buckle pipeat Fb axial load,

E = 29.6 x 106 psi,

z _ O-7854( OD4 - zD4)16 ’

w = w 65.5-MWm 0 65.5 >

buoyant weight of pipe (lb&t),

w, = achlalweightinair(lb/ft),MW = mud density (lb/gal),

hc= DH-T( > radial clearance of tool joint to

hole (in.),DH = diameter of hole (in.),

TJOD = OD tool joints (in.),

By = ~B;-B; iateral~ur~aturerate~/iooft),

BT = total curvature rate (o/lOO ft),

R L = y lateral build radius (ft),L

9 = inclination angle (deg).

A.1 4.2 If the hole curvature is limited to the vertical plane,the buckling equations simplify to the following:

w = 12xh,xF,?-2 4xExZ ’

B = -5730 x (W,, + w, x sine)Vmtn

Fb

9

B Vmax =5730 x (W,, - w, x sine)

Fb1

whereB,, = minimumverticalcurvaturerateforbuckling

(+ building, - dropping) (O/l00 ft),B vnvrr = maximum vertical curvature rate for buckling

(+ building, - dropping) (VlOO 13).Fb = buckling force (lb),E = 29.6 x 106 (psi),

I= ~(OD~-ZD~),

W, = buoyant weight equivalent for pipe in curvedborehole (lb/ft),

w _ w 65.5 -MWm- a 65.5 >

buoyant weight of pipe (lb/ft),

W, = actual weight of pipe in air (lb@,MW = mud density (lb/gal),

h = D H - T J O Dc 2 >

radial clearance of tool joint to

hole (in.),DH = diameter of hole (in.),

TJOD = OD of tool joint (in.),8 = inclination angle (deg).

STD.APIlPETRO RP 7G-ENGL I,998 - 0 7 3 2 2 9 0 0 6 0 9 8 0 8 186 -

138 API REWMMENDED PFLACITCE 76

A.14.3 Figures A-5 and A-6 show the effect of hole curva-ture on the buckling force for 5-inch and 31Wnch drillpipe.Figure A-7 shows the effect of lateral curvatures on the buck-ling force of 5-&h drillpipe. For lateral and upward curva-tures, the critical buckling force increases with the total- r a t e .

A.1 5 Bending Stresses on CompressivelyLoaded Drillpipe in CurvedBoreholes33p34

A . 1 5 1 Thetypeofloadingcanbedetc ’ Ibycompar-ing the actud hole curvature to calculated values of the criti-cal curvatures that define the transition from no pipe bodycontact to point contact and from point contact to wrap con-tact The two critical curvatures are computed from the fol-lowing equations.

B, =57.3x 100x 12xAD

JxL[tan(q$+)-A]

whereB, = the critical hole curvature that defines the tran-

sition from no pipe body contact to point con-tact (VlOO ft),

A0 = (TJOD - OD),TJOD = tool joint OD (in.),

O D = pipe body OD (in.),

(h),

L = lengthofonejointofpipe(in.),E = Young’s modulus 30 x 106 for steel (psi),I = moment of inertia of pipe body (in)

= n( OD4 - ZD4)64 ’

F = axial compressive load on pipe (lb),ID = pipe body ID (in.).

B, = 57.3 x 100x 12xADr 1'

Where

B, = the critical curyafure that dehes the transitionfrom point contact to wrap contact (WOO ft),

AD = (TJOD - OD),TJOD = tool joint OD (in.),

OD = pipebodyOD(h.),

“*J = m,

L = length of one joint of pipe (in.),E = Young’s modulus 30 x 106 for steel (psi),

Z = moment of inertia of pipe (in.3

= sc(OD4-ID4)64 ’

F = axial compressive load on pipe (lb),ZD = pipebody ID (in.).

