• Share
  • Email
  • Embed
  • Like
  • Save
  • Private Content
Download
 

Download

on

  • 4,493 views

 

Statistics

Views

Total Views
4,493
Views on SlideShare
4,493
Embed Views
0

Actions

Likes
1
Downloads
54
Comments
0

0 Embeds 0

No embeds

Accessibility

Upload Details

Uploaded via as Adobe PDF

Usage Rights

© All Rights Reserved

Report content

Flagged as inappropriate Flag as inappropriate
Flag as inappropriate

Select your reason for flagging this presentation as inappropriate.

Cancel
  • Full Name Full Name Comment goes here.
    Are you sure you want to
    Your message goes here
    Processing…
Post Comment
Edit your comment

    Download Download Document Transcript

    • ~ ~~ ~ ~ ~~ STD.API/PETRO RP 7G-ENGL L998 m 0732290 Ob09bb2 370 m Recommended Practice for Drill Stem Design and Operating Limits API RECOMMENDED PRACTICE 7G SIXTEENTH EDITION, AUGUST 1998 EFFECTIVE DATE: DECEMBER1,1998 -" L- American Strategies for lodays Petroleum Environmental Partnership InstituteCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL L998 m 0732290 0609663 2 0 7 m " Environmental Partnership API ENVIRONMENTAL, HEALTH AND SAFETY MISSION AND GUIDING PRINCIPLES The mcmbers of the American Petroleum Institute are dedicated to continuous efforts to improve the compatibility of our operations with the environment while economically developing energy resources and supplying high quality products and services to consum- ers. We recognize our responsibility to work with thc public, the government, and others to develop andto use natural resourcesin an environmentally sound manner while protecting the health and safety of our employees and the public.To meet these responsibilities,API memberspledgetomanageourbusinessesaccordingtothefollowingprinciplesusing sound scienceto prioritize risks and implement cost-effective management practices: to To recognize and to respond to community concerns about our raw matcrials, prod- ucts and operations. To operate our plants and facilities, and to handleraw materials and productsin a our manner that protects the environment, and the safety and hcalth of our employees and the public. To make safety, health and environmental considerations a priority i n our planning, and our development of new products and processes. To advise promptly, appropriate officials, employees, customers and the public of information on significant industry-related safety, health and environmental hazards, and to recommend protective measures. To counsel customers, transporters and others the safe use, transportation and dis- in posal of our raw materials, products and waste materials. To economicallydevelopandproducenaturalresourcesandtoconservethose resources by using energy efficiently. To extend knowledge by conducting or supporting research on the safety, health and environmental effects of our raw materials, products, processes and waste materials. To commit to reduce ovcrall emissions and waste generation. To work with others to resolve problems created handling and disposalof hazard- by ous substances from our operations. To participate with government and others in creating responsible laws, regulations and standards to safeguard the community, workplace and environment. To promote these principles and practices by sharing experiences and offering assis- tancc to others who produce, handlc, use, transport or disposc of similar raw materi- als, petroleum products and wastes.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP ?G-ENGL L998 W 0 7 3 2 2 9 0 0609664 L43 m Recommended Practice for Drill Stem Design and Operating Limits Exploration andProduction Department API RECOMMENDED PRACTICE7G SIXTEENTH EDITION, AUGUST 1998 EFFECTIVE DATE: DECEMBER1,1998 American Petroleum InstituteCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D - A P I / P E T R O R P 7G-ENGL L998 m 0732290 0609665 O 8 T SPECIAL NOTES API publications necessarily address problems of a general nature. With respect to partic- ular cu s ne,local, state,and federal laws and regulations should r mt cs i c a be reviewed. API is not undertaking to meet the duties of employers, mantrhcmem, or suppliers to warn and properly t a n and equip their employees, and others exposed, concerning health ri and safetyrisks and precautions, nor undertaking their obligations under local, or fed- state, eral laws. Information concerning safety and health risks and proper p a u t i o n s with respect to par- ticular materials and conditions should obtained h m the employer,the manufacturer or be supplier of material, or the material safety sheet. that data Nothing contained in any API publication is to be construed as granting any right, by implicationor otherwise, for the manufacture,sale, or use of any method, apparatus, or prod- uct covemi by letters patent. Neither should anything contained the publication be con- in strued as insuring anyone against liability infiingrnent of letters patent. for Generally,API standards are reviewed and revised, reafhned, or withdrawn at least every five years. Sometimes a onetime extension of upto two years willbe added tothis review cycle. This publication will no longer be in effect five years after its publication date as an operative API standard or, where an extension has granted, upon republication.Status been of the publicationcan be ascertained h m the API Exploration andProduction Depaxtment [telephone (202) 682-8000]. A catalog of API publications and materials is published aunu- ally and updated quarterly by I 1220L Street, N.W., Washington, D.C. 20005. A , F This document was producedunder API standardization procedures that ensure appropri- ate notifìcation and participation the developmentalprocess and is designated as an API in standard. Questions concerning the interpretation of the content of this standard or com- ments and questions concerning the procedures under which this standard was developed should be direGted in writing to the director of the Exploration and Production Department, American Petroleum Instimte, 1220 L Street, N.W., Washington, D.C. 20005. Requests for permission to reproduce or translate all or any part of the material published herein should also be addressedto the director. API standards are published tofacilitate the broad availability ofproven, sound engineer- ing and operating r c e .These standards are not intended to obviate the for apply- pa t s i c need ing sound engineering judgment regarding when and where these standards should be utilized. The formularion and publication of API standards is not intended in any way to inhibit anyone from using any other practices. Any manufactum marking equipment or materials in conformance with the marking requirements of an API standard is solely responsible for complying withthe applicable al l requirements of that standard. API does not represent, warrant, or guarantee that such prod- ucts do in fact conform the applicable s t a n d a d t o API AU rights wserved No part o this work may be wpnxhce4 stomd in a retTievaIsystem, or f tmnmritted by any m , e electronic, mechanical photocopying, receding, or otherwise, a without prior written pennisswn @m the publisher. Contact the Publishez; API Publishing Services, 1220 L Srnet, N. W ,Washington,D.C. 2 W 5 . Copyright Q 1998 Americaa petroleumInstitute.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • ~ STD*API/PETRO RP 7G-ENGL 1994 m 0732290 0609bbb TL6 m FOREWORD This recommended practice. is under the jurisdiction the A P I Subcommittee on Stan- of dardization of Drilling and Servicing Equipment. The purpose of this recommended practice is tostandardize techniques for the procedure of drill stem design and to dehe the operating iis of the drill stem. lmt API publications maybe used by anyone desiring to do Every effort hasbeen made by so. to of the Institute assure the accuracy and reliability the data contained in them; however, the Institute makes representation,w m t y , or guarantee in connection withthis publication no and hereby expressly disclaims any liabilityor responsibility for loss or damage resulting this from its use or for the violation any federal,state, or municipal regulation with which of publication may conflict edition are denoted withbars in themargins.The bars indicate I Changes h m the previous section new content or major editorial changes. Changes to numben due to reformatting or minor editorial changes not denoted with bars. are Suggested revisions invited and should submitted to the director the Exploration are be of and Production Department, American Petroleum Institute, L Street, N.W., Washing- 1220 ton,D.C. 20005. This recommended pmctice shall become gective on the date printed on the cover b u may be used voluntarilyfrom the date ofdistribution. iiiCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP "G-ENGL 1998 0732290 Ob09bb7 952 CONTENTS 1 SCOPE ............................................................... 1 1.1 Coverage ....................................................... 1 1.2 Section Coverage................................................. 1 2 REFERENCES ........................................................ 1 3 DEFINITIONS ......................................................... 1 4 PROPERTIES OF DRTLL PIPE AND TOOL JOINTS ......................... 3 5 PROPERTIESOFDRILLCOLLARS ..................................... 33 6 PROPERTIESOF - S Y ............................................. 33 7DESIGN CALCULAnONS............................................. 46 7.1 Design Parameten ............................................... 46 7.2 SpecialDesignparameterS ........................................ 46 7.3SupplementalDrillStemMembers .................................. 46 7.4 TensionLoading ................................................ 46 7.5CollapseDue t External Fluid Pressure ............................. o 50 7.6 Internal Pressure ................................................ 51 7.7 TorsionalStrength ............................................... 51 7.8 Example Calculation of a LLpical Drill String Design-Based on Margin of ovelpull .............................................. 51 7.9 Drill Pipe Bending Resulting From TongingOperations................. 52 8 LIhaATIONS RELATED TO HOLE DEVIATION ........................ 53 8.1 FatigueDamage ................................................. 53 8.2Remedial Action to ReduceFatigue ................................. 54 8.3 Estimation of CumulativeFatigueDamage ........................... 58 8.4Identifìcation of Fatigued Joints .................................... 58 8.5 Wa of Tool Joints and Drill Pipe .................................. er 58 8.6 Heat Checking of Tool Joints ...................................... 59 9 IJMlTATIONSRELATED TO FLOATING VESSELS ...................... 59 10 DRILL STEM CORROSION AND SULFIDE STRESS CRACKING ........... 62 10.1 Corrosion ...................................................... 62 10.2 s u m e stress cracking ........................................... 64 10.3 Drilling Fluids Containing Oil ..................................... 65 11 COMPRESSIVE SERVICE LIMITS FOR DRILL PIPE ...................... 67 11.1 CompressiveServiceApplications .................................. 67 11.2 DrillPipeBucklinginS~ ..InclinedWellBores .................... 67 11.3 Critical Buckling Force for Curved Boreholes......................... 78 11.4 Bending Stresses on Compressively Loaded Drill Pipe in Curved Boreholes 79 11.5 Fatigue Limits for API Drill Pipe ................................... 96 11.6EstimatingCumulativeFatigueDamage ............................. 98 11.7 Bending Stresses on Buckled Drill Pipe ............................. 101 12 SPECIAL SERVICE PROBLEMS....................................... 101 12.1SevereDownhole Vibration....................................... 101 12.2 Transition from Drill Pipe to Drill Collars ........................... 108 V Previous page is blankCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D = A P I / P E T RG - E N G L ?O P L998 0732290 0609668 899 12.3Pulling on StuckPipe ........................................... 108 12.4 Jarring ....................................................... 109 12.5Torque in Washover w o n s ................................... 109 12.6AllowableHookloadandTorqueCombinations ...................... 109 12.7 BiaxialLoadingofDrill Pipe ..................................... 110 12.8FormulasandPhysicalConstants .................................. 110 12.9 Transition from Elastic to Plastic Collapse........................... 110 12.10 Effect of Tensile Load Collapse Resistance on ........................ 110 12.11 Example Calculation of Biaxial Loading............................ 110 13 IDENTIFICATION, INSPECITON AND CLASSIFICATION OF DRILL STEM comNENTs ............................................... 112 13.1 Drill String MarkingandIdentilïcation ............................. 112 13.2 InspectionStandards”DrillPipeandTubingWorkS~gs............. 112 13.3 ToolJoints .................................................... 122 13.4 Drill Collar Inspection procedure .................................. 124 13.5 Drill CobHandlhg System .................................... 124 13.6 Kellys ........................................................ 125 13.7RecutConnections .............................................. 126 13.8 Pin S r s Relief Grooves for Rental Tools and tes Other Short Term Usage Tools ................................................... 126 14 WELDING ON DOWN HOLE DRILLING TOOLS........................ 127 15 DYNAMIC LOADING OF DRILL PIPE ................................. 127 16 CLASSIFICATION SIZE A N D “ pTORQUE FOR ROCKBES ....... 127 u APPENDIX A STRENGTH AND DESIGN FORMULAS ..................... 131 APPENDIX B ARTICLFiS AND TECHNICAL, PAPERS...................... 145 Figures 1-25 Torsional S r n t and Recommended Make-up Torque Curves tegh .......... 20-32 26 Drill Collar BendingS r n t Ratios. 1 2 1V4Inch ID ................. 39 tegh V and 27 Drill Collar BendingStrength Ratios. 2 and 2V4Inch ID ................... 40 28 Drill Collar Bending Strength Ratios. 2l/, Inch ID ........................ 41 29 Drill Collar Bending S r n t Ratios. 213/.. Inch ID....................... tegh 42 30 Drill Collar Bending S r n t Ratios. 3 Inch ID.......................... tegh 43 31 Drill Collar Bending S r n t Ratios. 3V4Inch ID........................ tegh 44 32 Drill Collar Bending S r n t Ratios. 3V2Inch I ........................ tegh D 45 33 NewKelly-NewDriveAssembly ..................................... 48 34 NewKelly-NewDriveAssembly ..................................... 48 35 Maximum Height of Tool Joint AboveSlip to Prevent Bending During Tonging ................................................... 53 36 Dogleg S v r t Limits for Fatigueof Grade E75 Drill Pipe ................ 55 eeiy 37 Dogleg S v r t Limits for Fatigue of S-135 Drill Pipe .................... eeiy 56 38 LateralForceonToolJoint .......................................... 57 39 Fatigue Damage in Gradual Doglegs (Noncorosive Environment)........... 58 40 Fatigue Damage inGradual Doglegs (In Extremely Corrosive Environment). . 58 41 Lateral Forces on Tool Joints and Range 2Drill Pipe 3l/, Inch, 13.3 Pounds ........................ 60 per Foot, Range 2Drill Pipe. 43/4 Inch Tool JointsCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D = A P I / P E T R O RP 7G-ENGL L998 m 0732290 0b09bb9 725 m 42 Lateral Forces on Tool Joints and Range 2 Drill Pipe 4V2Inch, 16.6 Pounds per Foot, Range 2 Drill Pipe. Inch Tool Joints 6V4 ........................ 60 43 Lateral Forces on Tool Joints and Range 2 Drill Pipe 5 Inch, 19.5Pounds per F o ,Range 2 Drill ot Pipe. 63/8 Inch Tool Joints........................... 61 44 Lateral Forces on Tool Joints and Range 3 Drill Pipe 5 Inch, 19.5 Pounds per Foot, Range 3Drill Pipe. 63/8 Inch Tool Joints ........................... 61 45 Delayed-Failure Characteristics of Unnotched Specimens of an SAE 4340 Steel During Cathodic Charging Hydrogen UnderStandardizedConditions.... 66 with 46-66 Approximate Axial Compressive Loads at which Sinusoidal Buckling is Expected to Occur............................................ 68-78 67a-74a Bending Stress and Fatigue Limits............................... 80-94 67b-74b LateralContact Forces andLength .............................. 81-95 75 Hole Curvature Adjustment Factor To Allow for Merences in Tooljoint ODs !X . 76 Median Failure i i s for Am Drillpipe Noncorrosive Service Lmt .............. 99 77 Minimum FailureL m t for A I Drillpipe Noncorrosive Service iis P ........... 100 78a Bending Stress for High CurvatUtes .................................. 102 78b M r lContact Forces and ea Length ................................... 103 79a Bending Stress for High CurvatUtes .................................. 104 79b Lateral Contact Forces and Length ................................... 105 80a Bending Stress for High CurvatUtes .................................. 106 8Ob Lateral Contact Forces and Length ................................... 107 81 Ellipse of Biaxial Yield Stress or Maximum Shear-Strain Energy Diagram After Holmquist and API Nadai. Collapse of DeepWell Casing. Drilling and production P a t c (1939) ......................................... rcie 111 82 Marking on Tool Joints for Identification of String Components ....... 113 Drill 83 Recommended Practice for Mill Slot and Groove MethodDrill of String Identifìcation............................................... 114 84 Identification of Lengths Covered byInspection Standads................ 116 85 Drill Pipe and Tool Joint Color Code Identification ...................... 122 86 Tong Space and Bench Mark Position................................ 123 87 Drill Collar Elevator ............................................... 124 88 Drill Collar Orooves for Elevators Slips............................ and 125 89 Drill Collat Wear ................................................. 125 90 Modified Pin Stress-Relief Groove................................... 126 A- 1 Eccentric Hollow Section ofDrill Pipe ................................ 131 A-2 Rotary Shouldered Connection ...................................... 133 A-3 Limits for Combined Torsion and Tension for a Rotary Shouldered Connection134 A 4 Rotary Shouldered Connection Location Dimensions for Bending of Strength Ratio Calculations......................................... 136 A-5 Buckling Force vs Hole Curvature ................................... 139 A d Buckling Forcevs Hole Curvature ................................... 140 A-7 Buckling Forcevs Hole Curvature ................................... 141 Tables 1 New Drill Pipe Dimensional Data...................................... 4 2 New Dil Pipe Torsional and Tensile Data rl ............................... 5 3 New Drill Pipe Collapse and Internal Pressuret ........................ Da a 6 4 Used Drill Pipe Torsional and Tensilet A I PremiumClass............... 7 Da P a 5 Used Drill Pipe Collapse and Intemal Pressure Data APIPremiumClass ....... 8 6 U e Drill Pipe Torsional and Tensilet API Class 2..................... sd Daa 9 7 Used Drill Pipe Collapse andInternal Pressure Dt API Class 2............. 10 aaCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • ~ ~~ S T D = A P I / P E T R O R P 7G-ENGL 1998 m 0732290 Ob09670 447 m 8 MechanicalpropertiesofNewToolJointsandNeworadeE75Drillpipe ..... 11 9 Mechauid properties of New Tool Joints and New S r n t Drill Pipe... 13 High t e g h 10 RecommendedMinimum OD and Makeup Torque of Weld-on Qpe Tool Joints Basedon Torsional S r n t of Box and Drill Pipe................... 15 tegh 11 Buoyancy Factors .................................................. 18 12 Rotary Shouldered Connection Interchange List .......................... 19 13 Drill Collar weight (Steel) @ounds per foot) ............................. 34 14 Recommended Make-up Torque1 for Rotary Shouldered Collar Drill COMdOXlS....................................................... 35 15 S r n t of Kellys .................................................. tegh 47 16 Contact Angle Between Kelly and Bushing for Development of Maximum Width Wear Pattern ................................................. 48 17 S r n t of Remachined Kellys ....................................... tegh 49 18 Section Modulus Values ............................................. 53 19 Effect of Drilling Fluid Typeon Coefficient of Friction.................... 67 20 Hole curvaturesthat Prevent Buckling ................................. 79 21 Youngstown Steel Test Results ........................................ 96 22 Fatigue Endurance Limits Compressively Loaded Drill Pipe ................ 98 23 Values Usedin Preparing Figure77 .................................... 98 24 Classification of Used Drill Pipe...................................... 115 25 Classification of Used Tubing Work Strings............................. 117 26 Hook-Load at Minimum Yield S r n t for New, PremiumClass (Used), and tegh class 2 (Used) Drill Pipe............................................ 118 27 Hook-Load at MinimumYleld S r n t for New. PremiumClass (Used). and tegh Class 2 (Used) Tubing Work Strings................................... 120 28 Drill Collar Groove and Elevator Bore Dimensions ....................... 125 29 M x m m Stress a Root ofLast Engaged aiu t Thread for the Pin of an NC50 Axisymmetric Model .............................................. 126 30 IADC Roller Bit ClassifìcationChart .................................. 128 31 IADCBit Classification Codes Fourth Position .......................... 129 32 Recommended Make-up Torque Ranges Roller Cone Bits .......... 129 for Drill 33 RecommendedMinimum Make-up Torques Diamond Drill Bits......... 130 for 34 Common RollerBit Sizes ........................................... 130 35 Common FixedCutter Bit Sizes ...................................... 130 A-1 Rotary Shouldered Connection Thread Element Information ............... 143COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD-API/PETRO RP ïG-ENGL L998 0732290 0 6 0 9 b 7 L 3 8 3 m Recommended Practice for Drill Stem Design Operating Limits and 1 scope 3 Definitions 1.1 COVERAGE 3.1bendingstrengthratio: The of section ratio the modulus of a rotary shouldered box at the point in the box This recommended practice involves not only selection the where the pin ends when made up divided by the section mod- of drill string members, but also the consideration of hole thread. ulus of therotary shouldered pin at the last engaged angle control, drilling fluids, weight and rotary speed, and other operational procedures. 3.2 bevel diameter: Theouterdiameter ofthe contact face of the rotary shouldered connection. 1.2SECTIONCOVERAGE 3.3 bit sub: A sub, usually with box connections, that is Sections 4, 5, 6, and 7 provide procedures for use in the 2 used to connect the bit to the drill string. I I selection of drill string members. Sections 8,9, 10, 11, 12, and 15 are related to operating l m t t o s which may reduce iiain the normal capability of the drill string. Section13 contains a 3.4 box connection: A threaded connection on Oil Country Tubular Goods (OCTG) that has internal (female) threads. classification system for used pipe and used tubing work drill strings, and identification and inspection procedures for other3.5 calibration system: A documented system of gauge drill string members. Section 14 contains statements regard- ing welding on down hole tools.Section 16 contains a classi- calibration and control. I rock fication system for bits. 3.6 Class 2: An API service classification for used drill pipe and tubing work n stri gs. 2 References 3.7 cold working: Plastic deformation of metal at a tem- (See also Appendix B.) perature low enoughto insure or cause permanent strain. I 3.8 corrosion: The alteration anddegradaton of material Am by its environment I RP 5C1 Care and Use o CasingTubing f and 3.9 critical rotary speed: A rotary speed at which har- Bull 5C3 Bulktin on Formulas and Calculationsfor Casing, Tubing, Drill Pipe, and Line Pipe monic vibrations OCCUT. vibrations may cause fatigue These Properties failms, excessive wear,or bending. Spec 7 Specijkation for Rotary Drill Stem Ele- 3.10 decarburization: The loss of carbon from the sur- I RP 7A1 ments RecommendedPractice for Testing o f face of a ferrous alloy as a result of heatingin a medium that reacts with the carbon the surface. at I I RP 13B-1 lkread Compoundrfor Rotary Shouldered connections Recommended Practice Standard Pnxe- 3.1 1 dedendum: The distance between the pitch line and root oft r a . hed dure for Field Testing Water-Based Drill- 3.12 dogleg: A term applied to a sharp change of direc- ing Fluids tion in a wellbore or ditch. Applied also to the permanent RP 13B-2 Recommended Practice Standard Pnxe- bending Of roPe Or Pipe- dun?for Field Testing Oil-Based Drilling 3.13dogleg severity: A measure of the amount of Fluids change in the inclination and/or direction of a borehole, usu- AST" ally expressed in degrees per feet of course length. 100 D3370 Standard Practices for Sampling Water 3.14 drift: A drift is a gauge used to check minimum ID of loops, flowlines, nipples, tubing, casing, drill pipe, and drill NACE2 clas olr. MR-01-75 Sulfide Stress CrackingResistMtMetallic Materiul for Oil Field Equipment 3.15 drill collar: Thick-walledpipe or tubedesigned to provide stiffness and concentration of weightat the bit. mrcn A e i a society for Testing Materials, 100 Barr Harbor Drive, West Con- shccken, Pennsylvania 19428. 3.16 drill pipe: A length of tube, usually steel, to which WACE ~ t m t n , BOX 218340, Houston, exa as mis-8340. n a a e o P.O. i l S e i threaded COMectiOnsCalledto01 joints attached. pC d 1COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • 2 PRACT~CE API RECOMMENDED 7G 3.17 drillstringelement: Drill pipewithtooljoints the system with caustic soda or quick lime and an organic attached. acid. Silicak, salt, and phosphate may also be present. Oil- base drilling fluids are differentiated from invert-emulsion 3.18 failure: Improper performauce of a device or equip- drilling fluids (both water-in-oil emulsions) amounts of by the ment that prevents completion its design of function. water used, method of controlling viscosity and thixotropic 3.19 fatigue: The process of progressive localizedperma- properties, wall-building a r sand fluid loss. m t a, eli nent structural change occurring in a material subjected to 3.31 pin end: A threaded connection on Oil Country conditions t a producefluctuating stresses and strains a ht t Tubular Goods (OCTG)t a has external (male)h ht t reads. some point or points and that may culminate in cracks or complete frilcture after a sufiicient number fluctuations. of 3.32plainend: Drill pipe, tubing, casing or without t r a s The pipe ends may may not be upset. hed. or 3.20 fatigue failure: A failure which originates as a result of repeated or fluctuating stresses having maximum values 3.33premiumclass: An API service classifìcationfor less than the tensile strength the material. of used drill pipe and tubing work strings. 3.21 fatigue crack A crack resulting from fatigue. See 3.34 quenched tempered: and Quench hardening- fatigue. Hardening a ferrous alloy by austenitizing and then cooling rapidly enough so t a some or all the austenite ht of transforms 3.22 forging: (1) Plastically deforming metal, usually hot, t martensite. o into desired shapes with compressive force, withor without de . (2) A shaped metal part formed by the forging method. Tempering-Reheating a quenched-hardened or normalized is ferrous alloy a temperatme below the transformation range to 3.23 kelly: The square or hexagonal shaped steel pipecon- and then cooling any rate desired. at necting the swivel the drill string. The kelly moves through to 3.35 range: A length classification for A P I Oil Country the rotary table andtransmits torque to the drill string. Tbbular Goods. 3.24 k ly saver sub A short substitutethat is made up el 3.36 rotary shouldered connection: A connection onto the bottom of the kelly protect the pin end of the kelly to used on drill stringelementswhichhascoarse, tapered h m wear during make-up and break-out operations. threadsand seating shouldem. 3.25 last engaged thread: The last thread on the pin 3.37 shear strength: The stress required to producefrac- engaged with the or the box engaged withthe p n box i. ture in the plane of cross section, the conditions of loading 3.26 lower kelly valve: An essentially full-opening valve being such that the directions of force and of msa c am it u e installed immediately below the kelly, with outside diameter parallel and opposite although their paths are offset a speci- outside diameter. Valvecan be closed to equal to the tool joint fied minimum amount. The maximum load divided by the zemove the kelly under pressure and can be stripped in the original cross-sectional area of a section separated by shear. hole for snubbing operations. 3 3 slip area:The slip is containedwithin a distanœ .8 area 3 2 makeup shoulder: The sealing shoulder on a .7 of 48 inches along pipe body from the juncture of the tool the rotary shouldered connection. joint OD and the elevator shoulder. 3.28 minimum make-up torque: The minimum make- 3.39 stress-relief f a r :A modiiìcation performedon et eu up torque is the minimum amount of torque necessary to rotary should& connectionswhich removes the unengaged develop an arbitrarily derived tensile in the pin or com- stress threads of the pin or box. This process makes thejoint m m pressive stress in the box. This arbitrarily derivedstress level flexible andreduces the likelihood of fatigue crachg in this is perceived as being SufEcient in most drilling conditions to highlystressedarea prevent downhole make-up and t prevent shoulder separa- o tion frombending loads. 3.40 swivel: Device at the of the drill stem which top per- mits simultaneous circulation and rotation. 329 minimum OD: For tool joints drill pipe with rotary on shouldered connections, the minimum OD is the minimum 3.41tensile s t r e n g t h : The maximum tensile stress boxODthatwillall~theconnectiontoremainasstrongasa which a material is capable of sustaining. Tensile strength is specifìedpercentage of the pipe tube i torsion. drill n calculated from themaximum load duringa tension test car- ried to N@UE the original cross-sectional area of the and 3.30 oil muds: The term “oil-base drilling fluid” is specimen. oil applied to a special type drilling fluid where is the contin- uous phase and watere dispersed phase. Such fluids th contain 3.42 test pressure: A pressure above working pressure blown asphalt and usuallyto 5 percent water emulsified into used to demonstrate structural integrity of pressure vessel. 1 aCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO P R 7G-ENGL L998 m 0732290 0609673 156 m RECOMMENDED PRACTICE FOR DRILLSTEM DESIGN OPERATING LIMrrS AND 3 3 4 thread f r : The form threadis the t r a profde .3 o m of hed tion for the purposes of this recommended practice is in an axial plane for a length one pitch. of assumed a constant; it has been demonstrated,however, that new tooljoints and service tempenahm often affect the coeffi- 3.44 tolerance: The amount of variation permitted. cient of friction of the tool joint system. While tool joints new 3 4 tool joint: A heavy coupling element for drill pipe .5 typically exhibit a low coefficient offriction,service tempera- having coarse, a p e d threads and sealing shoulders designed t tures greater than 300°F can dramatically increase decrease or to sustain the weight of the stem, withstand the drill strain of the coefficient of friction depending primarily on thread com- repeated make-up and break-out, resist fatigue, resist addi- pound. The torquerequired to yield arotary shouldered con- tional make-up during drilling, and provide a k - p f s a ale el . nection may be obtained from the equation i Section A.8. n The male section (pin) is attached to one end of a length of 4.6 The pin o box area, whichever contmls, is the largest r drill pipe and the female section is attached to the other (box) factor and is subject to the widest variation. The tool joint out- end Tool joints may be welded to the pipe, screwed onto drill side diameter (OD) and inside diameter (ID) largely deter- on the pipe, orcombination of screwed and welded. a mine the strength of the joint in torsion. The OD affects the 3.46 upper kelly cock: A valve immediately above the boxareaandtheIDaffectsthepinareaChoiceofODandID kelly that can be closed to confinepressures inside the drill determines the areas of the pin and box and establishes the string. theoretical torsional strength, assuming all other factors are constant. 3.47 upset: A pipe end with increased wall thickness. The outside diameter may be increased, or the inside diameter 4.7 The greatest reduction in theoretical torsional strength may be reduced, or both. Upsets are usually formed by hot of a tool joint during its service occurs with OD wear.At life forging the pipe end. whatever point the tool joint box area becomes the smaller or controlling a m , any further reduction in ODcauses a direct 3 4 working gauges: Gauges used for gaugingproduct .8 reduction in torsional strength. If the box area controls when tras hed. thetooljointis new, initial OD wear reduces torsional 3.49 working pressure: The pressure t which a partic- o strength. If the pin controls when nw some OD wear may e, ular piece of equipment is subjected during normal opera- occur before the torsional strength is affeckd Conversely, it is tions. possible to increase torsional strength by making joints with oversize OD and reducedID. 3.50 working temperature: The temperature to which a particular piece ofequipment is subjectedduring normal 4.8 Minimum OD,box shoulder, and make-up torque val- operatiom. ues listed in Table 10 were determined using the following criteria: 4 Properties of Drill Pipe andTool Joints 4.8.1 Calculations recommended for tool joint make-up 4.1 This section contains a of (Tables seriestables 1 torque are based on the use of a thread compound containing through 11) designed to present the dimensional, mechanical, 40 to 60 percent by weight of finely powdered metallic zinc and performance properties of new and usedpipe. Tables drill applied to all threads and shoulders, and containing not more are also included listing these properties for tool joints used than 0.3 percent total active sulfur (referencethecaution with newand used drill pipe. regarding the use of hazardous materials in Spedìcation 7, Appendix G). Calculations also basedon a tensilestress of are 4.2 All d i l pipe tool rl and joint p ee tables are pr s t i 60 percent of the minimum tensile yield tool joints. for included inSection 4. 4.8.2 In calculation of torsional strengths of tooljoints, 4.3 Values listed in drill pipe tables are based on accepted both new and worn, the bevels ofthe tool joint shoulders are standards of the industry and c l u a e from formulas in acltd disregarded. AppendixA. 4.8.3 premium Class Drill String is based on drill pipe hav- 4.4 Recommended drift diameters for new drill string ing aminimum wall thickness of80 percent. assemblies are shown in column 8 of Tables 8 and 9. Drift bars must be a minimum of four inches long. The drift bar 4.8.4 Class 2 drill string allows drill pipe with a minimum must pass through the upset but need not penetratemore area wall thickness of70 percent. t a twelve inches beyond the base of hn the elevator shoulder. 4.8.5 The tool joint to pipe torsional ratios that are used 4.5 The torsionalstrength of a tool joint is a functionof sev- here (20.80) are recOmmendations only and should real- it be eral variables. These include the strength of the steel,connec- ized that other combinations of dimensions may used. A be tion size, thread form, lead, taper and coefficient of i t o on f cin r given assembly t a is suitable for certain service may be ht mating surfaces, threads, or s h o u l h . The coefficient of fric- inadequate for some areas and overdesigned for others.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • 4 API REWMENDED PRACTICE 7 6 Table l-New Drill Pipe Dimensional Data Size Nominalweight WmArea Pls t oe ac r i d OD -and mainEnd Wall ID Body o P$ Modulus3 f i in Couplings, Weight1 Thickness i. n s .i. q n Cu. in. D li Wt Wt i in. d A Z44 .3 48 .5 24 3 195 .9 1. W 2 131 .2 .280 6.26 6.65 185 .1 182 .49 173 .3 .1 27 26 1 %. 6 68 .5 241 .4 1.8120 221 .4 .6 32 97 .2 1.0 04 211 .5 2.8579 324 .0 31 1, 95 .0 88 .1 .254 292 .9 2.5902 353 .2 1.0 33 1.1 23 .368 274 .6 360 .29 514 .4 1 .4 9 5 54 0 1.3 46 262 .0 4.3037 587 .4 4 1.262 1.5 8 10.46 346 .7 306 .77 5.400 1.0 40 1.3 29 .330 3.340 3.8048 648 .5 1.0 57 1.9 46 .380 3.240 4.3216 7.157 1.4 22 1.5 37 41 1, 398 .5 360 .04 7.184 1.0 6.337 6 14.98 3.826 4.4074 853 .4 20.00 .430 18.69 3.640 5.4981 1.3 022 2.2 28 2.6 13 S00 350 .0 6.2832 1.4 135 5 1.5 62 1.7 48 .% 2 448 .0 4.3743 978 .1 9.362 1.05 17.93 4.276 5.2746 1.1 145 2.0 56 2.3 40 .m 400 .0 7.0686 1.9 441 .304 16.87 511, 19.20 4.892 4%4 .2 1.2 221 2 .3 1 1 96 0 1.1 98 478 .7 5.8282 1.6 402 2 .A15 47 0 22.54 4.670 6.62% 1.8 568 6% 25.20 .330 22.19 595 .6 6.5262 1.7 952 .362 24.22 27.70 591 .0 7.1227 21.156 1Wft = 3.3996X A (COL 6) = 0.7854(D- a) A M=0.1%35 (-D " Dg 4.9 Many sizes and styles of connections are hte~hange- 4.1 1.2 Extend a horizontal line from OD under consid- the able with certain other sizes and styles of connections.These read the torsional strength represent- eration to the curve and conditionsdiffer only in name and in some cases thread form. ing the box. If the thread farms are interchangeable, the connections are1 interchangeable. 4.1 1.3 Extend a vertical line from theID to the curve and I zhese interchangeableconnections are listed inTable 12. read the torsional strength representingthe pin.! 4.10 The curves of Figures 1 through 25 depict the theoreti- 4.11.4 The d of the two torsional strengths thus e r cal t r i n l yield strength of a number of commonly used osoa obtained is the theoretical torsionalstrength of the tool joint, tool jointconnections over a wide range of inside and outside da ees The coefficient of fiiction on mating ff c s i m t r. la e , r 4.1 1.5 It is emphasized that the values obtained from the1 threadsandshoulders, is assumedto be 0.08 (See Section 3 of curves am theoreticalvalues of torsional strength. T o olI Am RP 7A1,Recommended Pmctice for lèstìng ofn2mad joints in the field, subject to many factors not included inl Compound for Rotary Shouldered Connections). The m a b determination of points for the curves,may vary h m these up torque should be based on a tensile stress level of 60 per- values.l cent of the minimum yield for tooljoints.~ 4.1 1.6 The curves are most useful to show the relative tor- 4.1 1 The curves may be usedby taking the followingsteps: sional strengths of joints for variations in OD and ID, b t oh 4.1 1.1 Select the appropriatelytitled curve for the size and new and after wear. In each case,the smaller value should be type tool joint COMection being studied. used. (Text continuedm page 3 . 3) COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
    • RECOMMENDED PRACTICE FOR DRU STEM DESIGNAND OPERATING LIMITS 5 ~ ~~______ ~____ ~~ ____ ~~ Table 2 4 e w Drill Pipe Torsionaland Tensile Data 4.85 234 176071. 136944. 123902. 6668. 97817. 8574.51. 7917. 6250. 6.65 6.85 248. 16176. 14635. 11554. 10.40 m 2 . 385820.50 312 14146. 17918. 19805. 25463. 194264. 246068. 271970. 34%76. 13.30 18551. 23498. 25972. 33392. 271569. 343988. 380197. 488825. 15.50 21086. 26708. 29520. 37954. 322775. 408848. 451885. 580995. 4 19474. 24668. 27264. 35054. 230755. 292290. 323057. 415360. 14.00 23288. 29498. 32603. 41918. 285359. 361454. 399502. 513646. 15.70 25810. 32692. 36134. 46458. 3241 18. 410550. 453765. 583413.13.75 4V2 25907. 32816. 36270. 46633. 270034. 342043. 378047. 486061. 16.60 30807. 39022. 43 130. 55453. 330558. 418707. 462781. 595004. 20.00 36901. 46741. 51661. w21. 412358. 522320. 5n301. 742244. 22.82 40912. 51821. 57276. 73641. 471239. 596903. 659734. 883. 420 5 16.25 35044. 44389. 49062. 63079. 328073. 415559. 459302. 59053l. 19.50 41 167. 52144. 57633. 74100. 395595. 501087. 553833. 712070. 25.60 52257. 66192. 73159. 94062. 530144. 671515. 742201. 954259. SI, 19.20 44074. 55826. 61703. 79332. 372181. 471429. 521053. 692. 695 21.90 50710. 64233. 70994. 91278. 437 1 16. 553681. 611963. 786809. 24.70 56574. 71660. 79204. 101833. 497222. 629814. 696111. 894999. 98812. 89402. 70580. 6% 25.20 881035. 685250. 619988. 489464. 76295. 27.70 67665 . 137330. m 534199. 106813. l. 961556. 747877. Based on the shear mhequalto 57.7 percent o minimumyield strength and nominal wall thickness. g t f Minimum tasionalyield strength calculated fimu Equation A.15. ZMinimumtensilestrengthcalculatedfromEquationA.13. COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL 1998 0732290 Ob09b7b 965 m 6 API RECOMMENDED-CE 76 Table %New Drill Pipe Collapse and Internal Pressure Data OD couplings .. Mlrlmumvalues,psi .. M m m m Y i e l d Strength, psi m. lb/& S135 E75 G105 x95x95 G105 E75 S135 24 3 11040. 13984. 15456. 19035. 10500. 13300. 14700. 18900. 66 .5 15599. 19759. 21839. 28079. 15474. 19600. 21663. 27853.5 24 7 10467. 12940. 14020. 17034. 9907. 12548. 13869. 17832. 1.0 04 16M9. 20911. 23112. 29716. 16526. 20933. 23137. 29747. 3V2 95 .0 loool. 12077. 13055. 15748. 9525. 12065. 13335. 17145. 1.0 33 14113. 17877. 19758. 25404. 13800. 17480. 19320. 280 44. 1.0 55 16774. 21247. 23434. 30194. 16838. 21328. 23573. 30308. 4 1.5 18 8381. 9978. 10708. 12618. 8597. 10889. 12036. 15474. 1.0 40 11354. 14382. 18. 5% 20141. 10828. 13716. 15159. 19491. 1.0 57 18. 2% 16335. 18055. 23213. 12469. 15794. 17456. 22444. 44 1 1.5 37 7173. 8412. 8956. 10283. 7904. 10012. 11066. 14228. 1.0 66 10392. 12765. 13825. 16773. 9829. 12450. 13761. 17693. 20.00 12964. 16421. 18149. 23335. 12542. 15886. 17558. 22575. 22.82 14815. 18765. 20741. 26667. 14583. 18472. 20417. 26250. 5 1.5 62 6938. 8108. 8616. 9831. 7770. 9842. 10818. 13986. 19.50 9962. 12026. 12999. 15672. 9503. 12037. 13304. 17105. 2.0 56 13500. 17100. 18900. 24300. 13125. 16625. 18375. 23625. 5 1, 1.0 92 6039. 6942. 7313. 8093. 7255. 9189. 10156. 13058. 21.90 8413. 10019. 10753. 12679. 8615. 10912. 12061. 15507. 24.70 1 M . 12933. 14013. 17023. 90. 93 12544. 13865. 17826. 6% 25.20 4788. 5321. 5500. 6036. 6538. 8281. 9153. 11768. 27.70 58W. 6755. 7103. 7813. 7172. 9084. 1o040. 12909. COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
    • RECOMMENDED PRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS 7 Table &Used Drill Pipe Torsional and Tensile Data API Premium Class New Weight NominalW/ Size Threadsand -orsional Yield Strength TensileDataBasedonUniformWear OD couplings Based OU UniformW=, ft-lb Load at Minimum Xeld Strength, lb m. lWft E75 x95 G105 S135 E75 x95 G105 5135 234 3725. 47 19. 5215. 6705. 76893. 97398. 107650. 138407. 6.65 4811. 6093. 6735. 8659. 107616. 136313. 150662. 193709.; 2V8 6332. 8020. 8865. 11397. 106946. 135465. 149725. 192503. 10.40 8858. 11220. 12401. 15945. 166535. 210945. 233149. 299764.50 3v2 11094. 14052. 15531. 19968. 152979. 193774. 214171. 275363. 13.30 14361. 18191. 20106. 25850. 212150. 268723. 297010. 381870. 15.50 16146. 20452. 22605. 29063. 250620. 317452. 350868. 451 115. 4 11.85 15310. 19392. 21433. 27557. 182016. 230554. 254823. 327630. 14.00 181%. 23048. 25474. 32752 224182. 283%3. 313854. 403527. 15.70 20067. 25418. 28094. 36120. 25385 l. 321544. 355391. 45693l. 44 13.75 20403. 25844. 28564. 36725. 213258. 270127. 298561. 383864. 16.60 24139. 30576. 33795. 43450. 260165. 329542. 36423l. 468297. 20.00 28683. 36332. 40157. 51630. 322916. 492. 006 452082. 581248. 22.82 31587. 40010. 44222. 56856. 367566. 465584. 514593. 661620. 5 16.25 27607. 34969. 38650. 49693. 259155. 328263. 362817. 466479. 19.50 32285. 40895. 45199. 58113. 311535. 394612. 436150. 560764. 25.60 40544. 51356. 56762. 72979. 414690. 525274. 580566. 746443. SV2 19.20 34764. 44035. 48670. 62575. 294260. 372730. 411965. 529669. 21.90 39863. 50494. 55809. 71754. 344780. 436721. 482692. 620604. 24.70 44320. 56139. 62048. 79776. 391285. 495627. 547799. 704313. 55766. 71522 79050. 101635. 387466. 490790. 542452. 697438. 6% 25.20 27.70 60192. 77312. 85450. 109864. 422419. 535064. 591387. 760354. Based mthe shear strength equalto 57.7 percent of minimum yield smngtb. Torsional data basedon U)percent uniform wear on outside diametex and tensile data based on 20 percent uniform wear on outside diamter. COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
    • STD.API/PETRORP 7G-ENGL L998 0732290 Ob09678 738 ~ ~~ Table W s e d Drill Pipe Collapse and Internal Pressure Data API Premium Class ___ ~85 234 8522. 10161. 10912. 12891. 90. 60 12160. 13440. 17280. 66 .5 13378. 16945. 18729. 24080. 14147. 17920. 19806. 25465. 7640. 9017. 9633. 11186. 9057. 11473. 12680. 16303. 2% 68 .5 1.0 04 14223. 18016. 19912 m. 11 5 1. 0 19139. 21153. 27197. 3V2 95 .0 7074. 88. 24 8813. 10093. 8709. 11031. 12192. 15675. 13.30 12015. 15218. 16820. 21626. 12617. 15982. 17664. 22711. 1.0 55 14472. 18331. 20260. 26049. 15394. 19499. 21552. 27710. 1.5 18 5704. 6508. 6827. 7445. 7860. 9956. 11004. 14148. 1.0 40 9012. 10795. 11622. 13836. 90. 90 12540. 13860. 180 72. 1.0 57 10914. 13825. 15190. 18593. 11400. 14440. 15960. 20520. 1.5 37 4686. 5190. 5352. 5908. 7227. 9154. 10117. 13008. 1.0 66 7525. 8868. 9467. 10964. 8987. 11383. 12581. 16176. 2.0 00 10975. 13901. 15350. 18806. 11467. 14524. 16053. 260 04. 22.82 12655. 16030. 17718. 22780. 13333. 16889. 18667. m. 5 1.5 62 4490. 4935. 5067. 5661. 7104. 8998. 94. 96 12787. 1.0 95 7041. 8241. 8765. 10029. 8688. 11005. 12163. 15638. 25.60 11458. 14514. 16042. 20510. 12000. 15ux). 16800. 21600. 54 1.0 92 3736. 4130. 4336. 47 1. 4 6633. 8401. 9286. 11939. 21.90 5730. 6542. 6865. 7496. 7876. 97. 97 11027. 14177. 24.70 7635. 91 0 1. 92. 66 11177. 9055. 11469. 12676. 16298. 6% 2.0 52 2931. 3252 3353. 3429. 5977. 7571. 8368. 10759. 2.0 77 3615. 4029. 4222. 4562. 6557. 8306. 9180. 11803. COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL 1778 m 0732290 0609677 679 m RECOMMENDEDPRACTICE FOR DRIU STEM DESIGN OPERATING AND LIMITS 9 Table W s e d Drill Pipe Torsional and Tensile Data Class 2 API New Weight Nominal W/ Size Threadsand +TorsionalYield Strength Tensile D t Based on Unifonn Wear aa OD COuplingS Based OU UniformWear, A-lb Load at Minimum Yield Strength, lb m. lWft E75 x95 S135 G105 E75 x95S135 G 105 4.85 231~ 84469. 120035. 93360. 5232. 4130. 6.65 167167. 130019. 117636. W71.167043. 129922.% 117549. 2 92801. 6.85 9871. 5484. 7677. 6946.0627. 9615. 7591. 10.40 9.50 3V2 13.30 12365. 15663. 17312. 22258. 183398. 232304. 256757. 3301 16. 15.50 13828. 17515. 19359. 24890. 215967. 273558. 302354. 388741. 4 11.85 13281. 16823. 18594. 23907. 158132. 200301. 221385. 284638. 14.00 15738. 19935. 22034. 28329. 194363. 246193. 272108. 349852. 15.70 17315. 21932. 24241. 31166. 219738. 278335. 307633. 395528.13.75 4V2 17715. 22439. 24801. 3 1887. 185389. 234827. 259545. 333701. 16.60 m. 26483. 29271. 37634. 225771. 285977. 316080. 406388. 34645. 31346. 24747. 20.00 27161. 22.82 34404. 38026. 48890. 402163. 317497. 4444%. 571495. 5 16.25 23974. 30368. 33564. 43 154. 225316. 285400. 315442. 405568. 19.50 27976. 35436. 39166. 50356. 270432. 342548. 378605. 486778. 25.60 34947. 44267. 48926. 62905. 358731. 454392. 502223. 645715. 511, 19.20 30208. 38263. 42291. 54374. 255954. 324208. 358335. W17. 21.90 34582. 43804. 48414. 62247. 299533. 379409. 419346. 539160.3.69090. 53737. 48619. 38383. 24.70 6% 472131.427166.337236. 87295. 67896. 61430. 25.20 48497. 607026.5. 73231. 66257. 52308. 27.70 B& on the shear strength equal to 57.7 percent of minimum yield strength. Tomid data based on 30 percent d o wear on outside diameter and tensiledata based on 30 pacent uniform wear on outside diameter. m COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