A.152 If the hole curvatme is less than the critical curva-ture required to begin point con= the maximum bendingstress is given by the following:

s, = BxODxFxJxL

57.3x1OOx12x4xZxsin

wheres, = mzminmmbendingstIess@si),B = hole curvature,F = axial compressive load on pipe (lb),

J = + I’*( ‘>

(in.),

E = Young’s modulus 30 x 106 for steel (psi),Z = moment of inertia (in.)

= n(OD4-1D4)64 ’

O D = pipe body OD (in.),ID = pipe body ID (in.).

L = length of one joint of pipe (in),

A.1 5.3 If the hole curvature is between the two critical cur-vaturescalcula@thepipewiUhavecenterbodypointcon-tad and the maximum bending stress is given by thefollowing equation:

ExODxU*Sb = 4R

Axsin9+Bxcos~

J

,vxsinu-4x&t*

whereE = Young’s modulus, 29.6 x 106 for steel (psi),

O D = pipe body OD (in.),ID = pipe body ZD (in.),

Lu= z-9

L = length of one joint of drillpipe for point contactof pipe body m-h

L = L, forwrap contact (in),

STD.API/PETRO R P 7G-ENGL Lqs8 m 0 7 3 2 2 9 0 0607807 olI2 m

RECCMMENDED PFIACTCE FOR DRIU STEM DESIGN AND OPEtwnruG LIMITS 1 3 9

E&in. 19.5 lb/it Drill Pipe, 6.375 in Tool Joint10 pp9 mud, 90 deg 8.5 in hole

-,,L-*..Pipe isb”cklec’ t.+ i ~.-~--.-r-,--,“--------.~----------.--”i

-JJ-..I . f. . ...““- f’ j . . ..-..................... . ~ . . . . ‘J . . . . . . . . ..-.

0

Vertical build rate--“/l 00 ft.

Figure A-5-Buckling Force vs Hole Curvature

STD.API/PETRO R P 7G-ENGL la%98 - 0 7 3 2 2 9 0 Ob09ALO 834 m

1 4 0 API RECZOMMENDED PRACTICE 76

100

9 0

60

70

60

50

40

30

20

10

0

3.5-in. 13.3 Ib/ft Drill Pipe, 4.75 in Tool Joint10 ppg mud, 90 deg 6.0 in hole

0

Vertloal build ratio/l 00 ft.

Figure A-6-Budding Force vs Hole Curvature

STD.API/PETRO R P 7G-ENGL I,998 m 0 7 3 2 2 9 0 ObO98LL 7 7 0 -

REKIMMENDED PRACTICE FOR DRIU STEM DESIGN AND OPERATING LIMITS 141

1 - -

5-in. 19.5 IbKt Drill Pipe, 6.375 in Tool JointIO ppg mud, 90 de9 8.5 in hole

W

9 0

_ .p.,........-,..........-

_ . _ ”

_ “ . . ”

-

. _ _

4 0

3 0

--~-I

4 sTotal curvature rat~VlO0 ft.

s io

Figure A-7-Buckling Force vs Hole Curvature

S T D . A P I / P E T R O R P 7G-ENGL I~978 - Oi’32290 ObO=l8L2 607 -

142 API RECZOMENLED PFWTICE 76

J _ E x I- C-1

“2F (in.),

Z = g(oD4-rD4) (in.4),

ALI = diameter differen= tool joint minus pipe bodyOD,

AD = (TJOD - 00) (in.),TJOD = tooljoint 00(h),

R = 57.3xlOOx12B,B = hole curyafure (Woo ft).

A.154 If the hole curvm exceeds the critical curvaturethat separates point contact from wmp contact, we need tofirst compute an effixtive pipe length in order to c&u&e themaximum bending stress. The effective pipe span length iscalculated from the following equation by trial and error untilthe calculated curvature matches the actual hole curvature:

B = 57.3x 100x 12xADr

whereL, = effective span lena (in),B = hole cuvatme (Woo ft),

AD = diameter diffmce between tool joint and pipeMY*

A D = TJOD - OD (ha),T J O D = tool joint OD (in.),

OD = pipe body OD (in.),a, = pipebodyzD(in.).

E = Young’s modulus 29.6 x 106 for steel (psi),

z= G(oD~-zD~),

F = axial compressive load (lb),L= length of pipe body touching hole (in.),L, = L - L , ,

L = length of one joint of pipe (in.).

A15.5 The maximumbendingstressescauthenbecom-puted using the equation for point contact and a pipe bodyleugth equal to the &ective span length.

A.1 5.6 One of our major concerns when drilling with cum-pressively loaded drillpipe is the magnitude of the lateral con-tact forces between the tool joints and the wall of the hole andthe pipe body and the wall of the hole. Various authors havesuggest4 operating limits in the range of two to three thou-sand pounds or more for tool joint contact faces. There are nogenerally accepted operating limits for compressively loadedpipe body contact forces. For loading conditions in whichthere is no pipe body contact, the lateral force on the tooljoints is given by:

LFT, = FxLxB57.3~100~12’

whereFTI = later-d force on tool joint (lb),

L = length of one joint of pipe (in.),B = hole curvature (WOO ft.).

A.15.7 For loading conditions witb point or wrap contact,the following equations give the contact forces for the tooljoint and the pipe body:

1-4RxAD

LFT, = 2xExIxU2 L,”RxL,

I

,

where

LFpip = F+L - LF,

LFQ = lateral fonze on tool joint (lb),LF* = lateral force on pipe body (lb),

& = L - L , ,L,= length of pipe (in.>,L, = Lforpointcontact (in.),L, = effective span length for wrap contact,

R =57.3 x loo x 12

BB = hole curvature (“/lo0 ft.),

L,u= z

(j,.p,

ALa = dkmwter difhmce tool joint minus pipe OD (in.),m = TJOD - OD (in.),

Z = &(00~-zD*). I

Table A-l-Rotary Shouldered Connection Thread Element Information

(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13)

CC3lltl~tiOllm

NC10

PitchDiameter

C

NC12

NC13

NC16

NC23

NC26

NC31

NC35

iI NC38

NC40

NC44

NC46

NC50

NC56

NC61

NC70

NC77

511, I F

6’18 IF

2318 Rm

2’18 REG

3’1, REG

4’1, RI33

5’Iz REG

6-78 REG

7518 REG

8’18 REG

2’18 FH

3112 FH

4’12 FH

511, FH

6’18 FH

231, SLH90

2V, SLH90

3’J2 SLH90

1.063000

1.265CGO

1.391aM

1.6o9ooo

2.355000

2.668ooO

3.183CKKl

3.53 1000

3.808000

4.072000

4.417cmO

4.626000

5.041700

5.616000

6.178Mx)

7.053cm

7.741ooo

6.189000

7.251000

2.365370

2.740370

3.239870

4.364870

5.234020

5.757800

6.714530

7.666580

3.364000

3.734OcKl

4.532000

5.591m

6.519600

2.5780X)

3.049000

3.688000

T a p e r

1.500000

1SOOOOO

1SOOOOO

1.5Ooam

2.oOom

2.000000

2.aIoam

2.OOOoo0

2mOGOO

2.OOOOOO

2.OOOOOO

2.OoOOOO

2.cmcm

3.OOOOOO

3.000000

3.mOaxl

3.000000

2.oOmoO

2.lxlO#O

3.000000

3.amOO

3.000000

3.OOOOOO

3.OOOOOo

2.OoOoo0

3.000000

3.OOOOoO

3.000000

3.000000

3.000000

2.000000

2.000000

1.250000

1.25MlOO

1.25OC00

Tlmad Stress Relief BoreBack Low LowPin Height Not Root Nominal Thread Angle Groove Cylinder Torsue Tque Bevel

Length Truncated TlUIlCatiOIl counterho~ Pitch 8 Diameter Diameter coullterho~ Diameter