    • 10 API RECOMMENDED PRACTICE 7 6 Table 7"used Drill Pipe Collapse and Internal Pressure Data API Class 25 234 7996. 8491. 96. 64 80. 40 10640. 11760. 15120. 66 .5 12138. 15375. 16993. 21849. 12379. 15680. 17331. 22282.5 2V8 6055. 6963. 7335. 8123. 7925. 10039. 11095. 14265. 1.0 04 12938. 16388. 18113. 23288. 13221. 16746. 18509. 23798. 31 2 95 .0 5544. 6301. 6% 5. 7137. 7620. %2 5. 10668. 13716. 1.0 33 10858. 13753. 15042. 13. 8% 11040. 13984. 15456. 19872. 1.0 55 13174. 16686. 18443. 23712. 13470. 17062. 18858. 24244. 1.5 18 4311. 4702. 4876. 5436. 6878. 8712. %29. 12380. 1.0 40 7295. 8570. 9134. 10520. 8663. 10973. 12128. 15593. 1.0 57 953l. 11468. 12374. 14840. 9975. 12635. 13%5. 17955. 1.5 37 3397. 3845. 4016. 4287. 6323. 8010. 8853. 11382. 16.60 5951. 6828. 7185. 7923. 7863. 96. 90 11009. 14154. 2o.m %3 1 . 11598. 12520. 15033. 10033. 12709. 14047. 18060. 22.82 11458. 14514. 16042. 20510. 11667. 1471-9. 16333. 21000. 5 1.5 62 3275. 3% 6. 3850. 4065. 6216. 7874. 8702. 11 189. 1.0 95 5514. 6262. 6552. 7079. 7602. 9629. 10643. 13684. 2.0 56 10338. 12640. 13685. 16587. 10500. 13300. 14700. 18900. 51 1, 19u) 2835. 3128. 3215. 3265. 5804. 75 3 l. 8125. 10447. 2.0 19 4334. 4733. 4899. 56. 45 6892. 8730. 9649. 12405. 24.70 m. 6957. 7329. 8115. 7923. 10035. 11092. 14261. 2227. 2343. 2346. 24. 36 5230. 62. 65 7322. 9414. 2765. 3037. 3113. 3148. 5737. 7267. 8032. 10327. COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
    • STDmAPIIPETRO RP 7G-ENGL 3998 W 0732290 0609683 222 m PRACTICE FOR DRU STEM DESIGN RECOMMENDED AND OPERAllNG LIMITS 11 DIill Pipe Data T o Joint Data ol meld, Tensile lb Torsional Yield, &lb Nominal Nominal Approx. Drift Weight Size Weight ?srpe OD ID Tool To ol in. lbift lm upset com. in. i. n in pipe3 Jointo P+ b Join@4.85 234 5.26 Eu N m 1.625 97817. 313681. 4763. 6875.b 4.95 Eu OH 1.807 97817. 206416. 4763. 4521.p 5.05 Eu SIX90 1.850 97817. 202670. 4763. 5129.p 5.15 EU wo 1.807 97817. 205369. 4763. 4311.p 6.65 6.99 EU N a 6 0 1.625 138214. 313681. 6250. 6875.b 6.89 Eu OH 1.625 138214. 294620. 6250. 6484.b 6.71 Iu PAC 1.250 138214. 238504. 6250. 4688.P 6.78 Eu SN90 1.670 138214. 202850. 6250. 5129.p6.85 274 7.50 N NC310 2.000 135902. 447130. 8083. 12053.p 6.93 Eu OH 2.253 135902. 223937. 8083. 5585.P 7.05 Eu S m 2.2% 135902. 260783. 8083. 7628.p 7.31 Eu wo 2.253 135902. 289264. 8083. 7197.p 10.40 10.87 Eu NC31(IF) 1 .%3 214344. 447130. 11554. 12053.p 10.59 Eu OH 1.963 214344. 345566. 11554. 8814.P 10.27 Iu PAC 1.375 214344. 272938. 11554. 5730.P 10.59 Eu S9 m0 2.006 214344. 382765. 11554. 11288.p 11.19 Iu XH 1.750 214344. 505054. 11554. 13282.p 10.35 Iu NC260 1.625 214344. 313681. 11554. 6875.B9.50 31, 10.58 Eu NC380 2563 194264. 587308. 14146. 18107.p 9.84 EU OH 2.804 194264. 392071. 14146. 1 1870.p 9.99 EU Sm90 2.847 194264. 366705. 14146. 12650.p 10.14 Eu wo 2.804 194264. 419797. 14146. 12878.p 13.30 312 14.37 Eu H90 2.619 271569. 664050. 18551. 23847.p 13.93 Eu NC380 2.457 271569. 587308. 18551. 18107.p 13.75 EU OH 2.414 271569. 559582. 18551. 17305.p 13.40 Iu NC31(SH) 2.000 271569. 447130. 18551. 11869.P 13.91 EU XH 2.313 271569. 570939. 18551. 17493.p 15.50 16.54 Eu NC380 2.414 322775. 649158. 21086. 20326.p 4 11.85 13.00 Iu H90 2688 230755. 913708. 19474. 35374.p 13.52 Eu NC460 3.125 230755. 901164. 19474. 33625.p 12.10 Eu OH 3.287 230755. 621357. 19474. 21976.p 12.91 Eu wo 3.313 230755. 782987. 19474. 28809.p 14.00 15.04 Iu N c 4 0 2.688 285359. 711611. 23288. 23487.p 15.43 Iu H90 2.688 285359. 913708. 23288. 35374.p 15.85 Eu NCAW? 3.125 285359. 901164. 23288. 33625.p (Table continued on next page.)COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • 12 API RECoMMENDED PRACTICE 76 DlillPipeD;lta Tool Joint Data Tensile Yield, lb TorsionalYield, A-lb Nominal Appmx. D a Si Weight Weight1 Qpe OD ID DiamEte9 Tool Tool m. Ib/ft upset cnm. in. in. in. pipe J&P f@ i Joint6 14.00 15.02 Eu 3.125 285359. 759875. 23288. 27289.p 14.35 Iu 2.438 285359. 512035. 23288. 15170.P 15.70 16.80 Iu 2.563 324118. 776406. 25810. 25673.p 17.09 Iu 2.688 324118. 913708. 25810. 35374.p 17.54 Eu 3.095 324118. 901164. 25810. 33625.p 13.75 15.23 Iu 3.125 270034. 938403. 25907. 38925.p 15.36 Eu 3.625 270034. 9390%. 25907. 37676.p 14.04 Eu 3.770 270034. 554844. 25907. m39.p 14.77 Eu 3.750 270034. 849266. 25907. 33651.P 16.60 18.14 IEU 2.875 330558. 976156. 30807. 34780.p 17.92 IEU 3.125 330558. 938403. 387 00. 38925.p 17.95 Eu 3.625 330558. 939096. 30807. 37676.p 17.07 Eu 3.625 330558. 713979. 30807. 27243.p 16.79 IEU 2.563 330558. 587308. 387 00. 18346.P 18.37 IEU 3.125 330558. 901164. 30807. 33993.p 20.00 21.64 IEU 2.875 412358. 976156. 36901. 34780.p 21.64 IEU 2.875 412358. 1085665. 36901. 45152.p 2159 Eu 3.452 412358. 1025980. 36901. 41235.p 2.9 20 IEU 2.875 412358. 1048426. 36901. 39659.p 22.82 24.11 Eu 3.452 471239. 1025980. 40912. 41235.p 24.56 IEU 2.875 471239. 1048426. 40912. 3%59.p 19.50 22.28 IEU 3.625 395595. 1448407. 41167. 60338.b 20.85 IEU 3.625 395595. 939095. 41167. 37676.p 2.0 56 28.27 IEU 3.375 530144. 1619231. 52257. 60338.b 26.85 IEU 3.375 530144. 1109920. 52257. 44673.p 21.90 23.78 IEU 3.875 437116. 1265802. unlo. 56045.p 24.70 26.30 IEU 3.875 497222. 1265802. 56574. 560459 25.20 27.28 IEU 4.875 489464. 1447697. 70580. 73620.p 27.70 29.06 IEU 4.875 534198. 1447697. 76295. 73620.pCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • AND OPERATING L PRACTICE FOR DRU S T E M DESIGN RECOMMENDED " 13 Mechauicalhpexties DrillPipeData Tool Joint Data Tensile Xeld, lb T m i o d Yield, &lb NominalNominal Approx. Drift Weight Size Weight OD ID Diameter? Tool Tool i. n l m lbht Typeupset corm. i. n in. i n pipe Joint4 pipe Joint56.65 231, 7.1 1 EU-x95 3% 1.625 175072 313681. 7917. 6875.b 6.99 EU-X95 3V4 1.670 175072. 270223. 7917. 6884.p 6.65 7.11 EU4105 3, 1 1.625 193500. 313681. 8751. 6875.b 6.99 EU4105 3V, 1.670 193500. 270223. 8751. 6884.P 10.40 274 11.09 EU-x95 4lI8 1.875 271503. 495726. 14635. 13389.p 10.95 EU-X95 4 1.875 271503. 443971. 14635. 13218.p 10.40 11.09 EU4105 4Ia 1.875 300082. 495726. 16176. 13389.p 10.95 EU4105 4 1.875 300082. 443971. 16176. 13218.p 10.40 11.55 EU-S135 4Va 1.500 385820. 623844. 20798. 17170.p 11.26 EU-S 135 4l1, 1.500 385820. 572089. 20798. 17213.p 13.30 3lI2 14.60 EU-x95 SV4 2.619 343988. 645. 600 23498. 23833.p 14.62 EU-X95 5 2.438 343988. 649158. 23498. 20326.p 14.06 EU-X95 4314 2.438 343988. 596066. 23498. m79.p 13.30 14.71 EU4105 5 2.313 380197. 708063. 25972 22213.p 14.06 EU-GlOS 4V4 2.438 380197. 596066. 25972. 20879.p 13.30 14.92 EU-S135 5 2.000 488825. 8424.40. 33392. 26515.P 14.65 EU-S135 5 2.000 488825. 789348. 33392. 28U78.p 15.13 EU-S 135 5% 2.313 488825. 897161. 33392. 29930.p 15.50 16.82 EU-x95 5 2.313 408848. 708063. 26708. 22213.p 15.50 17.03 EU4105 5 2.000 451885. 842440. 29520. 26515.p 16.97 EUG105 SI4 2.438 451885. 838257. 29520. 27760.p 15.50 17.57 EU-S135 SI2 2.125 580995. 979996. 37954. 32943.p 4 14.00 15.34 N-X95 51, 2.563 361454. 776406. 29498. 25673.p 15.63 N-X95 SI2 2.688 361454. 913708. 29498. 35374.p 16.19 EU-X95 6 3.125 361454. 901164. 29498. 33625.p 14.00 15.91 N4105 511, 2.313 399502. 897161. 32603. 301 14.p 15.63 N-G105 5lI2 2.688 399502. 913708. 32603. 35374.p 16.19 EU-G105 6 3.125 399502. 901 164. 32603. 33625.p 14.00 16.19 N-S135 51, 1.875 513646. 1080135. 41918. 36363.p 15.63 N-S135 51, 2.688 513646. 913708. 41918. 35374.p 16.42 EU-S 135 6 2.875 513646. 1048426. 41918. 39229.p 15.70 17.52 lux95 5V2 2.313 410550. 897161. 32692. 301 14.p 17.23 N-x95 512 2.688 410550. 913708. 32692. 35374.p 17.80 EU-X95 6 3.125 410550. 901164. 32692 33625.p 15.70 17.52 N-G105 512 2.313 453765. 897161. 36134. 301 14.p 17.23 N-G105 51, 2.688 453765. 913708. 36134. 35374.p 17.80 EUG105 6 3.125 453765. 901164. 36134. 33625.9 15.70 18.02 EU4135 6 2.875 583413. 1048426. 46458. 39229.p 16.60 4lI2 18.33 IEU-x95 6 2875 418707. 976156. 39022. 34780.p 18.11 IEU-x95 6 3.125 418707. 938403. 39022. 38925.p 18.36 EU-X95 6% 3.625 418707. 939095. 39022. 37676.p 18.79 IEU-x95 6V4 2.875 418707. 1048426. 39022. 3%59.p 16.60 4V2 18.33 IEU-G105 6 2.625 462781. 976156. 43130. 34780.p 18.33 IEU-G105 6 3.125 46278l. 1085665. 43130. 45152.p 18.36 EU4105 6% 3.625 46278l. 939095. 43130. 37676.p 18.79 IEU-G105 614 2.875 46278l. 1048426. 43130. 39659.p 16.60 19.19 IEU-S 135 6l1, 2.375 595004. 1235337. 55453. 44769.p (Table continued on next page.)COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP ?G-ENGL L998 m 0 7 3 2 2 9 0 0609684 T 3 1 M 14 API RECOMMENDEDPRACTlCE 7 6 Table 9"echanical Properties of New TodJoints and New High Strength Drill Pipe (Continued) 18.62 EU4135 31, 3.375 595004. 1109920. 55453. 44673.p 19.00 EU-S 135 21 3, 2.625 595004. 1183908. 55453. 44871.p 20.00 22.39 m-x95 21 1, 2.375 522320. 1235337. 46741. 44265.p 21.78 Eux95 3Ib 3.125 522320. 938403. 46741. 38925.p 22.08 EU-X95 312 3.375 522320. 1109920. 46741. 44673.p 22.67 IEU-x95 231, 2.625 522320. 1183908. 46741. 44871.p 20.00 22.39 IEU-G105 214 2.375 577301. 1235337. 51661. 44265.p 22.00 IEU-G105 3 2.875 577301. 1085665. 51661. 45152.p 22.08 EUX3105 3lI2 3.375 577301. 1109920. 51661. 44673.p 22.86 IEU-G105 211, 2.375 577301. 1307608. 51661. 4%30.p 20.00 23.03 EU-S135 3 2.875 742244. 1416225. 66421. 57800.p 23.03 EU-S135 21 1, 2.125 742244. 1419527. 66421. 53936.p 22.82 25.13 IEU-x95 2, 1 2.125 596903. 1347256. 51821. 48912.p 24.24 N-X95 3l1, 3.375 596903. 1109920. 51821. 44673.p 24.77 IEU-X95 21 3, 2.625 596903. 1183908. 51821. 44871.p 22.82 24.72 EU43105 31, 3.125 659735. 1268963. 57276. 51447.p 24.96 IEU-G105 21 1, 2.375 659735. 1307608. 57276. 4%30.p 22.82 25.41 EU-S135 21 3, 2.625 883. 420 1551706. 73641. 63406.p 1950 22.62 IEU-x95 3% 3.625 501087. 1448407. 52144. 60338.b 21.93 m-x95 31, 3.125 501087. 1176265. 52144. 51807.p 21.45 IEu-x95 31, 3.375 501087. 1109920. 52144. 44673.p 19.50 22.62 IEU-G105 331, 3.625 553833. 1448407. 57633. 60338.b 22.15 IEUX3105 3 2.875 553833. 1323527. 57633. 58398.p 21.93 IEU-G105 3lIb 3.125 553833. 1268963. 57633. 51447.p 19.50 23.48 IEU-S135 31, 3.375 712070. 1619231. 74100. 72627.p 22.61 EU-S135 21 3, 2.625 712070. 1551706. 74100. 63406.p 25.60 28.59 IEU-x95 31, 3.375 671515. 1619231. 66192. 60338.b 27.87 IEU-X95 3 2.875 671515. 1416225. 66192. 56984.b 25.60 29.16 IEU-Gl05 31, 3.375 742201. 1619231. 73159. 72627.p 28.32 IEUGlM 21 3, 2.625 742201. 1551706. 73159. 63406.b 25.60 29.43 EU4135 31, 3.125 954259. 1778274. 94062. 76156.b 21.90 24.53 m-m 3% 3.625 553681. 1448407. 64233. 60338.b 24.80 IEU-x95 3lI2 3.125 553681. 1268877. 64233. 59091.p 21.90 25.38 IEUGl05 3l1, 3.375 611963. 1619231. 70994. =.P 21.90 26.50 m4135 3 2.875 7809. 1925536. 91278. 873419 24.70 27.85 m-m 3l1, 3.375 629814. 1619231. 71660. 726279 24.70 27.85 IEU43105 3V2 3.375 696111. 1619231. 79204. 72627.p 24.70 2. 7n EU4135 3 2.875 894999. 1925536. 101833. 87341.p 25.20 27.15 m-m 5 4.875 619988. 1448416. 89402. 73661.p 25.20 2820 IEUX3105 4V4 4.625 685250. 1678145. 98812. 86237.p 25.20 29.63 EU4135 4l/, 4.125 881035. 2102260. 127044. la9226.p 27.70 30.1 1 m-x95 41 3, 4.625 676651. 1678145. 96640. 86237.p 27.70 30.1 1 EU43105 4% 4.625 747250. 1678145. 106813. 86237.p 27.70 31.54 EUS135 41 1, 4.125 961556. 2102260. 137330. 1092269COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL L978 m 0 7 3 2 2 9 0 0609685 978 9 RECOMMENDED PRACTICE FOR DRU STEM DESIGN AND OPERATING LIMITS 15 Table 1&Recommended Minimum OD* and Make-up Torque Weld-on Type Tool Joints of Based on Torsional Strength Box and Drill Pipe of Min. %.BOX Make-up Mn i. %.BOX Make-up Drill Pipe Tool New Joint Data OD Shoulder Torque for OD Shoulder Torque f a Nom Nominal New New Make-up Tool withEccen- b&. OD To ol with Eccen- Min. OD Size Weight -Upset OD ID T-d Joint Wear Joint Tool tricwear tric Joint Tool Joint in. lWft a n d m Conn. m. i. n fi-lb in. in. ft-lb in. m . ft-lb 21 3, 4.85 EUE75 NC26 3% 4,125 B 1,945 I132 1,689 4.85 EU-E75 W.O. 3% 2,586 P 1,994 1,746 4.85 EU-E75 234 OHLW 314 2,713 P 1,830 %4 1,589 4.85 EU475 234 SLHW 3v, 3,074 P 1,996 164 1,726 234 6.65 WE75 2 1 PAC 3, 21 7, 2,813 P 2,455 164 2,055 6.65 EU-E75 NC26 334 4,125 B 2,467 "16 2204 6.65 EU-E75 21 SLHW 3, 3v4 3,074 P 2549 "16 1,996 6.65 EU-E75 2 1 OHSW 3, 31/, 3,891 B 2,324 5454 2075 21 38 6.65 EUX95 NC26 3% 4,125 B 3,005 342 2734 234 6.65 EU-G105 NC26 33/, 4,125 B 3,279 7/y( 3,005 27j8 6.85 EU-E75 NC31 41/, 7,122 P 3,154 Il6 2,804 6.85 EU-E75 274 wo 4V8 4,318 P 3,216 I16 2,876 6.85 EU-E75 274 OHL.W pl, 3,351 P 3297 5/64 2666 6.85 EU-E75 271~SGHW 374 4,575 P 3.397 "16 2,666 274 10.40 EVE75 NC3 1 414 7,122 P 4,597 4 . 4 3.867 10.40 IU-E75 274 XII 41/, 7,969 P 4,357 76 14 3.664 10.40 WE75 NC26 334 4,125 B 4,125 %2 3,839 10.40 EVE75 274 OHSW 37/8 5,270 P 4273 7/64 3.941 1.0 04 EUE75 21 S L H ~ 7, 374 6,773 P 4,529 7k4 3,770 10.40 WE75 274 PAC 31/, 3,439 P 3,439 "la 3.439 21 78 10.40 EU-x95 NU1 41/, 7,918 P 5,726 5/32 4,969 10.40 EU-x95 2 1 SGHW 7, 37/, 6,773 P 5,702 5/32 4,915 10.40 EU-G105 NC31 41 1, 7,918 P 6.1 10 5,345 10.40 EU-Sl35 NC31 434 10,167P 7,694 6,893 9.50 EU-E75 NC38 41 3, 7,688 P 5,773 %2 4.797 9.50 EU-E75 NC38 41 3, 10,864P 5,773 1% 4,797 9.50 EU-E75 34 OHLW 43/, 7,218 P 5,340 1 4,868 9.50 EU-E75 3V2SGH90 454 7.584 P 5,521 3/32 5,003 31 1, 13.30 EWE75 NC38 43/, 10,864P 7274 5 u8 6 13.30 WE75 NC3 l2 41/, 7,122 P 6,893 13/64 6110 13.30 EU-E75 3 1 OHSW 3, 43/, 10,387 P 7,278 %2 6399 13.30 EWE75 3V2H90 51, 14,300P 7,064 7454 6,487 13.30 EU-X95 NC38 5 12,196 P 8,822 3/~6 7,785 13.30 EU-X95 3V2SGHW 454 2y6 11,137 P 8,742 7,647 13.30 EU-X95 3V2H90 51 1, 21 3, 14,300P 8,826 9/64 7,646 314 13.30 EU-G105 NU8 5 13,328 P 9,879 742 8,822 314 13.30 EU-S135 NC40 17,958 P 12,569 10,768 13.30 EU-S135 NC38 5 15,909P 12,614 1% 10,957 15.50 EUE75 NC38 5 12,196 P 7,785 %2 6,769 15.50 EU-X95 NC38 5 13,328 P 9,879 8,822 7132 15.50 EU-G105 NC38 5 15,909 P 10,957 9,348 15.50 EU-G105 NC40 514 16,656P 11,363 9,595 "Iw 3v2 15.50 EU-S135 NC40 s/, 19,766P 14,419 "164 11,963 4 11.85 EU-E75 NC46 6 20,175 P 7,843 6,476 11.85 EU-E75 4 WO 5% 17385 P 7,843 5/a 6,476 (Table conhued on next page.)COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • m 0732290 D b 0 9 b 8 b 804 m 16 API REC~MMENDED PRACTICE 7 6 Table 1+Recommended Minimum OD* and Make-upToque of Weld-on Type Tool Joints of Based on Torsional Strength Box and Drill Pipe(Continued)(2) (1) (3 (6) (9) C) I (8) (13) (12) (0 1) (11) class2 New Tool Joint Data mO Bx Make-up %.Box Make-up Shoulder Toque for shoulder Toque for Nominal Nm O New New Make-up with Eccen- Min. OD with Eccen- Min. OD Size weight W U P W ID OD Tasue6 tric Wear Tool Joint tdc Wa Tool Joint er in. lblftandGrade corm. i. n m. fi-lb i. n fi-lb in. ft-b 11.85 EU-E75 40HLW 51, 3"In 13,186 P 91a 7,866 164 6,593 11.85 IU-E75 4H 0 9 SI2 2VI6 21224 P 7J64 7,630 3J32 6,962 4 14.00 IU-E75 NC40 S I4 2VI6 14,092P V16 9,017 I32 7,877 14.00 EU-E75 NC46 6 3V4 20,175 P 9/61 9233 7Ja 7,843 14.00 IU-E75 4 SIP @I0 294, 9,102 P Isla 8,782 134, 7,817 14.00 EU475 4 OHSW 51, 34 1 16,320 P 9,131 5 7,839 14.00 IU-E75 4H 09 51, 2u1,6 21,224 P 8,986 7J64 7,630 4 14.00 IU-X95 NC40 SI4 211116 15,404 P I4 11,363 va 9,595 14.00 EU-X% NC46 6 3V3 20.175 P 3116 11,363 J32 9,937 14.00 IU-X95 4H 0 9 SI2 2u116 21324 P Y, 11,065 5J32 9,673 4 14.00 IU-G105 NC40 511, 271,~ 18,068 P 12,569 151a 10,768 14.00 EU4105 NC46 6 3V3 20,175 P 7132 12,813 ll la 10,647 14.00 IUG105 4H 0 9 SI2 2VI6 21224 P 7 1 ~ 1 ~ ~ 1 3116 11,065 4 14.00 EU3135 3 NC46 6 23,538 P ¶Ip 15,787 Il., 14,288 4 15.70 IU-E75 NC40 SI4 2VI6 15,404 P Ila 10,179 "Iw 8,444 15.70 EU4375 NC46 6 313 20,175 P 5J32 9,937 18 8,535 15.70 WE75 4H 0 9 5V, 2u116 21224 P 9,673 18 8,305 4 15.70 IU-X95 NC40 SI, 2llL6 18,068 P 12,569 "la 10,768 15.70 EU-X95 3 NC46 6 23,538 P la 12,813 "la 10,647 15.70 IU-x95 4H 0 9 5V, 2VI6 21224 P 7 1 ~ na,1 3116 11,065 4 15.70 EU4105 3 NC46 6 23,538 P V a 13,547 l3la 12,085 15.70 IU-GlOS 4H 0 9 SI, 2YI6 21224 P I4 13,922 134, 11,no 4 15.70 IU-S135 NC46 6 254 26,982 B "la 18.083 a V 15,035 15.70 EU3135 NC46 6 271~ 25,118 P 21164 18,083 15,035 "I4 4, V 16.60 IEU-E75 41, FH 3 6 20,868 P 13/64 12.125 10,072 16.60 EUX75 NC463V4 6l1, 20.3% P 131~ 12,085 "Iw 10,647 16.60 IEU-E75 411 OHSW YI0 3314 16,346 P "I4 11,862 " a 10,375 l 16.60 EU-E75 NC50 @I8 3314 22,836 P 51% 11,590 V a 10,773 16.60 IEU-E75 411 H 9 -0 6 314 23,355 P 3116 12,215 51% 10,642 16.60 lEU-X95 411 FH 6 21 3, 23,843 P lia 14,945 la 12,821 16.60 IEu-X95 NC46 61, 3V, 20.3% P Ila 15,035 la 12,813 16.60 EUX95 NCM VIg 3314 22,836 P 14,926 3116 13,245 16.60 IEu-X95 41, H-90 6 3 27,091 P I, 15,441 l l 3a 13.102 4ll2 16.60 IEUGl05 412 FH 6 21 3, 23,843 P 194, 16,391 1, 14,231 16.60 IEU-GlO5 NC46 614 3 23,795 P a V 16346 I, 14,288 16.60 EU4105 NC50 VIg YI, 22,836 P I4 16,633 "la 14,082 16.60 IEU4105 41. H-903 6 27,091 P "la 16264 "la 14,625 41, 16.60 IEU-S135 NC46 61 1, 231, 26923P "la 21930 21a 18,083 16.60 EU-Sl35 NC50 VIg 3Y2 27,076 P 211a 21,017 vp 18,367 41 V 20.00 IEU-ms 4V2FH 3 6 20.868 P 1,14,231 131~ 12125 20.00 mm75 NC46 61, 3 23,795 P 1,14,288 134, 12,oss 20.00 EUX75 NCM @Ig 3V0 24.993 P " a 14,082 l "la 12,415 20.00 IEu-E75 411 H-90 3 6 27,091 P la 13,815 3116 12215 4ll1 20.00 IEu-x95 412 FH 6 21 1, 26359 P 17,861 91a 15,665 20.00 IEu-x95 NC46 et, 231~ " a 18,083 l la 15,787 20.00 EU-x95 NCM @I0 3ll2 27.076 P l l 7a 17,497 151~ 15,776 20.00 m-x95 412 H-903 6 27,091 P l9la 17,929 V , 15,441 (Table continued m next W.) COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
    • STD-API/PETRO P R 7G-ENGL L978 m 0732270 0607687 790 m RECOMMENDED PRACTICE FOR DRU STEM DESIGNAND OPERATING LIMITS 17 Table 1&Recommended Minimum OD* and Make-up Toque o Weld-on TypeTool Joints f Based on Torsional Strength Box and Drill Pipe (Continued) of(4) (1) (3) (13) (12) (2) (11) (10) (9) (5) (8) (6) (7) premiumclass class 2 Min. Min. BOX Make-up Min. &.BOX Make-up m Pipe New Tool Joint Data OD OD Shoulder T r u for oqe Shoulder Ibrquefor Nominal Nom New New Make-up Tool withEccen- Min. OD Tool with Eccen- Min. OD Size -Upset Weight OD ID Torqd Joint eicWear Tool Joint Joint tdc Wear Joint Tool lWft in. andGrade C0nn. in. m. ft-lb m. in. &lb in. in. %lb 20.00 IEU-GlOS NC46 29,778 P 19,644 17,311 20.00 EU-G105 NC50 27,076 P 20,127 16,633 20.00 EU-S135 NC50 36,398 P 25,569 21,914 19.50 EVE75 NU0 22,836 P 15,776 14,082 19.50 EU-X95 NC50 27,076 P 20,127 17,497 19.50 EUX95 5 H-90 31,084 P 19,862 17,116 19.50 EU-G105 NC50 3 1,025P 21,914 19244 19.50 EUG105 5 H-90 35,039 P 21,727 18,940 19.50 IEU-S135 NB0 38,044 P 28,381 24,645 19.50 IEU-S135 51f2FH 43,490 P 28,737 24,412 25.60 EU-E75 NC50 27,076 P 20,127 17,497 25.60 EU475 5112FH 37,742 B 20,205 17,127 25.60 IEU-X95 NC50 34,680 P 25,569 21,914 25.60 Eux95 511, FH 37,742 B 25,483 22294 25.60 EU-G105 NC50 38,044 P 27,437 23,728 25.60 IEU-Gl05 5l/, FH 43,490 P 27,645 24,412 25.60 IEU-S135 51, FH 47,230 B 35,446 30,943 21.90 EU-E75 5V2FH 33560 P 19,172 17,127 21.90 IEU-x95 5V2FU 37,742 B 24,412 21m 21.90 IEU-x95 512 H-W 35,454 P 24,414 21,349 21.90 IEU-GlOs 5V2FH 43,490 P 27,645 23.350 21.90 IEU-S135 5Il2FH 53,302 P 35,446 30,943 24.70 EU-E75 51, FH 33,560 P 22294 19,172 24.70 IEU-X95 51, FH 43,490 P 27,645 23,350 24.70 IEUG105 SI2FH 43,490 P 29,836 26,560 24.70 EUS135 5V2FH 5z302 P 38,901 33,180 25.20 EU-E75 @I8FH 44,1% P 26,810 24,100 EU-x95 VI8FH 44,196 P 35,139 29,552 EU-G105 @I8FH 5 1,742P 37,983 33,730 IEU-S135 @I8FH 65,535 P 48204 42,312 27.70 EUE75 FH @I8 44,1% P 29,552 25,451 ~ IEU-x95 FH @I8 51,742 P 37,983 32,329 EU-G105 @I8FH 51,742 P 40,860 36,556 IEU-S135 VI8FH 65.535 P 52,714 45241 The use of outside diameters (OD) smaller than those listed in the. table may be acceptable due t special service requirements. o Tool joint with dimensions shown has lower torsional yield ratio than the 0.80 which is generally used. 3Recommended make-up toque i based on 72,000 psiSWS. s 4 i n calculation of torsional strengths of tool joints, both new and wom, the bevels of the tool jointshoulders are disregarded. This thickness measurement should bemadeinthe.planeofthe~fromtheLD.oftheco~~boretotheoutsidediameterofthebox,disregardingthebevels. tool joint with outside diameter less thanAm bevel diameter should be providal with a minimum Vu inch depth x 45 degree bevel on t e outside and an h inside diameter of t ebox shoulder and outside diameter of the pin shoulder. h 6p=Phlimit,B=B~~limit *Todjoint diameters specifiedare qid to retain torsid m n g t h in the tool joint comparablet the.torsional strength of the attached drill pipe. These should u r e o be adequate for all servi e.Tool joints with torsional strengths considerablybelow that of the drillpipe may be adequate for much drilling serviœ. cCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • 18 API RECOMMENDEDPRACTICE 6 7 Table 11 “Buoyancy Factors (1) () 2 (3) Mud Density Wgal Mud Density WcuA Buoyancy Factor, Kb 84 . 6.4 28 X7233 86 . .a66 88 . 65.83.32 9.0 362 92 68.82 359 32 9.4 356 81 9.631 98 . .850 80 1. 00 30 1. 02 .W.80 10.4 .841 29 1. 0679 1. 0829 1. 10 33278 1. 12 1. 14 85.28 32677 1. 1627 1. 18 .a20 1. 20 89.77 .81726 1. 22 31476 1. 24 1. 26 9.5 42 .an75 1. 28 .804 1. 30 97.25 .80174 1. 3202 .4 1. 3417 .4 1. 3632 .3 1. 3847 .3 1. 4062 .2 1. 4277 .2 1. 440922 14.607 .1 1. 48 .n422 .1 1. 50 .771 .6 78 152 137 1.01520 15.467 .0 1. 5681 .9 1. 5896 .9 1. 60 .752 162 121.1826 .8 1. 6441 .8 1. 6656 .7 1. 6871 .7 1. 7086 .6 1. 7201 .6 1. 74 116 3.6 1. 76 131 .5 1. 78 1. 80 134.65 -72583.9 1. 8521 .3 1. 9058 .7 1. 95 2. 00 196 4.1 .9 64 COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
    • STD-API/PETRO RP 7G-ENGL 1998 m 0732290 0609689 513 m PRACTICE FOR DRIU STEM DESIGN RECOMMENDED OPERATING AND LIMITS 19 Table 1"-Rotary Shouldered Connection Interchange Lt i s 2.876 4 2 (V-0.038 rad) N.C. 262 21 7: 3.391 4 2 v-0.065 3V2"Slim Hole (V-0.038 r d a) N.C. 312 3 1" 1, 4.016 4 2 v-0.065 4V2"Slim Hole (V-0.038 rd a) N.C. 382 4" 4.834 4 2 v-0.065 4V2"Extra Hole (V-0.038 rad) N.C. 462 411," 5.250 4 2 v-0.065 5" Ekdm Hole (V-0.038 rda) N.C. 502 5; Double Streamline V Full Hole ( H ) E. 4 4.280 4 2 v-0.065 4V2" Double Streamline (V-0.038 rad) N.C. W Extra Hole 271," (E.H.) Q.H.) 3.327 4 2 v-0.065 3V," Double Seeamline (V-0.038 r d a) 3v2- 3.812 4 2 v-0.065 4" Slim Hole (V-0.038 r d a) 4V2"Extemal Flush 4V2" 4.834 4 2 V-0.065 4" IntanalFlush (V-0.038 rad) N.C. W 5" 5.250 4 2 v-0.065 4l1," IntemalFlush (V-0.038 rad) N.C. 502 S1I2" Double Streamline Slim Hole (.. SH) 271: 2.876 4 2 v-0.065 234" Internal Flush (V-0.038 rad) N.C. 262 311," 3.391 4 2 v-0.065 2; Internal Flush 1 (V-0.038 rad) N.C. 31a 4" 3.812 4 2 v-0.065 3 , Exea Hole V" (V-0.038 rd a) 4V," Extemal Flush 4; V 4.016 4 2 v-0.065 3V2"Internal Flush (V-0.038 rd a) N.C. 38, Double Streirmline (DSL) 31 1; 3.327 4 2 v-0.065 2 1 : Extra Hole (V-0.038 rad) 41," 4.280 4 2 v-0.065 4" Full Hole (V-0.038 rad) N.C. W 5, V" 5.250 4 2 v-0.065 4V2"he a Flush tm l (V-0.038 rad) 5" Extra Hole N.C. 502 Numbered Connection (N.C.) 26 2.876 4 2 V-0.038 rad Z/ Intemal Flush 3: 27/gl(Slim Hole 31 3.391 4 2 V-0.038 rad 21 Iutemal Flush 7: 3 ; Slim Hole V 38 4.016 4 2 V-0.038 rad 31, Internal Flush 41," Slim Hole 40 4.280 4 2 V-0.038 rad 4" Full Hole 4lI; Double Streamline 46 4.834 4 2 V-0.038 rad 4" Intemal Flush 4lI; Extra Hole 50 5.250 4 2 V-0.038 rad 4V," InternalFlush 5" Extra Hole ExtemalFlush @. F) 4V2" 3.812 A 2 v-0.065 4" Slim Hole (V-0.038 rad) 3lI; Extra Hole 1~0nnectims two ttxead forms shown may be machined with either thread form without with gauging or interchangeability. % m ee connections (N.C.) may be machined only with the V-0.038 radius thad form u brdCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • 20 API RECOMMENDEDPRACnCE 7 6 Figures 1 -2+Torsional Strength and Recommended Make-up Toque Curves (All curves based on 120,000 psi minimum yield strength and percent 60 of minimum yield strength for recommended make-up toque.) Tool Joint Pin 1.0. Figure 1-NC26 Torsional Yield and Make-up 3.375 8 i? " 3.125 . " 2.875 I I I I 8 I 7 8 5 k F : 8 ni E$! Cr! N 8 u N ! Tool Joint Pin I.D. Figure 2-234, Open Hole Torsional Yield and Make-upCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • PRACTICE FOR DRU STEM DESIGN RECOMMENDED AND OPERATING L” 21 3.500 8 3.250 Torsional yield strength Recommended make-uptorque Mb 3.000 2.750 Tool Joint PinI.D. Figure Open Wide Torsional and Yield Make-up O z onal yield strength Mb < snded make-uptoque Wb , 2.875 1 8 2 I8 ~ Ln 7 Tool Joint Pin I.D. x Figure 4-2V8 SLHSO Torsional Yield and Make-upCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • ~~ S T D - A P I I P E T R O R P 7G-ENGL 1998 m 0732290 Ob09692 008 m 22 API RECOMMENDEDPRACTlCE 76 Torsional vield strenath 7 7 r Tool Joint Pin I.D. Figure 5-2V8 PAC Torsional Meld and Make-up I O I I I O I R 8 Cu O u! 7 ¿i cri Cu Tool Joint PinI.D. Figure M C 3 1 TorsionalMeld and Make-upCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D - A P I I P E T R O RP 7G-ENGL L998 m 0 7 3 2 2 9 0 0609693 T 4 4 m RECOMMENDED PRACTICE FOR DRU STEM DESIGN OPERATlNG LIMITS AND 23 rength I rc nO 9 8 n! I 8 L 5 rc : 8 F (u (u Ri N v5 Tool Joint Pin I.D. Figure 8-z7/, Wide Open Torsional Yield and Make-upCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • 24 API REC~MMENDED PFIACTICE 6 7 ni Tool Joint Pin I.D. Figure 92/ -’, Open Hole Torsional Yield and Make-up 11 yield strength ftllb Recommendedmake-up toque ftllb 2.750 I I I 8 7 I i r I Tool Joint Pin I.D. Figure 1C+27/8 PAC Torsional Yield and Make-upCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO P R 7G-ENGL L998 m 0732290 0607695 817 m RECOMMENDED PRACTICE FOR DRU STEM DESIGN OPERATING LIMITS AND 25 5.125 4.875 Recommerbded make-up toque 3 Mb Tool Joint Pin I.D. Figure 1 1-NC38 Torsional Yieldand Make-up Tool Joint Pin I.D. Figure 12-3V2 SLHSO Torsional Yield and Make-upCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • 26 API REWMMENDED PRACTlCE 7 6 trength FH Figure l M 2 Torsional Yield and Make-up V Torsional yield strength Recommended ma Mb Tool Joint Pin I.D. Figure 14-3V2 Open Hole Torsional Yield and Make-upCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD*API/PETRO RP 7G-ENGL L998 m 0732290 O b O 9 b 9 7 b 9 T m RECOMMENDED PRACTICE FOR DRU STEM DESIGN AND OPERATING LIMITS 27 4.000 " 8 6 O :: 3.750 ST! v 8 % 8 ) n c 8 -, v O (o o 8 8 8 Torsional yield aren Mb m c " W O 8 .- C (o O - 7 6 82 PC O O I-" Recommended make-up toque (D ;j 8 (o CD fttlb O 3.500 -0 8 v) 3.250 8 I r J Figurek F J 1 F L Tool Joint Yield PAC Torsional Pin I.D.and cj N Make-up 4.875 O O O N 6 O 4.625 i Mb I Torsional yield strength 8 I Recommended make-uptoque O 8 I I I Tool Joint Pin I.D. Figure 16 - 3 V 2 XH Torsional Yield and Make-upCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • ~~ ~~ STD.API/PETRO RP 7G-ENGL L998 m 0732290 Ob09698 526 m 28 API RECOMMENDED P M C E 7 6 5.500 Wlb 5.000 - 5 2 f L 4.500 r- .- I .. oi ci Tool Joint Pin 1.0. ci Figure 174C40TorsionalYield and Make-upCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 71;-ENGL L998 m 0732290 Ob09699 4b2 m RECOMMENDED AND OPERATING LIMITS PRACTICE FOR DRILL STEM DESIGN 29 O O m ” Tool Joint Pin I.D. Figure 1--Inch Open Hole Torsional Yield and Make-up Tool Joint Pin I.D. Figure 2O--NC46 Torsional Yield and Make-upCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • ~~~ ~ S T D - A P I / P E T R O R P 76-ENGL 1998 m 0732290 Ob09700 T04 m 30 PRACT~CE RECOMMENDED API 76 6.000 8 - (o ( u 0 Ri ttt 5.000 Tool Joint Pin I.D. Figure 21-@/, FH Torsional Yield and Make-up I Torsional yield strength fulb I 8 " ) v I l- "L m u! Tool Joint PinI.D. Figure 22-4V2 H90 TorsionalYield and Make-up I Q fCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D - A P I I P E T R O PG - E N G L R7 3778 m 0 7 3 2 2 9 0 0607703 740 m RECOMMENDED FOR PRACTICE DRIUSTEM DESIGN OPERATING AND LIMITS 31 Figure 23-4V2 Open Hole (Standard Weight) Torsional Yield and Make-up 7 ": . 6.500 %o -- O 8 I Torsional yield strength Wb S I- lk Recom&nded makeup toque Mb I I 2 5.750 5: N Tool Joint Pin I.D. Figure 24-NC50 Torsional Yield and Make-upCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO P R 7G-ENGL L998 m 0732290 Ob09702 8 8 7 32 API RECOMMENDED PRACTICE 76 + Tool Joint Pin I.D. Figure 25--5V2 FH TorsionalYield and Make-upCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL L998 m 0732290 Ob09703 713 m RECOMMENDED PRACTICE FOR DRIU STEM DESIGN OPERATlNG AND LIMITS 33 4.12 The recommendedmake-uptorque fora usedtool detexminhg the minimum acceptable bending strength ratio joint is determined by taking the following steps: for aparticular area and type of operation. 4.1 2.1 Select the appropriately titled curve for the and size 5.7 Certain other precautions should be observed in using type tool joint connection being studied. these charts.It is imperative that adequate shoulder width and area at the end of the pin be maintained. The calculations 4.1 2.2 Extend a horizontal line from the under consid- OD involvingbending strength ratios are based on standard eration to thecurveand read therecommendedmake-up dimensions for connections. all torque representing the box. 5.8 Minordif€erences between measuredinsidediameter 4.12.3 Extend a vertical line h m the ID under consider- and inside diameters Figures 26 through 32 are of little sig- in ation to the curve and the recommended make-up torque read figure with the inside diameter nifìcance; therefore select the representing the pin. closest to measured inside diameter. 4.12.4 The smaller the of two recommendedmake-up 5.9 The curves in Figures 26 through 32 were determined torques thus obtained is the recommended make-up torque from bending strengthratios calculated by using the Section for the tool joint. Modulus (Z) as the measure of the capacity of a section to 4.12.5 A make-up torque higher than recommended may resist any bending momentto which it may be subjected. The be requiredunder extreme conditions. effect of stress-relief featuresdisregarded. The equation, its is derivation, and an example of its are included in use A.lO. 5 Properties Of Drill Collars 6 Properties of Kellys 5.1 Table 13 contains steel drill collar weights for a wide range of OD andID combinations, in both A P I and non-API 6.1 Kellys are manufactwd with one of two drive confìgu- sizes. Values in the table may be used to provide the basic rations, square or hexagonal. Dimensions are listed in Tables information required to calculate the weights of drill collar 2 and 3 entitled “Square Kellys” and “Hexagon Kellys” of strings that are not made up of collars having uniform and API Specification 7. standard weights. 6.2 Square kellys are furnished forged or machined in the as 5.2 Recommended make-up torque valuesfor rotary shoul- sections are normal- drive section. On forged kellys, the drive listed dered drill collar connections are in Table14. These val- ie and tempered and the are quenched and tempered. zd ends ues are listed for various connection styles and for commonly 6.3 Hexagonal or fully machined kellys square are used drill collar OD and ID sizes. The table also includes a may machined from round bars. Heat treatmentbe either designation of the W& member @ or box) for each con- in nection size and style. 6.3.1 Full lengthquenchedandtemperedbeforemachin- or ing; I 5.3 Many drill collarconnection failms are aresultof bending stresses ratherthantorsionalstresses.Figures 26 6.3.2 The drive section nonnalized and tempered and the through 32 may be used for determining the most suitable ends quenched and tempered. connection tobe used on new drill collars or selecting the for It should benoted that fully quenched drive sections have new connection to be used on collars which havebeen worn higher minimum tensile yield strength thannormalized drive down on the outside diameter. sections when tempered to the same hardness level. For the same hardness level, the ultimate tensile may be con- strength 5.4 A connection that has a bending strength ratio of 2.50 1 sidered as the samein both cases. is generallyaccepted as anaveragebalancedconnection. However, theacceptablerange may vary from 3.20:l to 6.4 The following criteria should considered in selecting be 1.90: 1 depending upon the drilling conditions. square or hexagonal kellys. 5.5 As the outside diameter of the box wwear more r p l i a 6.4.1 It may be noted from Table 15 that the drive section idly than pin the inside diameter, resulting the bending of the hexagonal kelly strongerthan the drive section of the is strength ratio will be reduced accordingly. When the bending square kelly when the appropriate kelly is selectedgiven for a strengthratiofallsbelow 2.00:1, connectiontroublesmay casing size. begin.Thesetroublesmayconsistofswollenboxes,split boxes, or fatigue cracks in the boxes last engagede d at the tra. h Example: A 4V4-inch square kelly a5V4-inch hexagonal for or kelly would be selected use in 85/8-inch casing. It should benoted, however, that the connectionson these I 5.6 The minimum bending strength ratio acceptable in one two kellys are generally the same unless the bores (inside and operating area may not be acceptable in another. Local operat-diametem) are the same, kelly with the smaller bore could the ing practices experience based on recent predominance of be interpreted to have the greater pin tensile and torsional failuresandotherconditionsshouldbeconsidered when strength. Vext continued on page 46.)COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD=API/PETRO RF "G-ENGL L998 m 0732290 0609704 657 m 34 API REMENDED P M C E 76 Table 13"Drill Collar Weight (Steel) (pounds per foot) inches 1 1, 1 131, 2 3 31, 3V2 VI, 4 24 19 18 16 3 21 20 18 20 22 3V0 22 314 26 24 22 312 30 29 27 33 314 35 32 4 40 39 37 2935 32 44 43 41 39 37 35 32 4, 1 46 44 42 40 35 38 412 51 50 48 46 43 41 4314 52 54 50 47 44 59 61 56 53 50 68 65 63 60 57 75 73 70 67 64 60 82 80 78 67 75 72 64 60 90 88 85 83 79 75 72 68 98 % 94 91 88 83 72 80 76 107 105 102 99 % 85 91 89 80 116 114 111 108 105 930 10 98 89 125 123 10 2 117 114 110 107 103 98 93 84 134 132 130 127 14 2 119 116 112 108 103 93 14 4 142 139 137 133 129 16 2 122 117 113 102 154 152 150 147 144 139 136 132 18 2 123 112 165 163 160 157 154 150 147 143 138 133 122 176 174 171 168 165 160 158 154 149 144 133 187 185 182 179 176 172 169 165 10 6 155 10 5 210 208 m m3 u)(] 195 192 179 188 184 174 234 232 230 227 224 220 216 212 2 0 9 2 0 6 198 248 245 243 240 237 232 229 225 221 216 211 10 21 6 259 257 254 235 2 1 5 246 239 243 2 3 0 2 2 5 11 313 315 317 310 307 302 299 295 291 286 281 12 377 379 374 371 342 368 347 364 361 352 357COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STDmAPI/PETRO RP 7G-ENGL L998 m 0732290 Ob09705 5 9 6 m PRACTICE FOR DRILL STEM DESIGN RECOMMENDED AND OPERATING LIMITS 35 Table 14"Recommended Make-up Torque for Rotary Shouldered Drill Collar Connections (See footnotes for use of this table.)(2) (1) (5) (13) (12) (6) Q (11) (10) (8) (9) connection Minimum Make-up Toque ft-lW Size, OD, Bore of Drill collar,i n c h 1v4 in. W 112 1V4 in. 1 23, 14 22, 11 21 1, 3 3V, NC 23 *2,508 *2,508 *vos *3,330 *3,330 2,647 4,000 3,387 2,647 W 1 *231 1,749 *3,028 2,574 1,749 335 2,574 1,749 PC A? *3,797 *3,797 2926 *4,966 4,151 2,926 5m 4,151 2926 API IF *4,606 *4,606 3,697 NC 26 5,501 4,668 3,697 *3,838 *3.838 *3,838 5,166 4.95 1 4,002 5.766 4,95 1 4,002 Slim Hole Extra Hole *4,089 *4,089 *4,089 Double streamline *5,352 *5,352 *5,352 Mod. open *&O59 *&O59 7,433 APIIF *4,640 *4,640 *4,640 *4,640 NC 31 *7,390 *7,390 *7,390 6,853 Rg l eua *6.466 *6,466 *6,466 *6,466 5,685 *7,886 *7,886 *7,886 7,115 5,685 10,47 1 9,514 8,394 7,115 5,685 Slim Hole *8,858 *8,858 8,161 6,853 5,391 10,286 9.307 8,161 6,853 5,391 NC 35 *9,038 *9,038 *9,038 7,411 12,273 10,826 9,202 7.41 1 12,273 10,826 9302 7,411 Extra Hole *5,161 *5,161 *5,161 *5,161 Slim Hole *8,479 *8,479 *8,479 8,311 Mod.Open *12,074 11,803 10,144 8,311 13,283 11,803 10,144 8,311 13,283 1 1,803 10,144 8,311 API IF *9,986 *9,986 *9.986 9,986 8,315 NC 38 *13,949 *13,949 12,907 10,977 8,315 Slim Hole 16,207 14,643 12,907 10,m 8,315 16,207 14,643 12,907 10,977 8,315 H-W *8,786 *8,786 *8,786 *8,786 *8,786 * 12,794 *12,794 *12,794 *12,794 10,408 *17,094 16,929 15,137 13,151 10,408 18,522 16,929 15,137 13,151 10,408 Full Hole *10,910 *10,910 *10,910 *10,910 *10,910 NC 40 *15,290 *15,290 *15,290 14,%9 12125 Mod. Open *19,985 18,886 17,028 14,969 12,125 Double StFeamline 20,539 18,886 17,028 14,969 12,125 20,539 18,886 17,028 14,969 12,125 (Table continued on next page.)COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL L998 M 0732290 Ob0970b 422 m H-W * 12,590 *lu90 *12,590 *12,590 *1u90 *17,401 *17,401 *17,401 *17,401 16,536 *%S31 *m31 21,714 19,543 16,536 25,408 23,671 21,714 19,543 16,536 25,408 23,671 21,714 19,543 16,536 41 1, APIRegular *15,576 * 15,576 *15,576 *15,576 *15,576 *20,609 *20,609 *20,609 19,601 16,629 25,407 23,686 21,749 19,601 16,629 25,407 23,686 21,749 19,601 16,629 NC 44 *20,895 *20,895 *20,895 *20,895 18,161 *26,453 25,510 23,493 21,257 18,161 27,300 25,510 23,493 21,257 18,161 27,300 25,510 23,493 21,257 18,161 41 1, API F l Hole ul *12,973 *12,973 *12,973 *12,973 *12,973 *18,119 *18,119 *18,119 *18,119 17,900 *23,605 *23,605 23,028 19,921 17,900 27,294 25,272 22,028 19,921 17,900 27,294 25,272 22,028 19,921 17,900 Extra Hole *17,738 *17,738 *17,738 *17,738 NC 46 *23,422 *23,422 22,426 20,311 A P I IF 28,021 25,676 Z 4 2 6 20,311 semiIF 28.021 25,676 22,426 20,311 Double Stmadine 28,021 25,676 22,426 20,311 Mod. open H-W *18,019 *18,019 *18,019 *18,019 *23,681 *23,681 23,159 21,051 28,732 26,397 23,159 21.051 28,732 26,397 23.159 21,051 28,732 26,397 23,159 21,051 5 H-W $25,360 *5 2m $25,360 -560 23,988 *31,895 *31.895 29,400 27,167 23,988 35292 32,825 29,400 27,167 23,988 35,292 32,825 29,400 27,167 23,988 -3,004 *23.004 *23,004 %,o04 *23,004 *29,679 *29.679 *29,679 -9,679 26,675 *36,742 35.824 32377 29,966 26,675 38,379 35,824 32,277 29.966 26,675 3&379 35,824 32277 29,966 26,675 38379 35,824 32,277 29,966 26,675 *N508 * 4 *Nm 3m 34,142 30,781 *41,993 40,117 36,501 34,142 30,781 42,719 40.117 36,501 34,142 30,781 42,719 40.117 36,501 34,142 30,781 *31,941 *31.941 "31,941 *31,941 30,495 *39,419 *39,419 36235 33,868 30,495 42,481 39- 36,235 33,868 30,495 42,481 39,866 36,235 33,868 30,495 ("able amtinued m next p g . ae)COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D = A P I / P E T R O RP 7G-ENGL 1996 m 0732290 Ob07707 369 m PRACTICE FOR DRILL %M RECOMMENDED DESIGN OPERATING LIMITS AND 37 Table 14-Recommended Make-up Torque for Rotary ShoulderedDrill Collar Connections (Continued) (See footnotes for useof this table.) SI2 API Full Hole 7 *32,762 *32,762 *32,762 *32,762 *32,762 7V4 *40,998 *40,998 *40,998 *40,998 *m998 71 1, *49,661 *49,661 47,756 45,190 41,533 7% 54,515 51,687 47,756 45,190 41,533 API NC56 7V, . *40,498 *40,498 *40,498 *40,498 712 *49,060 48221 45,680 42,058 FI4 52,115 48,221 45,680 42,058 8 52,115 48,221 45,680 42,058 @la APIRegular 7V2 *46,399 *46,399 *46,399 *46,399 r1 4 *55,627 53,346 50,704 46,936 8 57,393 53,346 50,704 46,936 SV4 57,393 53,346 50,704 46,936 6Vg H-W 71 1, *59 a0 *46,509 *46,509 *46,509 7% *55,708 *55,708 53,629 49,855 8 60,321 56,273 53,629 49,855 811. 60,321 56,273 53,629 49,855 API NC61 8 *55,131 *55,131 *55,131 *55,131 8V4 65,438 *65,438 *65,438 61,624 812 72,670 68,398 65,607 61,624 831~ 72,670 68,398 65,607 61,624 9 72,670 68,398 65,607 61,624 51, API IF 8 *56,641 *56,641 *56,641 *56,641 *56,641 811, *67,133 *67,133 *67,133 63,381 59,027 81 1, 74.626 70,277 67,436 63,381 59,027 83/4 74,626 70,277 67,436 63,381 59,027 9 74,626 70,277 67,436 63,381 59,027 9V4 74,626 70,277 67,436 63,381 59,027 6518 API Full Hole 81/, *67,789 *67,789 *67,789 *67,789 *67,789 67,184 81 3, v9544 *79,544 *79J44 76,706 72,102 67,184 9 88,582 83,992 80,991 76,706 72,102 67,184 9V4 88,582 83,992 80,991 76,706 72,102 67,184 9V2 88,582 83,992 80,991 76,706 72,102 67,184 API NC70 9 *75,781 V5,781 *75,781 *75,781 *75,781 *75,781 9V4 *88,802 *88,802 *88,802 *88,802 *88,802 *88,802 9V2 *102,354 *102,354 * l a 3 5 4 101,107 %J14 90,984 9314 113,710 108,841 105,657 101,107 %,214 90,984 10 113,710 108,841 105,657 101,107 %514 90,984 lOV, 113,710 108,841 105,657 101,107 96,214 90,984 API NC77 10 *108,194 *108,194 *108,194 *108,194 *108,194 *108,194 lOV, *124.051 *124,051 *124,051 *124,051 *124,051 *124,051 lOV, *140,491 *140,491 *140,491 140,488 135,119 129,375 lov4 154,297 148,%5 145,476 140,488 135,119 129,375 11 154,297 148,965 145,476 140,488 135,119 129,375 7 H-9CP 8 *53,454 *53,454 *53,454 *53,454 *53,454 *53,454 8V4 *63,738 *63,738 *63,738 *63,738 60,971 56,382 SV, *74,478 72,066 69,265 65,267 60,971 56,382 7V8 APIRegular 81, *60,402 *60,402 *60,402 *60,402 *60,402 *60,402 8 14 3. V2,169 *72,169 *72,169 *72169 V2.169 *72,169 (Table continued on next page.)COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD-API/PETRO RP 7G-ENGL L998 m 0732290 Ob09708 2T5 m 38 API REC~MMENOED PRACTICE 7 6 9V4 96,301 91,633 88,580 84,221 7.3 956 74.529 9V2 96,301 91,633 88,580 84221 79,536 74,529 H-W 9 13,01713,017 307 7,1 *73,017 13,017 u307 7.1 91 14 *86,006 *86,006 *86,006 *86,006 *86,006 91 2 *86006 *W,= *99,508 *99,508 $99,508 *5508 %,285 8VU 10 *109,345 *109,345 *109,345 *109,345 $109,345 *109,345 11, 01 *125,263 *125,263 *125,263 *125,263 *125,263 1 5 0 4 2.3 lO1lZ *141,767 *141,767 141,134 136,146 130,777 125,034 H-W 11, 01 *113,482*113,482 *113,482 *113,482 *113,482 *113,482 1ov2 *130,063*130,063 *130,063 *130,063 *130,063 *130,063 7 H-W 8V4 *68,061 *68,061 67,257 62,845 58,131 ( tlow torqueh 9 wh i ) 74,235 71,361 67,257 62,845 58,131 7V8 M I Resular 9114 *73,099 *73,099 *73,099 $73,099 ( tlow toquet œ wh i ä) 92 1 *86,463 *86,463 82,457 77339 9% 91,789 87,292 82,457 77339 10 91,789 87,292 82,457 77,289 H-W 914 91,667 *91,667 *91,667 *91,667 *91,667 ( tlow toque face) wh i 10 *106,260 *l062a * l m 104,171 98,804 11, 01 117,112 113,851 109,188 104,171 98,804 1ov2 117,112 113,851 1 9 1 8 0.8 104,171 98,804 lW14 *112,883 * 1 , 8 *112,883 *112,883 1283 ( tlow toque faœ) wh i 11 *130,672 *130,672 *130,672 *130,672 1111, 147,616 1 2 4 0 136,846 130,871 4,3 H-W 1W14 *%%o *%%o *%%o *92,%o ( tlow torquef œ wh i a) 11 *110,781 *110,781 *110,781 *110,781 1111, *129,203 *129,203 *129,203 *129,203COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STDmAPIIPETRORP 7G-ENGL L998 0732290 Ob09709 L31 PRACTICE FOR DRILL S E DESIGN OPERATING LIMITS RECOMMENDED TM AND 39 1 1.0. 3 4 3.5 3.0 2.5 2.0 1.5 3.5 30 . 2.5 2.0 1.5 O U T S I D E E R TO OBTAIN BENDING STRENGTH RAT10,MEASURE W . 8, I.D. OF DRILL COLLAR AT POINTS SHOWN IN ABOVE ILLUSTRATION - 3.5 30 . 2.5 2.0 1.5 3.5 3.0 2.5 2.0 15 . BENDING STRENGTH RATIO BENDING STRENGTH RATIO Figure 26-Drill Collar Bending Strength Ratios, 1V2-and 13/,-lnch IDCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • 40 API RECOMMENDED PRACTlCE 7 6 2 . Ia TO OBTAINBENDING STRENGTH RATI0,YEASURE QD. 8 1.0.OF DRILLCOLLAR AT POINTS SHOWN IN ABOVE ILLUSTRATION 3.5 30 . 2.5 2.0 1.5 3.5 3.0 2.5 2.0 1.s BENDING STRENGTH RATIO BENOW STRENGTH RATIO Figure 27-Drill Collar Bending Strength Ratios,2- and 2V.,-lnch IDCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP ?G-ENGL LqsA E O732270 06077LL 8 7 T E PRACTICE FOR DRIU-M RECOMMENDED DESIGN OPERATING LIMITS AND 41 TO OBTAIN BENDING STRENGTH RATI0,MEASURE QD. B 1.0.OF DRILL COLLAR AT POINTS SHOWN IN ABOVE ILLUSTRATION 3.5 3.0 2.5 2.0 I.S 3.5 3.0 2.5 2.0 1.5 BENDING STRENGTH STRENGTH BENDING RATIO RATIO Figure 28-Drill Collar Bending Strength Ratios, 2V2-lnch IDCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • ~~ ~ STD.API/PETRO RP 7G-ENGL 3998 0732290 Ob09732 72b 42 API RECOMMENDEDPRACTlCE 7 6 13 2 8 1D 16 2161 o. 35 30 2.5 2.0 1.5 3.5 3.0 2.0 2.5 1.5 O U T S I D E D I A M E T E R I TO OBTAINBENDING STRENGTH RATI0,MEASURE QD. 8 1.0.OF DRILL COLLAR I:. AT P W T S SHOWN IN ABOVE ILLUSTRATION - 3.5 30 . 2.5 2.0 1.5 3.5 30 . 2.5 2.0 1.5 BENDING STRENGTH RATIO BENblffi STRENGTH RATIO Figure 2 W r i l l Collar Bending StrengthRatios, 213/l,-lnch IDCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL L998 m 0732290 Ob09733 662 H REWMMENDED PRACTICE F R D R U STEM DESIGN O AND OPERATING LIMITS 43 - 3 I.D. 3 1.D. 35 . 3.0 2.5 2.0 1.5 3.5 3.0 2.5 2.0 1.5 Figure 3(+l3r¡lI Collar Bending Strength Ratios, 3-Inch IDCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • ~ ~~ ~~~ ~ STD.API/PETRO RP 7G-ENGL 1998 m 0732290 06097L4 5T9 m 44 API RECOMMENDED W C E 76 P TO OBTAIN BENDING STRENGTH RAT10,MEAWRE QD. B 1.0. OF DRILL COLLAR AT POINTS SHOWN IN ABOVE ILLUSTRATION 1 35 . 