O.O4OfXO 1.204OOo - -1.5OOOOO

1.7mlOO

1.750000

1.750000

3.OOOOOo

3.OOmm

3.5OOGQo

3.750000

4.OOaOo0

4.5Ooam

4.5oom

4.500000

4.5OOcOo

5sKJOoOO

5.500000

6.OQOOOO

6.5OOWO

5.000000

5.OoOOOO

3.amOo

3.5OOGuO

3.750000

4.25CNXJO

4.75aOoO

5.OOOOm

5.25CICMl

5.375ooo

3sOOoOO

3.75Oml

4.axmo

5.oOOoOO

5.OOoOOO

2.812500

2.937500

3.187500

0.144100

0.144100

0.144100

0.144100

0.216005

0.216005

0.216005

0.216005

0.216005

0.216005

0.216005

0.216005

0.216005

0.215379

0.215379

0.215379

0.215379

0.216005

0.21M105

0.172303

0.172303

0.172303

0.172303

0.215379

0.216005

0.215379

0.215379

0.172303

0.172303

0.172303

0.216005

0.216005

0.166215

0.166215

0.166215

0.040600

0.040600

0.040600

0.038ooO

0.038ooO

0.038ooO

0.038cmO

0.038ooO

0.038KIO

0.038000

0.038ooO

0.038m

0.038000

0.038000

0.038000

0.038000

0.038000

0.038MKl

0.020000

0.020000

O.O2OOOO

0.02OCKXJ

0.025ooo

osY25000

0.025m

0.025000

0.020000

0.02oooO

0.020000

0.025GQo

0.025m

0.034300

0.034300

0.034300

1.406000

1.532ml

1.751000

2.625000

2.937500

3.453125

3.812500

4.078125

4.343750

4.687500

4.906250

5.312500

5.937500

6.500000

7.375Om

8.062500

6.453125

7.515625

2.687500

3.062500

3.562500

4.687500

5.578125

6.062500

7.093750

8.046875

3.687500

4.046875

4.875000

5.906250

6.843750.

2.765625

3.234375

3.875ooO

.166667

.166667

.166667

.25OWl

.250000

.25OOoO

.25OOIM

.250000

.250000

-250000

.25oooO

.25oooO

a250000

.25OOW

.25OOW

.25OOm

.250000

.250000

.2OOOoo

.2mOOO

.2OOOOO

.2axm

.25C000

.25oooO

.25OOOfl

-250000

.200000

.m

.2ooooO

.250000

.25OOOo

.333333

.333333

.333333

3 0

3 0

30

3 0

3 0

3 0

3 0

30

30

30

3 0

30

3 0

3 0

3 0

3 0

3 0

3 0

3 0

3 0

30

3 0

3 0

3 0

3 0

3 0

3 0

3 0

3 0

3 0

3 0

30

4 5

4 5

45

- -- -- -

2.140625 2.218750

2.375000 2.531250

2.890625 2.953125

3.234375 3.234375

3.515625 3.468750

3.781250 3.656250

4.187500 4.OOa)Oo

4.328125 4.203125

4.75Ocm 4.625000

5.296875 4.796875

5.859375 5.234375

6.734375 5.984375

7.421875 6.546875

5.890625 5.687500

6.953 125 6.75oooO

2.015625 2.062500

2.390625 2.3 12500

2.906250 2.718750

4.015625 3.718750

4.859375 4.5OmOO

5.421875 5.281250

6.406250 5.859375

7.296875 6.781250- -

3.421875 3.218750

4.203125 3.953125

5.25oooO 5.109375

6.171875 6.046875

2.328125 2.531250

2.671875 2.984375

3.312500 3.593750

-------------------------

7.7mOO

9sMOoOo-

-

-

-

-

-

-

-

-------------------------

9.250000

10.5OOmO-

-

-

-

-

-

-

-

Table A-l-Rotary Shouldered Connection Thread Element Information

(1) (2)Piteh

Connsction D i a m e t e r

PI= C

(4)

Pin

Length

(5)