3.0 2.5 2.0 1.5 3.5 3.0 2.5 2.0 I5 BENDING STRENGTHBENDING RATIO STRENGTH RATIO Figure 3 1 4 r i l l Collar Bending Strength Ratios, 3V4-lnchIDCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S TD.API/PETRO RP 7G-ENGL L998 m 0 7 3 2 2 9 0 O b 0 9 7 3 5 Y35 RECOMMENDEDPRACTICE FOR DRILL %M DESIGNAND OPERATING LIMITS TOOBTAINBENDING STRENGfH RATI0,MEASURE QD. B 1.0. OF DRILL COLLAR AT POINTS SHOWN IN ABOVE ILLUSTRATION 3.5 3.0 2.5 2.0 1.5 3.5 30 2.5 2.0 1.3 BENDING STRENGTH BENDING RATIO STRENGTH RATIO Figure 32-Drill Collar Bending Strength Ratios, 3l/,-lnch IDCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO P R 7G-ENGL L998 m 0732290 ObO973b 3 7 1 m 46 API RECOMMENDED PRACTlCE 7G 6.42 For a giventensile load, the stress level is less in the 6.5.1 Remachining hexagonal section. Before attemptingto remachine a kelly, it should be fully inspected for fatigue cracks and also dimensionally checked 6.4.3 Lhe to the lower stress level, the endurance limit of to assure that it is suitable for remilling. The strength of a the hexagonal drive section is greater in terms of cycles to remachined kelly should compared with strength of the be the failure for a given bending load. drill pipe with which kelly is to be used. (SeeTable 17 for the drive section dimensions and t e g h . srnts) 6.4.4 Surface decarburization (decarb) is inherent in theas forged square kelly which further reduces endurance limit the in terms of cyclesto failurefor a given bending load. Hexago- 6.5.2 Reversing Ends nal kellys and fully machined squares have machined sur- Usually ends the must both of kelly be buttwelded faces andare generally free of decarb in the drive section. (stubbed) for this to be possible as the original is too short top and the old lower end smaU in diameter for the is too comes- 6.4.5 It is impractical to remove the decarb from the com- tions to be reversed. The welds should made in the upset be plete drive section of the fOrgea square kelly; however, the portions on each end to insure the tensile integrity and fatigue decarb should be removedfromthe corners inthefillet resistance capabilities of the sections. Proper heating and between the drivesection and the upset aid in the preven- to welding p m x x h m s must be used to prevent cracking and to tion of fatigue cracks in this area. Machining ofsquare kellys recondition the sections where welding been performed. has from round bars could eliminate undesirable condition. this 6.6 The internal pressure at minimum yield for the drive 6.4.6 The life of the drive section is directly relatedto the section may be calculated from EquationA.9. kelly fit with the kelly drive.square drive section normally A will tolerate agreater clearance with acceptable life than will 7 Design Calculations a hexagonal section. A diligent effort by the rig personnel to 7.1DESIGN PARAMETERS maintain minimum clearance between the kelly drive section and the bushing will minimize this consideration in kelly It is intended to outline a step-by-step procedure to ensure selection. New roller bushing assemblies working on new complete consideration of factors, and to simpw calcula- kellys will develop wear pattems ta are essentially flat in ht tions. Derivaton o formulas may be reviewed in Appendix f of shape on the driving edge the kelly. Wearpattems begin as A. The following design criteria must be establish& point contacts of zero width near the comer. Thepattern wid- a Anticipated total depth with this string. ensasthekellyandbushingbegintowearuntilamaximum b. Hole size. wear pattern achieved. The wear will be the least when is rate c. Expected mud weight. the maximumwear pattern width is achieved. Figure 33 illus- d Desired Factor of Safety in tension andor Margin of Over tratesthemaximumwidthflatwearpatternthatcouldbe Pull. expected on the kelly drive flats if the new assembly has e. Desired Factor of Safety in collapse. clearancesas shown in Table 16. information in Table16 The f. Length of drill collars, OD, ID, and weight foot. per and Figures and 34 may be used to evaluate the clearances 33 g. Desired drill pipe s e ,and inspection class. zs i between kelly and bushing. This evaluation should be made assoonasawearpatternbecomesapparentafteranew 7.2SPECIALDESIGNPARAMETERS assembly is put into service. If the actual wall thickness been determined by has inspec- Example: At the of evaluation, the wear time pattern width tion to exceed that in API tables, higher tensile,ope and ca s , l I f r a 51/4-inch hexagonal kelly 1.00 inch. o is internalpressure values maybe used for stem design. drill T i could meau one of the following conditions exist: hs two 7.3 SUPPLEMENTAL DRILL STEM MEMBERS a If the contact angle is less than 8 d e 37 minutes, the m Machining of the connections t A P I specilìcations and the o original clearances were acceptable. The wear pattern is not properheat~tofthematerialshallbe&neon~supple fully developed mental dxill stem members, such as subs, stabilizers, t o s e c ol, t . b. Ifthecontactangleisgreaterthan8degmes37minutes, 7.4TENSIONLOADING the wear pattern is fully developed. The clearance is greater than is recommeadedand should be corrected. The design of the drill string for statictension loads requim sufficient strength in thetopmost joint of each size, 6.5 Techniques for extending life of kellys include rema- wei@t, grade, and classification of drill pipe t support the o chining drive sections to a d size and reversingends. er submerged weight of all the drill pipe plus the submergedCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL 199B D 0732290 Ob09717 208 D RECOMMENDED PRACTICE FOR DRU STEM DESIGN AND OPERATING LIMITS 47 Table 1-rength of Kellys (2) (1) 1) (1 (10) (6) 0) (9) (8) Internal pressure at .. yield in Lowerpinconnection M Yield Tensile Torsional Yield Bending yield Recom- Kellysi Kelly mn&-l Ipwerpin Drive h Through Drive e pin r Drive andm Bore Size and OD casing OD C~nnection~ Section Connection Section Drive Section Section in. i. n Style i. n i. n lb lb &lb fi-lb fi-lb Psi 2 1 square 1, 11 1, 416,000 440 440 , 9,650 12,300 29.800 13,000 3s q- 131~ 535,000 582,500 14,450 19.500 22,300 25,500 312 21, 724,000 725,200 z700 28,300 34200 2230 4% square 2131,~ 1,054,000 1,047,000 39,350 49,100 19,500 60,300 4l14 square 2134, 1.375m 1,047,000 55,810 49,100 19,500 60.300 5% square 3l1, 1,fjW000 1,703,400 72,950 99,400 117,000 260 00 , 3 Hex 1Il2 356,000 540,500 8,300 20,400 26,700 20,000 3V2Hex 174 495,000 710,000 13,400 31,400 25,500 31,200 414 Hex 2v4 724,000 1.046600 22,700 56,600 25,000 56,000 5V, Hex 3 %a000 1,507,600 35,450 101,900 20,600 103,000 5V, Hex 3, V 1,162,000 1,397,100 46,750 95,500 20,600 99,300 6 Hex 3Il2 1,463,000 1,935,500 66,350 149,800 18,200 152,500 I A U values havea safety factor of 1.O and are based on 1 10,000 minimum tensile yield (quenched and m ee ) for connections and 90,000 psi minimum psi t prd e than those so nSbear tensile yield(normalized and tempemi) for the drive section. Fully quenched andtempered drive sections will have higher values hw. strength is based on 57.7 percent o the minimum tensile yieldstrength. f zclearance between protects rubber on kelly saver sub andcasing inside diameter should a s be checked. lo Tensile area calculated a mot of thread V4 inch h m pin shoulder. tCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • ~ STD.API/PETRO RP 7G-ENGL L998 m 0732290 O b 0 9 7 3 8 L44 m 48 PMCE API REC~MMENDED 76 5 Il4 6 Small contact angle pattern Flat surface no curvature luare 3xagonal I I I l I I I I O 25 SO .75 1.00 1.25 1.50 20 0 2.25 Note:DriveEd~winhaveawideflatpatternwithsmall contact angle. Figure Mw Kelly-New Drive Assembly e Figure M e w Kelly-New Drive Assembly Table 16"contact Angle Between Kelly and Bushingfor Development o Maximumwidth Wear Pattern f - ~~ ~~ ~ 21, - - - .lo7 165Y 3 5O41 .O15 .o60 5"3Y 11% .o15 .1w 15"s 3lI2 .O15 5% .6 o0 SO14 1092 .O15 .w 1 1451 4V4 .o15 448 .o60 9-34 .o15 1336 4O4S .123 5l1, 4"W .m 89T 12"16 .123 .O15 4"17 451 6 .O15 .m 8"4 - - - -COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D - A P I I P E T R O RP 7G-ENGL 1994 0332290 0609339 080 PRACTICE FOR DRILL RECQMMENDED STEM DESIGN OPERATING LIMITS AND 49 Table 1"-Strength of Remachined Kellysl (5) (1) (4) (2) (3) o (8) (9) (10) original R an e cie mh d LowerPincoMection Tensile Xeld Torsional Xeld Xeld in Bending Kelly size Kelly Kellysize LcnverPin Drive Lowerpin Drive TImughDrive and m and I)rpe BOß3 Size and OD conllection~ section connection section section i. n i. n i. n Style m. l. b lb. Wb fvlb fvlb 411,sq~ 4 square 218 NC50 @/S 1,344m 834,400 55,500 36,200 47,800 (4%W 411, square 4 s ur q ae 218 NC46 6V4 1,011,600 834,400 38,300 36,200 47,800 (4 m 511, s u r q ae 5s ur q ae 33/, 511, IF 7% 1,924,300 1317,600 92.700 65,000 90200 511, s u r q ae 5 square 511, 3314 FH 1,217,600 7 1,356.800 58,900 90,200 65,000 Hex 6145V4NC46 314 427/32Hex 809,800 30,600 1,077,100 0 74,000 (4 mex 5 51, Hex 3v4 NC46 6Il4 809,800 1,196,800 30.600 78,500 83,300 (4 m Hex 5V, 5 Hex 31, NC50 @/S 990 990 , 1,077,600 4Q800 71,100 78,400 (4% W 6 Hex SI, Hex 4 119,900 1,300 109,100 5 FH 511, 1,443,400 7 1,189,Mo Hex 6 SI, Hex 4lIa 5V2IF 7% 1,371,500 1,669,200 80.400 116,XlO 103.800 Uvalues have a safety factor of 1.O and a . on 1 l0,OOO psi minimum tensile yield(quenched and tempered) for cOnnectiollS and O psi minimum A xbased 9O 0 ,O tensile yield(normaked and tm e ) for the driw section.Fully quenched and tempeml drive sections will have highex values thau those &m. Shear strength is based on 57.7 pacent of the minimumtensile yield seength. Tensile area calculated at mot of thread 1, inch h m pin s k u l k . Note: Kelly bushings 1111:normally available for kellys in above tbe al. weight ofthe collars, stabilizer, and This load may becal- bit. areas, wall thickness and yield strengths. The yield strength culated as shown in EQuation l. The bit and stabilizer weights as defìned in A P I speciiications is not the specific point at are either neglected or included withdrill collar weight. the which permanent deformation of the material begins, but the stress at which a certain total deformation has OcCuITed. This P = [<L+X W+)+ (L, W,)]X Kb (1) deformation includesall of the elastic deformation well as as some plastic @ermanent) deformation. the pipe is loaded to If where the extent shown the tables is likely t a some permanent in it ht P = submerged load hanging below this section of drill stretch wl occur and dirsculty be experienced inkeep il may pipe, lb., ing the pipe straight. prevent this condition a design factor To L+ = lengthof drillpipe,R, of approximately 90 percent of the tabulated tension value L, = length of drill collars,k, is a h m the table sometimes used, however,better practice is W = weight per foot of , drill pipe assembly in air, to request a specifìc factor for the particular grade of pipe W, = weight per foot of drill collars inair, involved from drill pipe supplier. the Kb = buoyancy factor-see Table 11. Any body floating immersed in a liquid is acted on by a or P, = P, x 0.9 (2) buoyant force equal the weight of liquid displaced. to the This force tends to reduce the effective weight of the drill string where and can become of appreciable magnitude in caseof the the P, = maximum allowable design load tension, lb., in heaviermuds. For example,fromTable 11, a one-pound P, = thmretical tension load m table, lb., h weight submergedin a 14 1bJgal. mud would have an appar- 0.9 = a constant relating proportional limit to yield ent weight of 0.786 lb. strength. Tension load data is given in Tables 2,4, 6, and 8 for the various sizes,grades and inspection classes of drill pipe. The diffenmce between the calculated load and the max- P It is important to note t a the tension strength values ht imum allowable tension load represents the Margin of Oa v on shown inthe tablesare theoretical values based minimum Pull (MOP). COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
    • S T D - A P I I P E T R O R P 7 G - E N G L L778 m 0732270 607720 0 8T2 m 50 API RECWMENDEDPRACTlCE 76 MOP=P,-P (3) condition usually occurs during the stem testing and may drill result in collapse of the drill pipe. The differential pssure The same values expressed as a ratio may be c l e the ald requiredto produce collapsehas been calculated for various Safety Factor (SF). sizes, grades, and inspection classes of drill pipe andappears in Tables 3, 5, 7, and 9. Thetabulatedvaluesshould be divided by a suitable factor of safety to establish the allow- SF= pa - able collapse pressure. P The selection of the pmper safety factor and/or margin of PP - = P,, over pullis of critical importance and should approached be SF with caution. Failureto provide an adequate safety factorcan result in loss or damage to the drill pipe while an overly con- where servative choice will result in an unnecessarily heavy and PP = theoretical collapse pressure from tables, psi, mure expensive drill string. The designer should consider the SF = safetyfactor, overall drilling conditions the area, particularly hole drag in P, = allowable collapse pressure, psi. and the likelihood of becoming The designer must stuck also When the fluid levels insideand outside the drill pipe are consider thedegree of risk which is acceptable for the partic- equal and provided the density of thedrilling fluid is constant, ular well for which the drill string is being designed. Fre- the collapsepressure is zero a any depth, i.e., thereis no dif- t quently, the safety factoralso includes an allowance for slip ferential pressure.If, however, there should no fluid inside be crushing and for the dynamic loading, which results from the pipe theactual collapse pressure may be calculated by the accelefations and deceledons during hoisting. following equation: Slip crushingis not a problem if slips and master bushings are maintained. Inspection class also grades the pipe with regard to slip crushing. L W, P, = - N o d y the designer w l desire to determine the maxi- l i 19.251 mum length of a spedìc se grade and inspection class of z, i drill pipe which can be used to drill a certain well. By com- or bining Equation 1 and either Equation 2 or 3, the following equationsresult: P, = L W , - 144 where P, = netcollapsepressure,psi, L = the deptha which P, at,R, t cs W, = weight of drilling fluid, lb/gal, W, = weight of drillingfluid lb/m ft. If there is fluid hide the drill pipe the fluid levelnot but is as high insideas outside or if the fluid insideis not the same Ifthestringistobeataperedstring,i.e.,toco~stofmure weight as the fluid outside, the following equation may be than one size, grade. or inspection class ofdrill pipe, the pipe used: having the lowest load capacity shouldbe placed just above thedrillcohandthemaximumlengthiscalculatedas L W,-(L-Y)Wi pipe shown previously. The next stronger is placed nextin the P, = stcingandtheWLterminEquation5or6isrepMbya 19.25 1 t r representingthe weight in air of the drill collars plus the em or d d l pipe assemblyin the lower string. The maximumlength An of the next strongerpipe maythen be calculated. example L W , -(L- Y)W, calculation using the above formulas included in7 8 is .. P, = 144 7.5 COLLAPSE DUE TO EXTERNAL FLUID where PRESSURE Y = depthtofluidinsidedrillpipe,&, Thedrillpipemayatcertaintimesbesubjectedtoanexter- W, = weight of drilling fluid insidepipe, lb/gal, nal pressure which is higher than the internal pressure. This W; = weight of drilling fluid inside pipe, lWcu ft.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL L998 m 0732290 0607723 739 m RECOMMENDED PRACTICE FOR DRU STEM DESIGNAND OPERATING LIMITS 51 7.6 INTERNALPRESSURE where Occasionally the drillpipe may a s be subjected to a net lo L, = length of drill collars, feet, internal pressure. Tables 3,5,7, and 9 contain calculated val-Bit, = maximum weight on bit, lb, ues of the differential internalpressure required to yield the a = hole angle from vertical,degrees, 3 drill pipe. Division by appropriate safety factor will result an NP = neutral point design factor determines neutral in an allowable net internalpressure. point position e.g.,.85 means the neutral point will be 85 percent of the drill collar string length 7.7 TORSIONALSTRENGTH measured from the bottom (.85 assumed for this The torsional strength drill pipe becomes critical when of calculation), drilling deviated holes, deep holes, reaming, or when the pipe K = buOyatlCj factOr, See Table 1 1, b is stuck This is discussed under Sections 8 and 12. calcu- W, = weight per foot of collars in air, lb, drill lated values of sizes, tonional strength for various grades, and 40,000 inspection classes of drill pipe arep e in Tables 2,4,6, vd d i L, = .998 x .85 x .847 x 90 and 8. The basis for these calculationsshown in Appendix is A. The actual torque applied to the pipe during drillingdif- is = 618 feet, closest length based 30 foot collars, on ficult to measure, but may be approximated by the following = 630 feet or 21 drill collars. equation: g. Drill string size: weight andg d 4 /16.60 lb/ft x r en x a i.2 1 Grade E75, with 4V2 in., NC46 tool joints, 614 in. OD x 3V4 i.ID, Inspection Class 2. n where From Equation 5: T = torque deliveredto drill pipe, fi-lbs, HP = horse power used produce rotation pipe, to of (P,, -9) - MOP W , X L, X RPM = revolutions per minute. = " wdpl x K b Note:Thetorqueappliedtothedrillstringshouldnotexceedtheactualtool joint make-up torque. The recommnded tool joint make-up toque is shown - - (225,771 X .9) - 50,000 90 X 630 " i Table 10. n 18.37 x .847 18.37 7.8 EXAMPLE CALCULATION OF ATYPICAL = 9846 - 3087 = 6759 feet DRILL STRING DESIGN-BASED ON MARGIN OF OVERPULL It is apparent that drill pipe of a higher strength will be Design parameters as follows: are required to reach 12,700 feet. Add4V2in. x 16.60 lb/ft Grade X-95, with 4V2 in. X.H.tool joints, 64 in. OD x 3 in. I D a Depth-12,700 feet. . (18.88 lb/ft) Inspect~on Class Premium. b. Hole sjze-7V8 inches. Air weight of Number 1 drill pipe anddrill collars: C. Mud Weight-10 lb/& d. Margin of overpull (MOPj50,OOO lb. (assumed for this Total weight = (L+l x W,,) + (Lcx W,) calculation). = (6759 x 18.37) + (630 x 9 ) 0 e. Desired safety factor in collapse-l/, (assumed for this calculation). = 124,163 + 56,700 = 180,863 lb. f. Drillcollar data: 1. Length430 feet. From Quation 5: 2. OD-6V4 inches. 3. &2V4 inches. 4. Weight per foot-90 lb. If the length drill collars is not known, the following of for- mula may be used: - (329,542 x .9) - 50,000 180,863 " 18.88 x 18.88 .M7 Bit, L, = = 15,420 - 9580 = 5840 feet CosaxNPx k b X W ,COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • 52 API RECOMMENDED PRACTICE 7 6 This is more drill pipe than required to reach 12,700 feet, ing make-up and break-outoperations to preVent bending O f so final drill string will consist of the following: the pipe. joint may be posi- There is a maximum height that the tool tioned above therotary slips and thepipe to resist bending, whilethe maximum recommendedmake-up or " o u t Item torque is applied to the tool joint Many factors govern height limitation.Severalof these this Drillcollars which shouldbe taken i t most serious considerationae no r: SV4"O.D. x 2V4"ID. 630 56,700 48,025 No. 1 Drill Pipe a The angle of separation between the make-up and break- 44" x 16.60 lb, out tongs, illustrated Case I andCase II, Figure 35. Case I by GradeE75,Qass2 105,166 124,163 6759 indicates tongs a 90 degrees and Case II indicates tongs a t t 180 degrees. No. 2 Drill Pipe 44" x 16.60 lb, b. The minimum yield strength the pipe. of Grade x-95, c. The length the tong handle. of Remiumclass100,272 5311 84,930 d The maximumrecommended make-up torque. 12.700 238,121 281,135 .O53 Y,LT (VC) Torsional Yield N," x 16.60lb x Grade E75 x Inspection of H,. = (C= I) T Class 2 = 20,902 fi-lb. Collapse Pressure of 4 ; x 16.60 lb x Grade E75 x Inspec- V tion Class2 = 5951 psi. Collapse pressure of 4V21) x 16.60 lb x Grade X-95 x Pre- miumInspection Class = 8868 psi. where From Equation 8: H = height of tool joint shoulder , . above slips, R, Y = minimum tensile yieldstress of pipe, psi, , preSsureatbottomofdrillpipe:P,= -LW, L, = tong ann length, R, 19.251 P = line pull(load), lbs, L = 12,070 feet, W,= 10 lb/@, T = makeup torque applied to tool joint (PA), fi-lb, VC = section modulus of p i p - i n 3 . (seeTable 18). Constants 0.053 and 0.038 include a factor of0.9 to reduce Y to proportional limit (see7.3). , Therefore,thisdrillpipehasalowercollapsepressurethau Sample calculation: may be encounted in drilling to 12,700 feet precautions Assume: 4V2-in., 16.60 lb/% Grade E drill pipe, with should be taken to prevent damage to the drill pipe whenm- 4V2-in.X.H. 6/4-in. OD,3V4-in. I tool joints. D ning the string dry below 10,183 feet This is determinedby Tong arm 31/2-R solving Equation 8 for maximum length of drill pipe, and Tongs at 90(Case I.) dividing bythe safety factor i collapse of 1V 8 : n Using Equation 13: P,x 19.251 L= W, + 1.125 Y, = 75,000 psi (for Grade E), - 5951 x 19.251 10 VC = 4.27 i n 3 (Table M), = 11,456 + 1.125 = 10,183 feet L, = 3.5 R, 7.9 DRILL PIPE BENDING RESULTING FROM T = 16,997 &lb (from Table lo), TONGING OPERATIONS It is generally known that the tool joint a length of drill on pipe should be kept as close to the rotary slips as possible dur-COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STDmAPI/PETRO RP 7G-ENGL L998 m 0732290 Ob09723 501 m RECOMMENDEDPRACTICE FOR DRILL STEM DESIGNAND OPERATING LIMITS 53 Table 18-Section Modulus Values 8 Limitations Relatedto Hole Deviation 8.1 FATIGUE DAMAGE Most drill pipe failws are a result of fatigue (see 11.2). Drill pipe will suffer fatigue whenit is rotated in a section of hole in which thereis a change of hole angle n o direction, adr 24 3 06 .6 commonly called a dogleg. The amount of fatigue damage 66 .5 08 .7 on which results depends the following: 68 .5 11 .2 10.40 1. 0 6 8.1.1 Tensile Load in the Pipe at the Dogleg 95 .0 1. % 1.0 33 25 .7 Following isan example calculation: 1.0 55 29 .2 a Data: 1.5 18 27 .0 1. 4V2-inch, 16.60 b Grade E, Rauge 2 drill pipe (actual l& 1.0 40 32 .2 weight in air including tool joints, 17.8 1b/ft) ?/&ch OD, 1.0 57 35 .8 2/4-inch ID drill ~ 0 l ( t l a u Weight in air 147 1Wft). hc a 1.5 37 35 .9 2. 15 lwgal(ll2.21 lb/cu. f)mud. t 1.0 66 42 .7 3. (buoyancy factot = 0.771) 20.00 51 .7 4. Dogleg d p h 3,000 ft. et. 2.2 28 5.68 24.66 60 .3 5. Anticipated t t l depth: 11,600f. oa t 25.50 6.19 6. Drill collar length: 600 ft. 1.5 62 48 .6 7. Drill pipe lengtha total depth:1 1,000 ft. t 1.0 95 57 .1 8. Length of drill collar string, whose buoyant weight is 2.0 56 72 .5 in excess of the weight bit 100 ft. on 1.0 92 61 .1 b. Solution: 21.90 70 .3 Tensile loadin the pipea the dogleg: t 24.70 78 .4 2.0 52 97 .9 [(11,000-3,OOO) 17.8+ 1 0 0 1471 0.771= 121,1241b ~ Figure &Maximum Height of Tool Joint Above Slips to Prevent Bending During TongingCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD=API/PETRO P R 7G-ENGL L398 m 0732290 Ob09724 448 m 54 API REC~MMENDED -CE 76 8.1.2 The Severi¡ o the D g g f ole where D = drillpipeOD,inches, The number of cycles experiencedin the dogleg, well as as the mechanical dimensions and properties of the pipe itself. d = drill pipe ID, inches. Because tension in the pipe critical, a shallow dogleg is in a The maximum permissible bendingstress, S,,is calculated deep hole often becomes a s o m of difficulty. Rotating off from the buoyant tensile stress, S, @si). in the dogleg with bottom is not a good practice sinœ additional tensile load Equations 19 and 20 below. S,is calculated with Equation 18: results from the suspended drill collars. Lubinski and Nicholson2 have published methods of calculating forceson tool joints and conditions necessary for fatigue damage to occur.Referring to Figures 36 and 37, note that it is necessary to remainto the left of fatigue curves reduce fatigue dam- to where age. Programs to plan and drill wells to minimize fatigue A = cross sectionalarea of drillpipe body, square inches. have been reportedby Schenck3 and Wilson4. Such programs are necessary to reduce fatigue damage. For Grade l 4 E The curves on figures 36,37, and 38 (also Figures 41,42, and 43) are for Range2 drill pipe, i.e. for joint lengths of 30 feet. This length has an effect on the m e s . Information is available on fatigue of Range 3 (45 feet) drill p i p e . 1 4 The curves on Figures 36,37, and 38 are independent of tool joint OD, however, the portion of the curve for which there is pipe Equation 19 holds true for values S, up to 67,000 psi. of to-hole contact between tool joints (dashed lines on Figures F I Grade S-1351~ O 36 and 38) becomes longer when tool joint OD becomes smaller, and convenely. The advent of electronic pocket to use the following calculatm makes it easy in equations instead of the curvesFigures Ob ( = 2000 " 1 145qbk) 36 and 3 7 . ~ ~ Equation 20 holds true values of up 133,400 psi. for to The following equation be used instead of Figure 38: may 108000 F c = - - XL T in which F is the lateral forceon tool joint (1000,2000, or 3000 pounds in Figure 38), and the meaningthe other sym- of maximum permissible dogleg severity (hole cur- bols is the same as prwiously. -, ) degrees per 100 feet, Youngs modulus,psi, 8.2 REMEDIAL ACTION TO REDUCE FATIGUE 30 x 106 psi, for steel, 10.5 x 106 psi, for aluminum, If doglegs ofsuBident magnitude are present or suspected, itisg~practicetostringreamthedogleg~Thisreduces drill pipe OD, inches, the severity of the hole angle change.With reference to Fig- half the distance between tool joints, inches, ure40,thefatiguelifeofdrillpipewillbedecreasedconsid- 180 inches, for Range 2. erably whenit is used in a corrosive drilling fluid. For many Note.Equation15doesmtholdtr~forRange3." water-base drilling fluids, the fatigue life of steel stems drill may be incmsed by maintaining pH of 9.5 or higher. Refer a T = buoyant weight (including tool joints) suspended t 10.1.4 for description of a corrosion monitoring system. o below the dogleg, pounds, S e v d methods are available for monitoring and control- S, = maximum permissible bendingstress,p i s, ling the cormsivity of drilling fluids. The most commonly Z = drillpipemomentofinertiawithrespecttoits used monitoring technique is the use of a comsion ring diamekr, i n 4 , calculated by Equation 17. insertedinthedrillstemForadescriptionofthistechnique see N I Recommended Plactice 13B-1, Recommended Pmc- tice StMdard Pmeabre for Fieid Testing Water-BasedDriU- ing F l u a .COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • RECOMMENDEDPRACTICE FOR DRlU STEM DESIGN OPERATING LIMITS AND 55 Dogleg Severity-Degrees Per100 Feet O 1 2 3 4 5 6 Note: Dashed curve corresponds to condition when drill pipe contacts the hole betweentool joints, andthen the permissible dogleg severity is greater than indicated. Figure 36-Dogleg Severity Limits for Fatigue of Grade E75 Drill PipeCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD-API/PETRO P R 7G-ENGL L998 m 0732290 Ob09726 210 m 56 API RECWMENMD PRACTlCE 7 6 Dogleg Severity-DegreesPer 100 Feet O 1 2 3 4 5 6 O I In corrosive environments, reduce dogleg severitya fraction to (0.6 for very severe conditions) of the indicated value. 100 7 0 0 1 joint plus drill pipe all Range 2. 700 I I I I Figure 37"Dogleg Severity Limits for Fatigue of S-135 Drill PipeCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD..LPI/PETRO P R 7G-ENGL L998 m 0 7 3 2 2 9 0 Ob09727 L57 m RECOMMENDED PRACTICE FOR DRILLSlEM DESIGN AND OPERATING LIMITS 57 Dogleg Severity-DegreesPer 100 Feet O 1 2 3 4 5 6 O 100 400 500 600 700 Note: Dashed curves correspond to condition when drill pipe may contact the hole between tool joints, and then the permissible dogleg severity maybe greater than indicated. Figure 38"ateral Force on Tool JointCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • 8.3 ESTIMATION OF CUMULATIVE FATIGUE Percent Fatigue Life DAMAGE Ewended in a 30 Foot lntervd Hansford and Lubinsk.? have developed method for esti- a mating the cumulative fatigue damage to joints of pipe which have been rotated through severe doglegs (seeFigures 39 and 40). Whileinsuf6cientfieldchecksofthe results of this method havebeen made to verify its reliability,it is available as a simple analytic device use as a guide in the identifica- to tion of suspect joints. A corzection formula to use for other penetration rates and rotary speeds is as follows: 9 Life Expended= % Life Expendedfrom 6 Figure39~40x ActualRPM x 10 ft/hr 100RPM Actualft/hr 8.4 IDENTIFICATION OF FATIGUED JOINTS As mentioned, inmf5cient data is available to verify the For: results of the method explained in8.3. Howeveryit is the only Drill pipe, 31/.,1 and 5 Grade E 4 ; 7 steel; rotary speed, 100 rpm; drilling method presently available for estimating cumulative fatigue rate, 10 feethour. damage and should be used if it is possible to identi@ and Figure 39-Fatigue Damage in Gradual Doglegs classify fatigued joints. Thedifkulty lies in identifying and (Noncorrosive Environment) recording each separate joint fatigue history. Joints which have been calculated to have more than 100 percent of their faligue life expended should be ca~fully if examined and, not downgraded or abandoned, watched as closely as possible. Percent FatigueLife Expended in a30 Foot Interval Such consideration should be finally governed by experience factors until such time as the analytical method for fatigue predictiongains more reliability. 8.5 WEAR OFTOOL JOINTS AND DRILL PIPE When drill pipe in a dogleg in tension it is is pulled to the inside of the bend with substantial force. The force will lateral increase the wear of pipe and tool joints. When abrasion the is aproblemitisdesirabletolimittheamountoflateralforceto less than about 2000 lb on the tool joints by controlling the rate of change of hole angle. Values either smaller or greater than 2000 lb might be in oder, depending on formation a thet dogleg. F 38 shows curves for 1000,2000, or 3000 lb pi lateral force on the tool joints; points to the left of these curves whave less lateral force, and points to the right more l i lateral force on the tool joints. F i p s 41, 42, 43, and 44, developed by Lubbki, show l t r l force curves for both aea tool j i t and drill pipe for three popular pipe sizes. The first ons threefi~arefor~pipesizes,Range2.Figure44isfor For: Drill pipe, 3 ; 41h, and 5 Grade E V , 5 - i n ~ 4 lb 19.5 foot, Range 3 drill pipe. steel; rotary speed, 100 r r ; drilling pn tate, 10 feethour. 8.5.1 For conditions represented bypoints located to the i 41, only tool left of Curve No. 1, such as Point A in fp Figure W a t i g u e Damage in GradualDoglegs joints and not pipe between tool joints drill contact the wall of (ln ExtremelyCorrosive Environment) the hole. T i should notbe construed to mean the drill pipe hsCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD=API/PETRO P R 7G-ENGL L998 m 0732290 Ob09729 T2T m PRACTlCE FOR DRILL REC~MMENDED STEM DESIGN OPERATING LIMITS AND 59 body does not wear at as Figure 41 is for a gradual and not 9 Limitations RelatedTo Floating Vessels all, for an abrupt dogleg. In an abrupt dogleg, drill pipe does con- 9.1 All possible steps should be taken to avoid subjecting tc the wallof the hole way between tool joints, at half and the drill pipe to fatigue; i.e., to cyclic stresses dueto rotation of pipe body is subjected to wear. This lasts until the dogleg is the drill string under bending and tension. *o major factors rounded off and becomes gradual. which are spec& to drilling from al a e that contributeto fotr fatigue of drill pipe are as follows: 8.5.2 For conditions represented points by located on Curve No. 1, theoretically the drill pipe contacts the wallof 9.1.1 The rotary table is not c e n t e d at all times exactly the hole with force at the midpoint between tool joints. above the subsea borehole. zero 9.1.2 The derrick is not always vertical but follows the roll 8.5.3 For conditions represented by points located between and pitch motions the floater. of Curve No. and CurveNo. 2, theoretically the drill pipe 1 still 9.2 contacts the wall the hole at midpoint only, but with a force This text pertains to prevention of fatigue due to factor of which is not equal to z r . This force increases from Curve eo b, above. When the derrick is inclined during of the roll a part No. 1 toward CurveNo. 2. Practically, of course, thecontact o pitch motion, the upper extremity of the string is not r drill between the pipe and the wall of the hole be along a drill will vertical while the pipe a some distance drill t below the rotary short length located near the midpoint of the joint. table r vertical. Thus the drill string is bent. As drill e & pipe is much less rigid than the kelly, most of the bending 8.5.4 For conditions represented bypointslocatedtothe occurs in the first length of drill pipe below the kelly. This right of Curve No. 2, theoretically the drill pipecontacts the subject is studied in a paper titled, Z’he Efect OfDrilLing Ves- wallof theholenot at onepoint,butalongan arc with sel Pitch or Roll on Kelly and Drill Pipe Fatigue, by John E. increasing length the right CurveNo. 2. to of Hamford and Arthur Lubinski6 On each of the Figures 41,42,43, and 44,there are in addi- 9.3 Based on the Hamford and Lubinski@ p, a the follow- tion to curves 1 and No. 2, two families of curves: one for No. ing practices mommended to minimize bending and, on on force the force tool joint, and the other for the drill pipe therefore, fatigue of the joint of drill pipe, due to roll first and body. As an example, consider Figure 41; Point B indicates or pitch ofa f l o w . that if the buoyant weight suspended below the dogleg is 9.3.1 Multiplanebushingsshouldnotbe used. Ether a 170,000 lb, and if dogleg severity (hole curvature) is 10.1 gamboled kelly bushing, a one-plane roller bushing or is pref- d e p s per 100 feet, then the forceon tool joint is 6OOO lb, erable. and the force drill pipe body is 3000 lb. on 9.3.2 An extended length kelly should be used to relieve the severe bending of the limber drill pipe through less severe 8.6 HEAT CHECKING OFTOOL JOINTS bending of the rigid kelly extension. This extension may be accomplished by any the following means: of Tool joints which are rotatedunderhighlateralforce against the wall of the hole may be damaged as a result of a For Range 2 drill pipe, use a 54-foot kelly which is ordi- . friction heat checking. The heat generated at the surface of narily used with Range 3 pipe, rather than the usuala f o o t the tool joint friction with the wall of the hole when under kelly. by high radialthrust loads may raise the temperature of the tool b. Use a specially made kelly a least 8 feet longer than the t joint steel above its critical temperatme. Metallurgical exami- standard length. nation of such joints has indicated affected zones with vary- c. Use at least 8 feet of kelly saver subs between the kelly ing hardness as much as 3/16-in.below OD s r c . If the uf e a and drill pipe. radial thrust load is sufficiently high, surface heat checking 9.3.3 If b, above, is notimplemented,avoidrotating off can OCCUT in the presence of drilling mud alternately being bottom with the kelly more half way up for long than periods heatedandquenched as it rotates. This action produces of time if the maximum angular vessel motion moreis than 5 often numerous irregular heat check cracks accompanied by degrees single amplitude. In this text, long periods of time longer axial cracks sometimes extending through the sec- full ae r: tion of the joint and washouts may occur in these splits or a More than30 minutes for large hookloads. windows. (See Lubinski, ‘Maximum Permissible Dog Legs b. More than 2 hours for light hookloads. in Rotary Boreholes,’’ Jouml o Peímleum Technology, f 1961.)’ Maintaining hole angle control that 2000 lb lateral so 9.3.4 If conditions prevent implementing b or c, above, the force is not exceeded wminimize or eliminate heat check- first joint of drill pipe below the kelly should be removed l i ing of tool joints. from the string the first opportunity and discarded. atCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL L998 m 0732290 Ob09730 741 m 60 API RECOMMENDEDPRACTlCE 7 6 Figure 4l"ateral Forces on Tool Joints and Range 2 Drill Pipe 3V2-lnch,13.3 Pounds per Foot, Range 2 Drill Pipe, 43/,-lnch Tool Joints wg Severily ( M e CurVahrre)-Degreeg e Per 1O0 Feet 5 10 15 I I I I I I I I I I I I I I I I Figure 42"ateral Forces on Tool Joints and Range2 Drill Pipe 4V2-lnch, 16.6 Pounds per Foot, Range 2 Drill Pipe, 6V4-lnch Joints ToolCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL 1 9 7 8 m 0732290 Ob09731 bB8 m RECOMMENDED PRACTICE FOR DRILL STEM DESIGNAND OPERATING LIMITS 61 Dogleg Severity (Hole Cunrature~egrees 1 0 0 Feet Per Figure 43"ateral Forces onTool Joints and Range2 Drill Pipe 5-lnch,19.5 Pounds per Foot, Range 2 Drill Pipe, 63/,-lnchTool Joints Dogleg Sevem (Hole Cunrature)-Degrees Per 100 Feet Figure U a t e r a l Forces on Tool Joints and Range Drill Pipe 5-lnch, 19.5 Pounds per Foot, 3 Range 3 Drill Pipe, 63/,-lnch Tool JointsCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL L998 U 0732290 Ob09732 514 m 62 API RECOMMENDEDPWCE 76 10 Drill Stem Corrosion and Sulfide the n conductivity may result in higher c o n i o n i d Stress Cracking rates. Concentrated salt solutions m usually less corrosive than dilute solutions; however,because of decreased oxygen 10.1 CORROSION solubility. Dissolved salts also may serve a source of w- as 10.1.1 Corrosive Agents bon dioxide or hydrogen Sulfide drilling fluids. in Dissolvedsalts in drillingfluids may comefromthe Corrosion may de6ned as the alteration and degradarion makeup water, formation &lididow, drilled formations, or be of material by e h n m e n t . The principal corrosive agents drilling fluid additives. its affecting drill stem materials in water-base drilling fluids are dissolved gases (oxygen, carbon dioxide, and hydrogensul- 10.1.1.5 Acids fd) dissolved salts,and a i s ie, cd. Acids corzode metals by lowering pH (causing hydro- the 10.1.1.1 Oxygen gen evolution) and by dissolving protectivem Dissolved íil s. oxygen appreciably accelerates the corrosion rates of acids, Oxygen is the mostcommon corrosive agent. In the pres- and dissolved hydrogensulfide greatly accelerates hydrogen ence of moistureit causes rustingof steel, the most common embrittlement. form ofcomsion. Oxygen causes uniform corrosion pit- and organic acids (formic, acetic,etc.) Mn be formed in drill- ting,leading to washouts, twistoffs, andfatiguefailures. ing fluids by bacterial action or by thermal degradation of Since oxygenis soluble in water, and most drilling fluid sys- organic drilling fluid additives. Organic acids and mineral tems are open to the a r the drill stem is continually exposed i, acids (hydmchloric, hydrofluoric, etc.) may be used during to potentially sevem corrosive conditions. workover operations or stimulating treatments. 10.1.1.2 Carbon Dioxide 10.1.2 Factors Affecting Corrosion Rates Carbon dioxide dissolves in water to form a weak acid Among the many factors a€fecting corrosion rates of drill (carbonic acid) ta corroda steel in the same manner as ht other acids (by hydrogen evolution),unless the pH is main- stem materials the more important ae r: 6. tained above At higher pH values, carbon dioxide corrosion damage is similar to oxygencorrosiondamage, but at a 10.1.2.1 pH slower rt. When carbon dioxideandoxygen are both ae This is a scale for measuring hydrogen ion concentration. p e n t , however, the corrosion r t is higher than the ae sum of The pH scale is logarithmic; i.e., each pH increment of 1.0 the rates for each alone. represents a tenfold change in hydrogen ion concentration. Carbon dioxide in drilling fluids maycome h m the The pH of pure water, fkee of dissolvedgases, is 7 0 pH val- .. makeup water, gas bearing formaton fluid inflow, thermal ues less than 7 a increasingly acidic, and pH values greater decomposition of dissolved salts and organic drilling fluid than 7 are incmshgly alkaline. In the presenceof dissolved additives, or bacterial action on organic material in the oxygen, the corrosiona e of steel in water is relatively con- rt makeup wateror drilling fluid additives. stant between pH 4.5 and 9.5; but it increases rapidly at lower pH v l e ,and decreases Slowly at higher pH values.A h - aus 10.1.1.3 Hydrogen Sutfide num alloys, however, may show increasing corrosion rates at Hydrogen & dissolves in water to form an acid some- de pH valuesgreater than 8.5. what weaker and less corrosive calnmic acid, although it than may causepitting, particularly t epresence of oxygena d in h n 10.1.2.2 Temperature or carbon dioxide. A more signifìmt action of hydrogensul- In general, corrosion rates inmase with inmasing temper- fide is its effect on a form of hydrogenembrittlement known aue tr. as sulfide stress clacking ( e 10.2 for dtis. se eal) Hydrogen sulíìde in drilling fluids may come from the 10.12.3 Velocity makeup water, gas-bearing formation fluid inflow, bacterial action on dissolved sulfirtes,or thermal degradationof sulfur- In general, corrosion rates inarase with higher r t s of ae containing drilling fluid additives. flow. 10.1.1 A Dissolved S a l t s 10.1.24 Heterogeneity Dissolved salts (chlorides, carbonates, and sulfates) Localized variations in composition microstructure may or increase the electrical conductivity of drilling fluids. Since increase corrosion rates. Ringworm corrosion,that is some- most cormsion pmceses involve electrochemical d o n s , times found near the upset areas of drill pipe or tubing t a htCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGC 1798 U 0732290 Ob09733 450 m RECOMMENDED AND OPERATING LIMITS PRACTICE FOR D R l U STEM DESIGN 63 treated after upsetting, is an exam- has notbeen properly heat for an infinitenumber of cycles is known the fatigue limit. as nonuniform grain structure. ple of corrosion caused by Remedial action for reducing drill stem fatigue is discussed in Section 8. 10.1.2.5 High Stresses In a corrosive environment no fatigue limit exists, since failure will ultimately occur from corrosion,even in the Highlystressed areas may corrode faster than areas of absence of cyclic stress. The cumulative effect of corrosion lower stress. The drill stemjustabovedrill collars often greater and cyclic stress (corrosion fatigue) is than thes u m of shows abnormal corrosion damage, partially becauseof the damage from each. Fatigue lifewill always be less in a higher stresses andhigh bending moments. corrosive environment, even under mildly corrosive condi- tions that show little or visible evidence of corrosion. no 10.1.3 Corrosion Damage (Forms of Corrosion) Corrosion can take many forms and may combine with 10.1.4 Detecting and Monitoring Corrosion other types of damage (erosion, wear. fatigue, etc.) to cause The complex interactions between various corrosive agents extremely severe damageor failure. Several forms of c m o and the many factors controlling corrosion rates make it dBì- sion may occur at the same time, but one type will usually cult to accurately assess the potential corrosivity of a drilling predominate. Knowing and identifying the forms of corrosion fluid. Various instruments and devices such as pH meters, can be helpful in planning corrective action. The forms of oxygen meters, corrosion meters, hydrogen probes, chemical corrosion most often encountered with drill stem materials test kits, test coupons, etc. are available for field monitoring aer: of corrosion agents and their effects. The monitoring system "described in Appendix A of API 10.1.3.1UniformorGeneral Attack Recommended Practice13B-1, Recommended Pmctice Stun- During uniform attack, the material corzodes evenly, usu- dard Pmedure for F e d Testing Water-Based il Drilling Fluids, ally leaving a coating of corrosion products. The resulting can be used to evaluate corrosive conditions and follow the to loss in wall thickness lead to failure h m reduction of the can effect of remedial actionstaken to correct undesirable condi- materials load-carrying capability. tions. Preweighed test ringsare placed in recessesat the back of tool jointbox threads at selected locations throughout the 10.1.3.2 Localized Attack (Pitting) drill stem, exposed to the drilling operation for a period of time, then removed, cleaned, and reweighed. The degree and Corrosion may be localized in small, well-defined a a,r s e severity of pitting observed may be of greater significance causing pits.Their number,depth, andsize may vary consid- than the weight loss measurement. erably; and they may obscured by corrosion products. be Pit- The chemical testing of drilling fluids (see API Recom- ting is difficult to detect and evaluate, since it may occur mended practices 13B-1 and 13B-2) should be performed in under corrosion products, mill scale and other deposits, in the field whenever possible, especially tests for pH, alkahity, crevices or other stagnantareas, in highly stressedareas, etc. and the dissolved gases (oxygen, carbon dioxide, and hydro- P t can cause washouts and can serve points of origin for is as gen sulfide). fatigue cracks. Chlorides, oxygen, carbon dioxide, and hydro- gen sullide, and especially combinations them, are major of 10.1.5 Procurement of Samples for Laboratory contributors to pitting corrosion. Testing 10.1.3.3 Erosion-Corrosion When laboratory examinationof drilling fluid is desired, representative samples should collected in a II2 to 1 gallon be Many metals resist corrosion by forming protective oxide (2 to 4 liter) clean container, allowingair space of approx- an films or tightly adherent deposits. If these fìlms o deposits r imately 1 percent of the container volume and sealing tightly are removed o disturbed by high-velocity fluid flow, abrasive r with a suitable stopper. Chemically resisting glass, polyeth- suspended solids, excessive turbulence, cavitation, etc., accel- ylene, and hard rubber are suitable materialsfor most drill- This erated attack occurs at the fresh metal surface. combina- ing fluid samples. Samples should be analyzed as soon as tion erosive and of wear corrosion cause may pitting, possible, and the elapsed time between collection and analy- extensive damage, and failure. See sis reported. ASTM D3370, Standard Practicesfor S m - pZing Water, for guidance on sampling shipping and 10.1.3.4 Fatigue in a Corrosive Environment procedures. (Corrosion Fatigue) When laboratory examination of corroded or failed drill Metals subjected to cyclic stresses of sufEcient magnitude stem materialis required, use care in securing the specimens. will develop fatigue cracks that may growuntil complete fail- If torch cutting needed,do it in away ta wl avoid physi- is ht il ure occurs. The limiting cyclic stress t a a metal cansustain ht cal or metallurgical changes the area to be examined. Spec- inCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • e4 API RECOMMENDED PRACTICE 7 6 h e n s must not be cleaned, wire brushed,or shot blasted in 10.1.8 Extending C r o i n Fatigue L i o r so any m n w and should be wrapped and shipped in a way an , W e generally not a€Fecting corrosion es,the following rt a that will avoid damage to the corrosion products or fracture measures will extend corrosion fatigue life by lowering the s r a e .Whenever possible, both ufcs fracture surfaces should be strength of cyclic stress intensity or by increasing the fatigue supplied. the material: 10.1.6 DrillPipeCoatings a Use thicker-walled components. b. Reduce high stresses near connections by mhimizhg dog- ddl Internally coating the pipe and attached tool joints can legs and by maintaining straight hole conditions, insofar as pie effective pe n against corrosioninthepipe v d rc ootit possible. bore. In the F e n c e of corrosive agents, however, the corro- c. M . . . stress concentratomsuch as slip marks,tong sionrateoftheddlStemODmaybeincreaxxLDrillpipe m rsgouges, notches, scratches, etc. a , k coating is a shopoperation in which thepipe is cleaned of all d Use quenched and tempered components. grease and scale, sandor grit blasted to white metal, plastic coated, and baked. After baking, the coatingis examined for 10.2SULFIDE STRESS CRACKING breaks or holidays. 