Height Notnuneated

(6) (7) (8) (9) (10) (11) (12) (13)Thread Stress Relief Bore-Back LOW LAnv

Root Nominal Angle Omove Cylinder TorsUe TorqueBevellhmeatioo counterhole Pitch e Diameter Diameter CountiE Diametex

3V2 H-90 3.929860 2.OalOOO kmoooo 0.141865 0.017042 4.187500 .2857 10 45

4 H-90 4.303600 2.OOoOOO 4.25OOOo 0.141865 0.017042 4.562500 .285710 45

4’1, H-90 4.637600 2.cmOoO 4.5oom 0.141865 0.017042 4.890625 a2857 10 45

5 H-90 4.908 100 2.000000 4.75!xlOO 0.141865 0.017042 5.171875 .285710 4 5

5’12 H-90 5.178600 2.000000 4.75mO 0.141865 0.017042 5.437500 a2857 10 4 5

6’13 H-90 5.803600 2.omam 5.000000 0.141865 0.017042 6.062500 a285710 4s

7 H-90 6.252300 3.oOooo0 Mooooo 0.140625 0.016733 6.562500 .2857 10 4 5

7s/B H-90 7.141100 3.amam 6.125ooO 0.140625 0.016733 7.453125 .285710 4 5

8’/8 H-90 8.0161al 3.OOOOOO 6.625000 0.140625 0.016733 8.328125 -285710 4 5

23iB PAC 2.203000 1.5OOfMO 2.375ooO 0.216224 0.057948 2.406250 .25OMNl 3 0

27/s PAC 2.369000 1.5OOOM 2.375000 0.216224 0.057948 2.578125 .25OmO 30

3’1, PAC 2.884ooo 1.5O@XQ 3.25mO 0.216224 0.057948 3.109375 .2xHxKl 30

2’/8 SH 2.230000 2.cmm 2.875ooO 0.216005 0.038000 2soOoo0 .250000 30

2’/s SH 2.668000 2.OoOooO 3.OoOOo0 0.216005 0.038m 2.937500 .25OOOo 30

3V2 SH 3.183tXlO 2.000000 3.5Omm 0.216005 0.038000 3.453125 .250000 3 0

4SH 3.604000 2.amOOO 3.5amO 0.216005 0.038ooO 3.875000 .25OOMl 3 0

4’1, SH 3.808ooO 2.000000 4.000000 0.216005 0.038ooO 4.078125 .25oooo 3 0

2718 Xl-I 3.119000 2.000000 4 . m 0.216005 0.038ooO 3.359375 .250000 3 0

3’1, XH 3.604000 2.OlxloCm 3.5OcmOO 0.216005 0.038ooO 3.875ooO .25axo 3 0

5x.H 5.041700 2JmO000 4sooooo 0.216005 0.038ooO 5.312500 .250000 3 0

2’/( OH SW 2.588CUKl 1SOOOOO 2.375ooO 0.216224 0.057948 2.796875 .25OONJ 3 0

2”/( OH LW 2.588ooO 1.5OONM 2.375COO 0.216224 0.057948 2.796875 .25CKKQ 3 0

2’/, OH SW 2.984ooo 1.5OOOfM 2.875000 0.216224 0.057948 3.203125 .25OoOO 3 0

271~ OH LW 2.984m 1.500000 2.5oOOOO 0.216224 0.057948 3.203125 .250000 3 0

3’1, OH SW 3.72mOO 1.5OEOO 3.25ocal 0.216224 0.057948 3.953125 .25mlO 3 0

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4.687500

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2.171875

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STD.API/PETRO R P 7G-ENGL I,998 m 0 7 3 2 2 5 0 lJbO9835 3l,b m

Many of the topics covered in Recommended Practice 7Ghave been the subject of significant investigation by variousparties in the industry. Following is a pattial list of articlesand technical papers on topics related to items found in Rec-ommended Practice 7G.

1. Arthur Lubinski, ‘Maximum Permissible Dog-Legs inRotary Boreholes,” Journal of Petmlewn Technology, Febru-ary l%l.2. Robert W. Nicholson, ‘Minimize Drill Pipe Damage andHole Problems. Follow Acceptable Dogleg Severity Limits,”Tmachons of the 1974 Internat ional Assoc ia t ion of Dr i l l -ing Contractors (IADC) Rotary Dril l ing Conference.

3. K. D. Schenk, “Calco Learns About Drilling ThroughExcessive Doglegs,” Oil and Gas Journal, Cktok 12, 1964.4 . G. J. Wilson, “Dogleg Control In Directionally DrilledWells,” Transactions of The American Institute of Mining, Met-allurgical, and Petrvleum Engineers (AlME), 1%7, Vol. 240.

5. Hansford, John E. and Lubiuski, Arthur, ‘CumulativeFatigue Damage of Drill Pipe in Dog Legs,” Journal ofPetm-leum Technology, March 1966.6 . Hansford, John E. and Lubinski, Arthurz “The Effect ofDrilling Vessel Pitch or Roll on Kelly and Drill Pipe Fatigue,”Tmactions of AIME, 1964, Vol. 23 1.

7 . Thad Vreeland, Jr., ‘Dynamic Stresses In Long Drill PipeStrings,” The Petroleum Engineel; May 1961.

8 . Henry Bourne, Continental Gil Co., Ponca City, Okla-homa, Drilling Fluid Cormsion, Unpublished.9. Edward R Slaughter, E. Ellis Fletcher, Arthur R. Elsear,and George K. Manning, ‘An Investigation of the Effects ofHydrogen on the Brittle Failure of High Strength Steels,’WADC TR 56-83, June 1955.1 0 . H. M. Rollins, ‘Drill Stem Failures Due to H,S,” Oil andGas Journal, January 24,1966.11. Walter Main, Discussion of Paper by Grant and Texter,“Causes and Prevention of Drill Pipe and Tool Joint Trou-bles,” World OiZ, October 1948.

12. J. C. Stall and K. A. Blenkarn, “Allowable Hook Loadand Torque Combinations For Stuck Drill String,” Mid-Conti-nent API District Meeting, Paper No. 851-36-M, April 6,1962.13. Armco Steel Corporation, “Gil Country Tubular Prod-ucts-Engineering Data,” 1966.

1 4 . Arthur Lubinski, ‘Fatigue of Range 3 Drill Pipe,” Revuede L’hstitut Fnmcais du Pet&e, November 2,1977 (Englishtranslat ion) .1 5 . Arthur Lubinski, ‘Dynamic Loading of Drill Pipe DuringTripping,” Journal of Petmleum Technology, August 1988.

1 6 . Huang T, Dareing D. W., “Buckling and Lateral Vibra-tion of Drill Pipe.,” Journal OfEngineering for In&my,November 1968, pp. 613-619.

17. Dateiug D. W., Livesay B. J., ‘longitudinal and AngularDrill-g Vibrations With Damping,” JownaZ of Engineer-ing for Zndzmry, November 1968, pp. 671-679.

1 8 . Combes J. D., Baxter V. R., “Critical Rotary Speeds CanBe Costly,” PetmZeum Engineer, September 1969, pp. 60-63.

1 9 . Besaisow A. A., et. al., ‘?>evelopment of a Surface DrilI-string Vibration Measurement System, ” Society of Petro-leum Engineers (SPE) SPE 14327, presented at the 1985Technical Conference, Las Vegas, September 22-25,1985.

2 0 . Burgess T. M., McDaniel G. L., Das P. K., ‘TmprovingTool Reliability with Drillstring Vibration Models-FieldExperience and Limitations,” SPIYIADC 16109, presented atthe 1987 SPEYIADC Drilling Conference, New Grleaus,March 1987.

21. Halsey G. W., et. al., “Torque Feedback Used to CureSlip-Stick Motion,” SPE 18049, presented at the 1988 Tech-nical Conference, New Orleans, March 1987.