10.2.1 Mechanism of Sulfide Stress Cracking 10.1.7 Corrective Measures to Minimize Corrosion (SSC) in Water-Base Drilling Fluids In the presence of hydrogen sulfide (H$), tensile-loaded drill stem components may suddenlyf i in a brittle manner al The selection and control of appropriate corrective mea- at a fraction of their nominal load-carrying capability after sures is usually performed by competent corrosion technolo- performing satisfactorily for extended periods of time. Failure gists and specialists. Generally, oneor more of the following may occur even in the apparent absence of corrosion, but is measures is used,but certain conditions may require more more likely if active corrosion exists. Embrittlement of the specializedtreatments: steel is caused by the absorption and diffusion ofatomic a Control the drilling fluid pH. When practical so with- . to do hydrogen andis much moresevere when H,S is present. The out upsetting otherdesired fluid pmperties, the maintenance brittle failure of tensile-loaded steel in the presenceH,S is of of a pH of 9.5 or higher will minimize corrosion of steel in termed sulflde stress clacking (SSC). water-base systems containingdissolvedoxygen. In some drilling fluids,however, corrosion of aluminum drill pipe 10.2.2 Materials Resistant t SSC o than . . increases at pH values higher 8 5 The l t s revision of NACE Standard “01-75, Suyide aet b. Use appropriate inhibitors and/oroxygenscavengers to Stress Cracking Resistant Mekdlic Material for Oil Eeld Equip minimize weight loss corrosion. This is pafticularly helpfill ment, should be consulted for materials that have been found to with low pH, low solids drilling fluids. Inhibitors must be be satisfactory for drilling and well servicing ons. operati carefully selected and controlled, because different corzosive Other chemical compositions, h r n se, and heat treat- a es s d agents and different drilling fluid systems @aaicularly those ments should notbe used in sour environments without fully used for air or mist ddling) require Merent types of inhibi- evaluatingtheir SSC susceptibility intheenvironmentin tr.The use of the wrong type of inhibitor, or the wrong os which t e will be used. Susceptibilityto SSC depends on the hy amount,may actuallyincrease corrosion. following c. Use plastic coated drill pipe. C~IC must be exercised to prevent damage the coating. to 10.2.2.1 Strength of the S t e e l d Use degassers and desandento remove harmful dissolved . The higher strength (hardness) of the steel, the the greater is gases and abrasive material. the swceptibility to SSC. In general, steels having strengths e. Limit oxygen intake by maintaining tight pump connec- equivalenttohardnessesupto22HRCmaximumareresistant tions and by minimizing. pit-jetting. to SSC. If the chemical composition adjusted to permit the is f. Limit gascutting and formation fluid inflow by maintain- development of a well tempered, p d o m h a d y martensitic ing proper drilling fluid weight microstructut by pe quenching and tempering; steels rr op g.Whentheddlstringislaiddown,stored,ortransported, having strengths equivalent t hardnesses up to 26 HRC maxi- o wash outall drilling fluid residues with fresh water, clean out mum are resistant to SSC. When strengths higher than the all corrosion products (by shot blasting or hydmblasting, if equivalent of 26 HRC are required corrective measures (s a necessary). and coat surfaces with a suitable corrosion all p- showninalateasection)mustbeused;and,thehi~the ventive ( e Am Recommended Practice 5C1,Recovnmended se stnmgth q ie , greater the necessity for the corrective udr the Pmctice for Care and Use o Casing and Tubing). f measures.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D - A P I I P E T R O RP 7G-ENGL L998 W 0732290 0609735 223 m PRACTICE FOR DRILL STEM DESIGN RECOMMENDED AND OPERATING LIMITS 65 10.2.2.2 Total Tensile Load (Stress) the Steed on b. Limit gascutting and formation fluid inflow by maintain- ing p r drilling fluid weight. p e The higher the total tensile load on the component, the .. . c. Mlmmlze corrosion by the corrective measures shownin greater is the possibility of failure by SSC. For each strength 10.1.7. of steel used, thereappears to be a critical or threshold stress below which SSC will not ww, however, the higher the Note: While use of plastic coated drill pipe can minimize colrosion, plastic strength, the lower the thresholdstress. coating does not protect susceptible d d l pipe from SSC. d Chemically treat for hydrogen sulfide inflows, preferably . 10.2.2.3 Amount o Atomic Hydrogen and H2S f prior to encountering the sulfide. e. U e the lowest strength drill pipe capable of withstanding s Thehighertheamountofatomichydrogenand H2S the required drilling conditions. At any strength level, po rp present in the environment, the shorter the time before failure erly quenched andtempered drill pipe will provi& the best by SSC. The amounts of atomic hydrogen and&S required SSC resistance. to cause SSC quite small, but corrective measures con- are to trol amounts their w minimize the l i atomic hydrogen f. Reduce unit stresses by using thicker walled components. absorbed by the steel. g.Reduce high stresses at connections by maintaining straight hole conditions, insofarpossible. as 10.2.2.4 Time h. Minimize stress concentrators such as slip marks, tong m rsgouges, notches, scratches, etc. a , k Time is required for atomic hydrogen to absorbed and be i. After exposure to a mur environment, usecare in tripping diffused in steel to the critical concentration required for out of the hole, avoiding sudden shocks and high loads. crack initiation and propagation failure. By controlling the to factors referredto above, time-to-failure may be sufficiently j. After exposure to a sour environment, remove absorbed hydrogen by aging in open air for several days to several lengthened to permit the use of marginally susceptible steels for shortduration drilling operations (see Figure 45). weeks (depending upon conditions of exposure) or bake at 400" to 600°F (204" to 316°C) for several hours. 10.2.2.5 Temperature Note: Plastic coated drill pipe should not be kated above 400°F (204°C)and should be checked subsequently for holidays and disbondhg. The severityof SSC is greatest normal atmospheric tem- at The removal of hydrogen is hindered by the presence of peratures, and decreasesas t m e- increases. At operat- corrosion products, scale, grease, oil, etc. Cracks that have ing temperatma in excess of approximately 135°F (57"C), formed (internally externally) prior to removing the hydro- or marginallysusceptiblematerials(thosehaving h&esses gen will not be repaired by the baking or stress relief opera- higher than 22 to 26 HRC) have been used successfully in tions. potentially embrittling environments. (The higher the hard- ness of the m t r ,the higher the required safe operating aa eli k Limit drill stem testingin sour environments toas brief a tm. e -) Caution must be exercised, however4SC fail- period as possible, using operating procedures that mini- will ure may occur when the material returnsto normal tempera- mize exposure to SSC conditions. ture after it is removed h m the hole. 10.3 DRILLING FLUIDS CONTAINING OIL 10.2.3 Corrective Measures to Minimize SSCin 10.3.1 Use of Oil Muds for Drill Stem Protection Water-Base Drilling Fluids Comsion and SSC can be minimizedby the use of drilling The selection and control of appropriate corrective mea- fluids having oilas the continuous phase. Corrosion does not sures is usually performed competent corrosiontechnolo- by occur if metal is completely enveloped and wet oil envi- by an gists and s e i l s s Generally, oneo more of the following pcait. r ronment t a is electrically nonconductive. ht measures is used, but certain conditions may require more Oil systems used for drilling (oil-base or invert emulsion specialized treatments: muds) contain surfactants that stabilize water as emulsitied practical a Control the drilling fluid pH. When to doso with- dropletsand cause preferentialoil-wettingofthemetal. out upsetting other desired fluid properties, maintain a pH of Agents that cause corrosion in water (dissolved gases, dis- 10or higher. solved salts, and acids) donotdamagetheoil-wetmetal. Therefore, under drilling conditionsthat cause serious prob- Note: In some drilling fluids, alnminum alloys show slowly i n d g corro- lemsof corrosiondamageerosion-corrosion,orcorrosion sion rates a pH values higher than 8.5; and the rate may become excessive at t pH v l higher than 10.5. T e em i dill strings containing aluminum am hrf , n fatigue, drill stem life can be greatly extended by using an oil drin pipe, the pHshould not exceed 10.5. mud.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • 66 API REWENDED P A TC 7 6 R CI E PCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • 10.3.2 Monitoring Oil Muds for Drill Stem where Protection 9, = critical sliding hole angle, f = coefficient offriction. An oil mud must be properly prepared and maintainedto protect drill stem from corrosion and Water will always SSC. 11.1.3 The critical sliding hole angle is theangleabove be present in an oil mud, whether added intentionally, incor- which drill string components mustbe pushed into the hole. porated as a contaminant in the surface system,orfrom Although many factors a & coefficient t the € of friction exposed drilled formations. Corrosion andSSC may OCCUT if between the drill string components and the wall of the hole, free this water is allowed to become and to wet the drill stem. the type of drilling fluid used has the greatest impact (see Factors to be evaluated monitokg an oil mud include: in Table 19). Water-baseddrillingfluidsgeneratethehighest coefficient to friction andproducecriticalholeanglesof 10.3.2.1 Electrical Stability about 71 degrees. Synthetic-based drilling fluids provide the lowest coefficients of friction and produce critical hole angles This test measures the voltage required to cause current to of about80 degrees. flow between electrodes immersed in the oil mud (seeAPI RecommendedPractice 13B-2, Recommended Pmctice Stan- 11.1.4 OperatingSignificantlengthsofthe drill stringin dard Procedure for Field Testing Oil-Based Drilling Fluids, compression can causethepipetohelicallybuckleand for details). The higher the voltage, the the stability greater of induce pipe c u r v m s larger than the curvature of the hole the emulsion, and the better the protection provided to the and may cause unacceptable bending stresses. Rotating drill drill stem. pipe in curvedportions of the hole generates cyclic bending stresses that can also cause fatigue failures. The most effec- 10.3.2.2 Alkalinity tive and efficient drill string design for extended leach and horizontal holes is the lightest weight drill string t a can ht The acidic dissolved gases(carbon dioxide and hydrogen withstand the operating environment Using heavier compo- sulfide) are harmful contaminants for most oil muds. Moni- nents or thicker wall tubulm often increases the operating toring the alkalinity of an oil mud can indicate when acidic loads without reducing the bending stresses. gases are being encountered so ta corrective treatment can ht beinstituted. Table 19-Effect of Drilling Fluid Type on Coefficient of Friction 10.3.23 Corrosion Test Rings Q p i d Coefficient Critical Hole Angle Test rings placed in the stem bore are used to monitor drill Ddlling Fluid of fiction & = F the corrosionprotection aftorded by oil muds (see AH Rec- W ~ - mb ~ d 0.35 71 ommended Practice 13B-2 for details). A properly function- Oil-bas mud 0.25 76 ingoilmudshouldshowlittle or no visualevidenceof Synthetic-basemud O. 17 80 corrosion on the test ring. 11.2 DRILL PIPE BUCKLING IN STRAIGHT, 11 Compressive Service Limits for Drill INCLINED WELL BORES Pipe (see also Appendices A.14 and A.15) 11.2.1 overview 11.1COMPRESSIVESERVICEAPPLICATIONS 11.2.1.1 The curves shown in Figures46 through 66 give the approximate axial compressive loads at which sinusoidal 11.1.1 Wheneverdrillinghighangle,extendedreach, or buckling is expectedto occur in drill pipe in straight, horizontal well bores it is desirable to use compressively inclined wellbores.If the drill pipe is being rotatea limiting loaded portions of the drillstring. Drilling withdrill pipe in the drill pipe compressive load to below the estimated buck- compression causes no more damage to the drill pipe than will ling load shown in these curves significantly reducethe conventionaldrillingoperations as long as theoperating danger of fatigue damage to the pipe. Conversely, rotating conditions do not exceed the compressive service limits for drill pipe while is buckled can lead rapid fatigue damage it to the pipe. and failure. 11.1.2 Drill strings are subject to compressive service con- 11.2.1.2 These curvesare based on the equations of Daw- ditions whenever significantportions of the borehole exceed son and They are reproduced with here permission the critical sliding hole angle as defined as follows: from Standard DS-1, Drill Stem Design and Inspection.28The assumptions behind these curves include: e, = arc tan@, a, Pipe weightis newnominal X-grade with tool joint dimensions (where applicable). more than one tool If joint is (Text continued on page 78.)COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D - A P I / P E T R O R P 3G-ENGL L998 m Q732290 Ob09738 T 3 2 m 8 API RECOMMENDED M C E 7 6 P Figure W p p m x i m a t e Axial CompressiveL o a d s at which Sinusoidal Buckling is Expected to Occur 4 10 12 18 14 16 20 Hole size (n h s i c e) Figure 47-Appmimate Axial Compressive Loads at which Sinusoidal Buckling isExpected to OccurCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • RECOMMENDED PRACTICE FOR DRU S E DESIGN TM AND OPERATING LIMITS 69 4 6 8 10 16 12 14 18 m Hole size (inches) Figure &Approximate Axial Compressive Loads at which Sinusoidal Buckling is Expectedto Occur Hole size (inches) Figure 49-Approximate Axial Compressive Loads at which Sinusoidal Buckling is Expected to OccurCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO 7G-ENGL RP L998 m 0732290 O b 0 9 7 4 0 690 m 70 API RECOMMENDED PRACTICE 7 6 Figure ! - prx a % p mt A oi e is Axial Compressive Loads at which Sinusoidal Budding Expected to Occur FigureCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL L998 0732290 Ob09743 527 RECOMMENDED PRACTICE FOR DRILLSTEM DESIGN OPERATING AND LIMITS 71 I ...... / . . . . ...... 1:: i 4 ...... ..." ... .... . ....... . . i...... ............... i. i 1.............. 4 ..............i i... ....... ....... . . ...... ....... . . . ....... . i I." .... ...... ......1 ......I...... i i-...... ....i 1 ..... .......L I.............+...... ......!....__i [....... i...... ...... !....I ......i L ...... ..... !. ...... ....... ...... ...... .......i......i......c......i......i..... .....l, .... .......i.... . . . . ... ...... 3V,-inch, 15.50 ppf ...... 12 ppg mud I::+ ...... ......i....... ....... . ~ . . ; . i . ............... ......_... i . i i ; ................................ i...... :.............. 1.......................................... ; ; i i i. . . . . . I l I I I 1 1 1 1 1 i 1 l 1 1 1 I 1 I 1 1 1 1 1 6 8 10 12 18 14 16 20 Hole size (inches) Figure 52-Approximate Axial Compressive Loads at which Sinusoidal Buckling is Expectedto OccurCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL L998 m 0732290 Ob09742 4b3 m 72 API REC~MMENDED PRACTlCE 7 6 Figure 55"Appmimate Axial Compressive Loads atwhich Sinusoidal Budding isExpected to OccurCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD-APIIPETRO RP 7G-ENGL L998 m 0 7 3 2 2 9 0 Ob09743 3 T T RECOMMENDED PRACTICE DRILL %EM DESIGN OPERATING LIMITS FOR AND 73 Figure 56-Approximate Axial Compressive Loads at which Sinusoidal Budding isExpected to OccurCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD-API/PETRO P R ÏG-ENGL L998 , I I 0732290 Ob09744 23b m 74 API RECOMMENDED M C E 7 6 P Figure 58-Approximate A x i a l Compressive Loads at which Sinusoidal Budding Expected to Occur is Figure 59-Appmimate Axial Compressive Loads at which Sinusoidal Budding isExpected to OccurCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • RECWMENDED PRACTICE FOR DRU STEM DESIGNAND OPERATING LIMITS 75COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D = A P I / P E T R O R P 7G-ENGL 1998 m 0732290 b0974b O09 I API REC~MMENDED PRACTICE 7 6COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL L998 m 0732290 Ob09747 T 4 5 m RECOMMENDED PRACTICE FOR DRILL*M DESIGN AND OPERATlNG LIMITS 77 I 1 I I I I ........ ...,-. ......................... ........... 1 1 ..... ......I .....1.....i.....i.....i..... ............ 1.....i..... .....I............ ..... .......................................l .,.,,,: .!..................1 I ....- i ....... .. .. 1-.....!___.- l ... ~ " f .....i..... i.....j.....4.c .....i_.._.i..... ......i ..... .....i J .....i....i.....j..... L . .. .! i..... ............ I ..; _.___i r-- ...... . ....- .....i......;..-..i. i..i i......i.....i . .....i i.... . . ..... ..... . . 5/,inch, 24.70 ppf ....- "_ ..... i........... 1...... .....I ...... .....i.....i...........i..... f .....i..... i i .. . i . i . i ..... L ..... ...... ..... ..... ...... ..... ..... .....j ......i.....i 1 .....?)..... ..... .....i ..... A ...... ..... i ........... ..... ..... ..... .....i...... i..... i.....i i.....i..... ..... ...... ..... ppg 12 mud .... ....i i... i .........i. . . . . . . . . .. _.__.i ..i ... .. ..... ..... i ..i...t .....i i........... i......i i.....i i ............ i.__.__i...i.....i..... .... .. .. .. . i .i ..... .. . 7oooo ..... ..... ................. ......i....... i...........i.....i......1._..__i L......i. i......i............i.. i............. .. . ..... .......... ...... .....4 . i . i......i.....i......+.....i .....i ..... ii ......I ..... . .....ii ............ +.....i ...... .... . ..___G . i _____i . ? E . ............................. i......j...........i......i..... ...... ...... ..... i.....i...... .._..i... i ....._..... ... _._._i ............i.....1_____i i.....i ..... .... i .....i..i ... ... L :._..:.. ...i...i ... _____: .. .. ..i .....i........... j ......i...... . ......i .... i . c-" .. .. . . 1 .... . .. ... . ...... . i . ..... ...... . ...... . i . ..... .... .......i.....i. 4_....: .(-.i L.... .-..I...L....i......i i..i... i........... i.....i. : i.....i. i....." __._i ... . : .. . ..... i I-........i J..".*......... .. 4... ......C." .i"... . - ..c .. .. ..... .....i ... i...i.....i ........ i... .....j ......i .....L .....:...... .... j .. .. ! ? I . . . . .. :.....J i ... .. .. . .. .....:..L ..____:.. * ..... * .....:......:..... i ...... :.. 2:::::: ..... ...... . ............ I .....I .... _._._i 1_____ii.....1____.i i .....2 ...._i 1......i .....4 .....i ...... ..... ..... ". ......i i......I..... i j......i...........i i.......i...... ...-i i.....j.....i..... i............i..... 1......i i..... ..... i...... ..... :>.....i ...... . . ...... . j . ...... 1 ...... ...... ...... 14 12 8 10 16 18 20 22 24 Hole size (inches) Figure 64-Approximate Axial Compressive Loads at which Sinusoidal Buckling is Expected to Occur Figure 65-Approximate Axial Compressive Loads at which Sinusoidal Buckling Expected to Occur isCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • ~~~ ~~ ~~ ~~ STD.API/PETRO RP 7G-ENGL II998 m 0732290 Ob09748 981 m 78 PRACTICE 76 API REC~MMENDED 10 12 14 16 18 20 22 24 Hde size (inches) Figure 66-Approximate Axial Compressive Loads at w c Sinusoidal Budding is Expected to Occur hh i common one wasselected. u e on a particular pipe,the most sd 11.2.3 Using the Drill Pipe Buckling Curves Tool joint diameter is the minimum for Premium Class. Enter the curvefor the correct pipe size and weight a the t Radial clearance is the distance between the tool joint OD hole diameter. Read verticallyo intersect the hole angle, then t and the hole. horizontally t read critical buckling load. Compensate the o b. Pipe wall thickness is new nominal. value obtained for mud weight being used. c. The well bore is straight. d The effects of torqueare neglected. 11.2.3.1 Example e. Mud weight is 12.0 1Wgal. How much compressive load may be applied to 5-inch, 11.2.2 Compensating for Different Mud Weight 19.50 Wft drill pipe in a 12/,-inch horizontal hole before the drill pipe buckles? Mud weight is 9.0 lb/gal. criticalbuckling If the actual mud weightis not 12.0 lWgal, load maybe adjustedby the following formukx 11.2.3.2 Solution: = (Fd-œ#)(FA(f,) Reading from the figure for the drill pipe in question (Fig- urem), the critical buckling load is about 28,200 pounds. W h Adjusting to 9.0 Wgal mud: F - = adjusted criticalbuckling load(lbs), F& = criticalbuckling loadfrom curve ( b ) ls, F - = 28,200 lbs (1.03) = 29,000 lbs f = (buoyan~y , factor/o.817)05 (~ee below), 11.3 CRITICAL BUCKLING FORCE FOR CURVED Mud Weight Mudweight BOREHOLESnSSflS W@) , f W@) f - The critical buckling force of compressively loaded drill04 8.0 14.0 0.98 pipe is also signifìcautly ifed by the c m - n n l u of the03 9.0 15.0 09 .7 borehole. In angle building intervals the upward curvature of02 10.0 16.0 O.% the borehole in- the critical buckling force. In turning01 11.0 17.0 0.95 iutervals t e hole curvature also increases the buckling force h 12.0 1.00 18.0 0.94 of the drill pipe. Table 20 showsthe hole curvature rates t aht 13.0 0.99 19.0 0.93 p e n t buckling for range ofpipe and holesizes. a COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL L998 m 0732290 Ob09749 818 m RECOMMENDEDPRACTICE FOR DRILL STEM DESIGNAND OPERATING LIMITS 79 Table 2 W o l e Curvatures that Prevent Buckling Hole DrillPipe Drill pipe Nominal Tool Joint AxialLoad Size OD I D Weight OD 5Mlbs 1OMlbs lsMlbs UlMlbS 25Mlbs 40Mlbs 30Mlbs 50Mlh i. n ia i n lWft in. allm "/looft " / l mO/lOoEt "/looft. ""/ /l lm m "/looft2.375 4.000 1.815 6.7 4.750 2.875 2.151 10.4 4.125 0.8 0.4 1.6 1.2 2.0 2.4 3.2 3.9 6.000 2.875 2.151 10.4 4.125 2.4 1.2 4.7 3.5 5.9 7.1 9.5 11.8 6.000 3.500 2.764 13.3 5.000 0.6 0.3 1.3 1.0 1.6 1.9 2.6 3.2 6.750 3.500 2.764 13.3 5.000 1.1 0.6 2.3 1.7 2.8 3.4 4.5 5.6 6.750 4.000 3.340 14.0 0.7 5.250 0.3 1.o 1.3 1.7 2.0 2.7 3.4 7.875 4.000 3.340 14.0 5.250 1.2 0.6 2.4 1.8 3.0 3.5 4.7 5.9 7.875 4.500 3.826 16.6 6.250 0.2 0.5 1 0.7 .o 1.2 1.5 2.0 2.5 8.750 4.500 3.826 16.6 6.250 0.8 0.4 1.5 1.1 2.3 1.9 3.O 3.8 8.750 5.000 4.276 19.5 6.375 O2 0.5 1 0.7 1.4.o 1.2 2.4 1.9 8.750 5.500 4.778 21.9 7.500 o.1 0.42 O 0.3 0.5 0.6 0.9 0.8 8.750 5.500 4.670 24.7 7.250 0.2 o.1 0.4 0.3 0.5 0.6 1 0.8 .o 9.875 5.000 4.276 19.5 6.375 0.4 1.4 0.7 1.1 3.6 1.8 2.8 2.1 9.875 5.500 4.778 21.9 7.500 0.4 0.2 0.7 0.5 1.8 0.9 1.4 1.1 9.875 5.500 4.670 24.7 7.250 0.2 0.4 0.5 0.7 1.8 0.9 1.4 1.1 9.875 6.625 5.%5 25.2 8.000 0.2 o.1 0.3 0.3 0.4 0.8 0.5 0.7 12.250 5.000 4276 19.5 6.375 1.2 0.6 2.4 1.8 3.6 3.0 6.0 4.8 12.250 5.500 4.778 21.9 7.500 0.4 0.7 1.4 1.1 2.1 1.8 3.6 2.9 12.250 5.500 4.670 24.7 7.250 0.3 0.7 1.o 2.0 1.3 1.7 3.4 2.7 12.250 6.625 5.