2 2 . Cook R. L., Nicholson J. W., Sheppard M. C., and West-lake W., ‘First Real Time Measuremerits of Dowuhole Vibra-tions, Forces, and Pressures Used to Monitor DirectionalDrilling operations,” SPEAADC 19651, presented at the1989 SPEXADC Drilling Conference, New Orleans, Febru-ary 28 to March 3,1989.

23. Warren T. M., Brett J. F., and Sinor L. A., “Developmentof a Whirl-Resistant Bit,” SPE 19572, presented at 1989 SPEAnnual Technical Conference and Exhibition, San Antonio,October 8-11.

2 4 . Yanglie Zhang, Zaiyang Xiao, ‘Motion of Reviewing theSection 9 of API RP 7G,” presented at the API Standardiza-tion Conference, June 1993.

2 5 . Nicholson J. W., “An Integrated Approach to DrilliugDynamics Planning, Identitication, and Control,” SPE!IADC27537, presented at the SPEYIADC Drilling Conference, Dal-las, February 15-18,1994.

26. Fereidoun Abbassian, “Drillstring Vibration Primer,” BPExpZomtion, Unpublished

27. Dawson, Rapier, and Paslay, P.R., “Drillpipe Buckling inInclined Holes,” JPT, Cktober 1984.

2 8 . Standard DS-I, Dri l l Stern Design and Inspect ion, Sec-ond Edition, T.H. Hill Associates, Inc., Houston, Texas,August 1997.

2 9 . Mitchell, R.F., “Effects of Well Deviation on HelicalBuckling,” SPE 29462, SPE Production operations Sympo-sium, Oklahoma City, April 1995.

145

STD.API/PETRO R P 7G-ENGL I,998 m 0 7 3 2 2 9 0 ObO=JBlib 2 5 2 -

146 API REWWENDED PFWTICE 76

3 0 . Schuh, FJ,, ‘The Critical Buckling Force and Stresses for 3 5 . Morgan, RP.; Roblin, MJ., ‘A Method for the Investiga-Pipe in Inclined Curved Boreholes,” SPEVIADC 21942, SPlY tion of Fatigue Strength in Seamless Drillpipe,” ASME Con-IADC Drilling conference, Amsterdam, March ll-14,199l. ference, Ikrk Oklahoma, September 22,1%9.31. Kyllingstad, Aage, ‘Buckling of Tubular Strings inCurved Wells,” Journal of Petmhm Science and Engineer- 3 6 . Canner, John, A., “Endurance Limit of Drill Pipe,” letter

ing, 12,1995, pp. 209-218.l/21/95 to John Altermium.

3 2 . Suryanmyana, PVR.; McCann, R.C., “An ExperimentalStudy of Buckling and Post-Buckling of La&ally Con-strained Rods,” Journal ofEnergy Resources Technology, Vol.177, June 1995, pp. 115-124.33. Paslay, PR; Cemocky, E.I?, “Bending Stress Magnika-tion in Constant curvature Doglegs with Impact on Drillingand Casing,” SPE 22547, the SPE 66th Annual TechnicalConfmnce and Exposition, DalIas, Texas, October 6-9,1991.34. Acknowledgment: Subcommittee appreciates the use ofShell Exploration and Production Company pnqietary BSMBending Stress Code.

37. Hansford, J.E.; Lubinski, A., “Cumulative Fatigue Dam-age of Drillpipe in Doglegs,” Joumd ofPetroleum Technol-ogy, March 1966, pp. 359-363.

3 8 . Lubinski, Arthur A., “Maximum Permissible Dog-Legsin Rotary Boreholes,” Journal of Petroleum Technology, Feb-mu-y l%l.

39. Acknowledgment: Subcommittee appreciates the releaseby Mobil Exploration and Production Technical Center, DaI-las, Texas of the report, “Buckling of a Rod Confined to be inContact with a Toroidal Surface, Parts I and II,” by Paul R.Paslay, October 15,1993.

STD.API/PETRO R P ?G-ENGL 1998 - 0 7 3 2 2 9 0 0609837 l,qq m _

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