%5 25.2 8.ax 0.2 0.8 0.4 0.6 1.o 1.1 1.9 1.5 11.3.1 Example ing of the tool joints, well as the axial compressive load as on the pipe and the curvature of the hole. Will 5-inch drill pipe buckle in a 10-degrees-per-100-foot The application of compressive loadson tool jointeddrill build curve of a horizontal well? The hole is 8.75 inches size pipe in curved boreholes progresses through three s a e . tgs and the maximum required bit loadis 30,000 pounds. Under light loads, the maximum bending occurs in the stress center of the pipe span only the tool joints in contact but are 11.3.2 Solution with the wall of the borehole. As loading is inmased, the Table 20 shows t a 5-inch, 19.5 lb/ft ht drill pipe in an 8.75- center of the pipe comes into contact with the wall of the inch hole will not buckle in hole curvatures greater than 1.4 hole.Under this loadingconditionthemaximumbending degrees per 100 feet with a30,000 pound load. stress occurs a two positions that located on either side of t are thepointofpipe body contact. As theload is further increased, the length of pipe body contact increases from 11.4 BENDING STRESSES ON COMPRESSIVELY point contact wrap contact along a length to of pipe locatedin LOADED DRILL PIPE CURVED IN BOREHOLES33p34 the center the joint. of Figures 67 through 74 pie solutions to the bending v d Rotating compressively loaded pipe in curved portions drill stress, pipe body contact, and lateral contact loads for the of the borehole generates cyclic bending stresses that, if large most common sizes of 6V8-inch to 23/,-inch drill pipe. There enough,maycausefatiguedamage.Compressiveloading are four plots for each size of drill pipe. The plot in figures may also cause aportion of the pipe bodyto contact the wall 67-74 (figures a) show the maximum bending stress as a of the hole. In abrasive formations, pipe body contact can function of axial compressive load for a range of hole curva- erode the body of the pipe and further magnify the bending tures. The type of loadingis shown by the style of the plotted stresses. The maximum bending stress caused by compres- lines. For no pipe body contact, the bending stress curve is sively loading pipe in curved boreholes is affected by the drill shown as a solid line. For point contact the bending stress size of the tool joints, the of the pipe size body, and thespac- relation is shown as a dashed line and forwrap contact the (Text continued onpage 96.)COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • ~ STD-API/PETRO P R 7G-ENGL 1998 m 0732290 Ob09750 53T PRACTICE 7 6 API RECOMMENDED 6.625-in. 25.2Ib/ft Drill Pipe, &in. Tool Joint 1O ppg mud, 90-degree 12.25-in.hole 40 35 30 25 20 15 10 5 O O 10 20 30 40 50 60 70 Axial compressive load-lo00 lb. Figure 67a-Eending Stress and Fatigue LimitsCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D m A P I I P E T R O R P 7G-ENGL L998 m 0732290 0609751 476 m REC~MMENDED PRACTICE FOR DRU -M DESIGNAND OPERATlNG LIMITS 81 6.625-in. 25.2Ib/ft Drill Pipe, &in.Tool Joint 1 O ppg mud, 90-degree 12.25-in. hole 10 d/h O 10 20 30 40 50 60 70 Axial compressive load-1 o00 lb. Figure 6 7 H a t e r a l Contact Forces and LengthCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • 82 API RECOMMENDED ~ C7 6 P E 5.5-in. 21.9 Ib/ft Drill Pipe, 7.5-in. Tool Joint 10 ppg mud, 90-degree 9.875-in. hole 40 35 30 25 20 15 10 5 O ö 10 20 30 40 50 60 70 Axial compressive Ioad-lOOO lb. Figure 68a-Bending Stress and Fatigue LimitsCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • ~ S T D - A P I I P E T R O PG - E N G L R7 L998 m 0732290 Ob09753 249 m PRACTICE FOR DRU STEM DESIGN RECOMMENDED AND OPERATING LIMITS 83 Tool Joint 5.5-in. 21.9IbRt Drill Pipe, 7.5-in. 10 ppg mud, 90-degree 9.875-in. hole 10 5 O 20 d/h Figure 68b”ateral Contact Forces and LengthCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • a4 pRAcTlc~ 6 API REC~MMENDED 7 sin. 19.5 IbAt Drill Pipe, 6.375-in. Tool Joint 1O ppg mud, 9Gdegree 8.50-in.hole 40 35 30 25 - o P Q 1 8 20 c. 00 P ü C d 15 10 5 O O 10 20 30 40 60 Axial compressive o O O la- O lb. dl Figure 69a"Bending Stress and Fatigue LimitsCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL L998 m 0732290 0609755 O L L m PRACTICE FOR DRU SE DESIGN AND OPERATING LIMITS RECOMMENDED TM 85 5-in. 19.5IbM Drill Pipe, 6.375-in.Tool Joint 1O ppg mud, 90-degree 8.50-in. hole 10 I. I " " - " " - I 5 O , " " , - . " , " . . , . . . . , . . . . ~ . . . . 20 dlh ~ O 10 20 30 40 50 601 Axial compressive load-1 O00 lb. Figure 69b"Lateral Contact Forces and LengthCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • 86 API REW"ENDED 76 PRACTICE 4.541.16.6 lbfi Drill Pipe, 6.254. Tool Joint 1O ppg mud, 90-degree8.50-in. hole Figure 70a-Bending Stress and Fatigue LimitsCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D O A P I I P E T R O R P IC-ENGL 1998 m 0732290 Ob09757 994 W RECOMMENDED FOR PRACTICE DRIU STEM DESIGN OPERATING LIMITS AND 87 4.5-in. 16.6Ib/ft Drill Pipe, 6.25-in.Tool Joint 1O ppg mud, 90-degree 8.50-in. hole 10 5 30dn-l O 20 d/h O 10 20 30 Axial compressive load-1 O00 lb. Figure 7Ob"Lateral Contact Forces and LengthCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • ~~ ~ STD-API/PETRO RP 7G-ENGL L998 m 0732290 Ob09758 820 m 80 API REC~MMENDED PRACnCE 7 6 4.0-in. 14.0 IbAt Drill Pipe, 5.25-in.Tool Joint with 10 IWgal mud in a 6.75-in. hole Figure 71e n d i n g Stress and Fatigue LimitsCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO P R 7G-ENGL L998 m 0732290 Ob09759 767 m RECOMMENDED PRACTICE FOR DRU %EM DESIGNAND OPERATING LIMITS 89 Tool Joint 4.0-in. 14.0Ib/ft Drill Pipe, 5.25-in. with 10 IWgal mud in a 6.75-in. hole 15 10 30dnl 5 2odnl 10 dnl O O 10 20 30 40 50 Axial compressive load-1 O00 lb. Figure 71 M a t e r a l Contact Forces and LengthCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STDmAPIlPETRO RP 71;-ENGL L998 m 0 7 3 2 2 9 0 ObO37bO 489 3.5-in. 13.3 1 M t Drill Pipe, 4.75-in. Tool Joint with 1O Wgal mud ina 6-in. hole 40 35 30 25 20 15 10 5 O O 10 20 30 40 Axial compmsive load-loo0 lb. Figure 72a"Bending Stress and Fatigue LimitsCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D a A P I / P E T R O RP 7G-ENGL 1 9 9 8 m 0732290 ObO97b1 315 D RECOMMENDED PRACTICE FOR DRILLSTEM DESIGN OPERATING AND LIMITS 91 3.5-in. 13.3Ib/ft Drill Pipe, 4.75-in. Tool Joint with 10 Ib/gal mud in a 6-in. hole OD P 5 4odh I 3 I 2 30dh a - c C O 20 dh S I- 10 dh 15 I 1 I - I I I I 10 4odh 30dh 2m o 5 10 dh O Figure 72b-Lateral Contact Forces and LengthCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • ~~ S T D = A P I / P E T R O RP 7G-ENGL L998 m 0732290 Ob097b2 251 W 92 API RECOMMENDED PRAC~CE 6 7 2.875-in. 10.4 Ibm Drill Pipe, 4.125-in. Tool Joint with 10 Wgal mud ina 4.75-in. hole Figure 73a-Bending Stress and Fatigue LimitsCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D = A P I / P E T R O R P 7G-ENGL 1998 W 0732290 0609763 198 W PRACTICE FOR DRILL RECOMMENDED STEM DESIGN AND OPERATING LIMITS 93 2.875-in. 10.47Ibh Drill Pipe, 4.125-in. Tool Joint with 10 Wgal mud in a 4.75-in. hole 6 2 O 10 5 1 1om O O 10 20 30 40 50 70 Axial compressive load-i O00 lb. Figure 73b-Lateral Contact Forces and LengthCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • 94 API PRACTICERECOMMENDED 76 2.375-in. 6.65 I b / f t Drill Pipe, 3.12541. Tool Joint with 10 IWgal mud in a 3.875-in. hole 40 35 30 25 20 15 10 5 O O 5 10 15 20 25 Axial mpressive load-lo00 lb. Figure 74a43ending Stress and Fatigue LimitsCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • RECOMMENDEDPRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS 95 2.375-in. 6.65 Ibht Drill Pipe, 3.125-in.Tool Joint with 1O Ib/gal mud in a 3.875-in. hole 4odh 3m o 20 dh 10 d/h 2odh 10 dh O 5 10 15 20 25 Axial compressive load-1 O00 lb. Figure 74Materal Contact Forces and LengthCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • 96 API RECOMMENDED PRACTICE 7 6 plotted stress is shown as a dotted line. The plots include also 11.4.3 Example the fatigueendurance bending stress limits h m Section 11.5. The plots assume 10 %/gal mud, 9Odegree hole angle, and a Determine the maximum bending stresses for d i c h , 14 a deíìned hole se z. i The mud d n i , hole angle, and hole es t y %/ft drill pipe with 5V8-inch tool joints in 24Megrees-per- 100-foot holecurvature, and a 20,000 poundaxial compres- size do not affect the bending stresses unless the pipe buckles. On most o theplotsthe f critical bucklingforce is only sive load. e for cases with or negative build The bend- x& zero rate. ing stresses for buckled pipe independent ofthe hole cur- are 11A.4Solution vatureandgenerallyfollowcurves i whichthebending n Figure 71a shows the bending stresses for 4-inch, 14 lb/ft stress inarmes more rapidly with increased axial load than drill pipe, with W4-inch tool joints. The actual tool joint out- for the constant hole curvatures s c e. a side diameter is 53/8-inchor ‘/,-inch larger. Figure 75 shows The plots Figures 67-74 (iue b) show the pipe body the hole curvatwe adjustment in fgrs factorsfor various sizes of drill contact length and the lateral contact forces between the pipe pipe as a function of the difference in the tool joint outside body and the tool joints with the wall of the hole. diameters. Foran actual tool joint, ’/,-inch larger than nomi- nal, Figure 75 showsthat with 4inch d d I pipe the curvature adjustment factoris l.l. To determine themaximumbending 11A.1 Example V, stress for the inch larger tool jointa 2Odegrees-per-100- in An 8V2-inch horizontal well will be drilled with 5-inch foot holeamature at 20,000 pound load, multiply the actual hole curvature by the adjustment factor, 2Odegrees-per-100- 19.50 lb/ft drill pipe with 6V,-inch tool joints in an W2-inch feet times 1.1 = 22-degrees-per-lOO-feet Using 22degrees- hole with 10 lb/gal mud The maximum hole curvatm will per-100-feet a 20,000 pounds on Figure 71% the bending t be 16 degrees per 100 feet. The horizontal interval will be stress for 53/,-inch tool joints 24,500 psi. is drilled with surface rotation with loads up 35,000 p u d . to ons What grade of drill pipe is requiredfor this example? 11.5 FATIGUE LIMITS FOR API DRILL PIPE 11.A2 solutlon R P Morgan and M. J. R ~ b l i n ~ ~ . developed a method of measuring fatiguelimits from smaU drill pipe samples. Their 11.4.2.1 Figure 69a shows the bending stresses and fatigue technique preserves the effect of the produced” drill pipe “as limits for 5-inch, 19.5 1b/ft pipe, with @/,-inch tool joints drill hotfinish sr cs uf e. a They reported on thetestingof API in a 9dg e oer , . e 8V2-inch hole with lWgal mud For a hole 10 Grades E75, X95, G105, and S135well as an experimental as cumahre of 16deps-per-100-feet and an axial compres- high strength tubular identified as V180. Their test program sive load of 35,000 pounds, the maximum bending stress is showed that the fatigue endurance iis for drillpipe corre- lmt %O 0 psi. A slightly , 0 high= bending stress of 25,OOO psi is late well with the tensile strengththe pipe. Table 21 shows of some of the results of their test program. p u by a 24,000 pound axial load. Themaximumbend- od rd ing stresses exceeds the fatigue endurance limits for Am Grade. E75, X95, and D55 pipe, but is less than t e fatigue h Table 21-Youngstown Steel Test Resutts* endurance lmt for grades G105 and S135 pipe. iis Figure 69b Avenge EndunmceIimit shows that at 35,000 pound axial load, the tooljoint contact forces would be about 2,600 pounds with a 16 degrees per .m. Idnumum API Yild API Tensile Tensile Strength M’ Median 1OOfootcurvaauerate.Thepipebodycontactforcewillbe Ya strength strength Of m Test mt about 600 pounds under a 35,000 pound axial load F r this o clrade strength Maximum Minimum samples val= value curvatureratethecontactwillbeatthecenterofthespan. ksi ksi ksi ksi ksi ksi 123 100 105 E75 75 30 32 11.4.22 The maximum bending stresses for point and x95 95 132 125 105 35 32 wrap contact are directly proportional to the holecurvatures G105144 115 105 135 34 38 andradialclearancesbetweenthepipebodyandthetool 167 145 165 135 joints. This allows us to use the existing bending stress plots S135 36 40 to estimate the bending stresses for tool joint dimensions *o Y- Sheet and lbbe Compauy, 1969M E conference,Tulsa, M other than used in preparing the plots. adjustment is nec- No Oklahoma essary unless the loading condition produces point or wrap contact- If t i is the c s , we can compute an adjustment fac- hs ae tafromtheactualsizeofthetooljointandusethattocom- Casne+hasutilizedtheirtestresultstodetenninethemin- pute an equivalent hole curvature to determine the coT28cf b fatigue endurauce limits for API drillpipe that meets um bendingstress. the API minimum strength requirements, See “%le 2. 2COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D O A P I I P E T R O RP 7G-ENGL L778 m 0732290 0607767 8 3 3 m PRACTICE FOR DRU STEM DESIGN RECOMMENDED AND OPERATING LIMITS 97 1.30 1.20 1.10 1.o0 0.90 0.80 0.70 -0.375 -0.250 -0.1 25 O.OO0 0.125 0.250 Actual TJ minus nominal M n . T Figure 75"iole Curvature Adjustment FactorTo A l w for Differences in Tooljoint ODs loCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • Table 22-lätigue Endurance Limits Compressively Table 23-Values Used in Preparing Figure77 Loaded Drill Pipe Expactedultimate MinimumFatigue m API Strength and Fatigue Stress Limit far .. IvhmumTensile MinimumFatigue Islpical stress Limit forme l o ,o , O O o o Minimum Grade Yield Strength strength EhdmœLimit Grade YieldStzmgth Revdutions Revolutim ksi ksi ksi ki s ksi ksi E75 75 100 2. 20 E75 87.5 115 2. 2. 67 x95 2 . 95 31 15 0 x95 219 . 80 0 .3 115 3.5 G105 2. 53 15 1 G105 319 . 22 0 .4 195 4. S135 3. 19 15 4 150.0 S135 3. 50 190 5. 11.6 ESTIMATINGCUMULATIVEFATIGUE fatigued endurance limits for these tensile strengths. The SN DAMAGE curve was computed by using the exponential relationship described above with the tensilestrength equal to the fatigue An interesting altemative to operating below the fatigue endurance limit for one revolution and the fatigue endurance endurance limits for drill pipe is to monitor the cumulative stress limit for onemillion revo- limit values to represent the fatigue damagecaused by rotating in high curvature intervals lutions.Thevaluesused to prepare Figure 77 are S &li of the borehole and retire the pipe before failuresoccur. The in Table 23. concepts for tracking the cumulative fatigue damage have been well developed by Hansford andLubir~slci.~~J~ The key The cumulative fatigue damage determined by counting is towards successful use of this technique is establishing the the revolutions of pipe in highly curvedportions of the bore- appropriate stress versus revolutionsto failure curves for the hole where the stresses exceed the fatigue endurancel m t .iis various grades of A P I drill pipe. Figures 76 and 77 provide If, for example, the revolutions in aparticular section of hole estimates of the median expected failm limits found by Mor- represent 20 percent of the predicted revolutions to failure for gan and Roblin and an estimate minimum failwe limits of the ta dogleg severity it is judged that 20 percent of the fatigue ht of API drill pipe that has been manufactured to average A P I life has been consumed. Figures 76 and 77 can be used to properties. We would expect that f of the drill pipe exposed hl a judge inspection levels and ultimate retirement levels. The to the limits shown i Figure 76 would fail. The minimum n ultimate life can be judged from the plot ofthemedian failure limits in Figure 77 should avoid fatigue failures on fatigue limits of Figure76. The appropriate minimuminspec- typical API drill pipe. The mediaa failure limits based on are tion levels can judged from the be minimum fatigue limits of an exponential relationshipthat connects the average tensile Figure 77. After exposure to this level of fatigue, inspection strength of the tested specimens representing one revolution and removal of damaged joints can extend the remaining to failure with the median fatigue endurance limits represent-string life or beyond the expected median life levels. to ing onemillion cycles to failm. The average tensile strength Figures 78 through 80 are plots of the bending stresses for values and the median fatigues endurance limits h m Table and 3vZ-inch, 27l8-inch, 23i8-inch drill pipe in highly curved 21 were used to develop thestress versus revolutionsto fail- boreholes. The bending stresses determined h m these plots we curves shown in Figure 6 7. are used to determine thetotal n m e of revolutions the u br that pipe can withstand from Figures 76 and 77. These are then TS Theequationisoftheform: S = - comparedt the observed number of revolutions determine o to N" ratio the level of fatigue damage. The of the revolutions the to where predictedmedian revolutions failure defìnes the to fraction of the drillpipefatigue life consumed drilling through the high in S = bending stress limit,p is, Ts = tensile stmgtb of pipe, psi, curvature hole. N = molutionst~failm, x = a frzlctionalexponent of about l. D. 11.6.1 Example Thecurvesofminimumfailmljmitsarealsobasedonthe An example ofthe cumulative fatigue damage calculations Morgan and R o b b data Their report includes a table t a ht is given by the following. Consider drilling a 5OO-foot hori- de6nes the typical yield and ultimate tensile strengths for nor- zontal hole below a 1OO-fod build curve with 3VZ-inch radius malized Grade E75, normalized and t e - orades X95 S135 c i l pipe. Drill pipe will be rotated at 30 RPM with hl and G105, and quenched tempered Grade S135 API drill l , O WOB, andis expected to drill at 15 feet per hour. The 0O O pipe. Using Casnefs d e 0.22 ratio we computed the ed h rate equivalent build is given by: COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
    • STD-API/PETRO RP 7G-ENGL 1998 D 0732270 06077b9 bob D RECOMMENDEDPRACTICE FOR DRU S E DESIGNAND TM OPERATING LIMITS 99 85 80 75 70 65 W 55 50 45 40 30 lo00 10,Ooo Revolutionsto failure Figure 76"edian Failure Limits for API Drillpipe Noncorrosive ServiceCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • ~ ~~~~~ STD.API/PETRO RP 7G-ENGL L99B D 0732290 Ob09770 328 D 100 API RECOMMENDED W C E 7 6 P 5 lo00 Figure 774inimum Failure Limitsfor API Drillpipe Noncorrosive ServiceCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL 1,998 m 073229.0 0609771, 264 m PRACTICE FOR DRU &EM DESIGN AND OPERATING L I M ~ REC~MMENDED 1o1 11.7 BENDING STRESSES ON BUCKLED DRILL B = -5730 R PIPE where The bending stresses on buckled drill pipe must account B = build rate,d e ~ 1 0 R, 0 for both the mechanicsof buckling and the additional bend- R = build r d s R ai , u ing caused by the axial load and the tool joints. The curvature producedby bucklingis given by: 5730 For this case: B = -100 = 57.3 degreedlooft. Fxh,x57.3x12x100 Bbuc = 2xExZ 11.6.2 Solution 17190 X F(Dh - Dtj) Figure 78a shows that at 10,000 pound axial compressive Bbvc = load and a 57-degrees-per-100-footbuild rate the maximum ExZ bending stress is 50,000 psi. Figure predicts that half of the 76 S135 pipe will fail under a 50,000 psi bending stress after where 110,000revolutions. The minimumfailure limits Figure 77 of Bk = curvatme of buckled pipe, "/lo0 f. t, predict that S135 pipe can rotated 39,000 re~olution~ be with- F = axial load, lb., out failure. Dh = hole diameter, in., The number of revolutions of exposureis given by: Dti = tooljoint OD,in., h, = radial clearance 60xLxRPM - h,. N = " ROP 2 Z = acea moment of inertial of pipe, ? i , n where B = Youngs modulus, psi N = revolutions of exposure, = 30 x 106 psi for steel. L = length of high curvature hole,R, RPM = romy speed rev/min, This curvature can be used in place ofthe hole curvature in ROP = penetration rate,ft/hr. the equations covered inSection 1 1.4. The length of of our 90 degree build curveis equal t : L o 12 Special Service Problems R IC 12.1 SEVEREDOWNHOLEVIBRATION L = - X R = - X 1 0 0 = 157ft. 2 2 Downhole vibration inevitable.In many cases, low levels is of vibration go undetected and harmless. However, severe are Therefore, the number of revolutions of exposure for the downhole vibralion cause can drillstring fatigue failure pipe that is rotated through the build is equal to: curve (washou~twist~ff), k e d drillstrings, premature bit fail- m ure, and r e d u d penetration rates. The mainsources of exci- tation are providedbythe interaction of the bit with the N = 6o x 157 x 30 = 18,850 revolutions 15 formation and the drillstring with the wellbore. The drillstring response to these excitationsources is very complex. The cumulative damage can be computed by comparing Vibration can induce three components of motion in the therevolutions exposure of to the ll0,OOO revolutions drillstring and the namely: axial (motion along drillstring bit, required to cause half of t e pipe t fail. This suggeststhat 17 h o axis), torsional (motion causing twistftorque) and lateral (side percent of the fatigue life of the affected pipe has been con- to side motion).A l three dynamic motions may coexist and l sumedindrillingonewell.Comparingtherevolutionsof one motion may cause another. exposure to theminimum fatigue limitof 39,000 revolutions While theories exist, thereno general agreementon how is evaluates the risk offailure. For this case, the a 18,850revolu- to predict (calculate) when damaging vibrations will occur. tions ofexposurerepresents 48 percentofthe minimum However, by observing the symptoms of severe downhole fatigue life expected for Sthe pipe. This suggests that two 135 vibrations,probablemechanismsmay bedeterminedand wells could be drilled withthis string before inspecting and appropriate corredive actions taken. downgrading or removing fatigue damaged joints from ser- Severe downhole vibration often accompanied bysymp is vice. Continued use of the string requireremoving signif- will toms belonging to more than one mechanism. fact makes This icant portions of the affected pipe in order to prevent failures. the detection of the primary mechanism more d E ut For Z cl (Text continuedc page 108.) mCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • 102 API REWMMENDED PRACTCE 7 6 3.5 in. 13.3 lwft Drill Pipe, 4.75 in. Tool Joint with 10 lWgal mud in a 6 in. hole ö ï o 30 b lcompressive load-1 O00 lb. a Figure 78a-Bending Stress for High CuwaturesCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 76-ENGL L998 m 0732290 0609773 037 m PRACTICE FOR DRU STEM DESIGN AND OPERATING LIMITS RECOMMENDED 103 3.5 in. 13.3 IbAt Drill Pipe, 4.75 in. Tool Joint with 10 Ib/gal mud in a 6 in. hole 10 8 6 4 2 O 15 10 5 O O 10 20 3ö Axjal compressive load-1 O00 lb. Figure 7 8 H a t e r a l Contact Forces and LengthCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • ~ ~~~~~ ~~ STD.API/PETRO RP 7G-ENGL L998 m 0732290 Ob09774 T73 m 104 API REC~MMENDED PFtt~mcE 76 2.875 in. 10.4 lwft Drill Pipe, 4.125 in.Tool Joint with 1O Wgal mud in a 4.75 in. hole Figure 79a-Bending S r s for High Curvatures tesCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D = A P I / P E T R O R P 7G-ENGL L998 m 0 7 3 2 2 9 0 Ob09775 90T m PRACTlCE FOR DRU STEM DESIGN AND OPERATING L RECOMMENDED " 105 2.875 in. 10.4 Ibht Drill Pipe, 4.125 in.Tool Joint with 10 Wgal mud in a4.75 in. hole 100dh 80dlh 6om 40 dlh 20 dlh 15 10 5 O ~ " " 8 " " 10 15 20 25 Axial compressive load-1 O00 lb. Figure 79b"Lateral Contact Forces and LengthCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • 106 API REW"ENDED PMCE 76 2.375 in. 6.65 IbAt Drill Pipe, 3 2 0 in. Tool Joint .5 with 10 Wgal mud in a 4.00 in. hole O 5 10 15 Aial compressive load-loo0 lb. Figure 80a-Bending Stress for High CurvaturesCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • PRACTICE FOR DRU STEM DESIGN RECOMMENDED AND OPERATING LIMITS 107 2.375 in. 6.65 IbM Drill Pipe, 3.250 in. Tool Joint with 10 Ib/gal mud in a 4.00 in. hole 10 8 6 4 2 O 20 15 10 5 O O 5 10 15 20 Axial compressive load-lo00 lb. Figure 8Ob”ateral Contact Forces and LengthCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • example, an increase " inDshock counts, which indica- is ping rotation,use s a i i e BHA withfull gauge near-bit tblzd tive of BHA lateral vibration, can be caused by BHA Whirl, stabikmmreamer. Bit Bounce, or other mechanism. Additional clues, suchas d Bit bounce: bit t o hbreakage, for example, are required for the iden- ot this 1. Mechanism--large weight-on-bit fluctuaiions causing primary vibration mechanism. tifìcation of the the bitto repeatedly lf off andimpact the formation. it This There are a number of mechanisms which cause severe can mechanism often occurs when drilling with roller cone downhole vibration. For mechanisms, their symptoms, and bits inhard formations. methods of control are described below: 2. Symptoms-large axial 1 t 10 Hz vibrations (shaking o of hoisting equipment), large WOB fluctuations, cutter and/ a Slapstick . or bearing impact damage, fatigue cracks, reduced ROP. l. Mechanism-Non-uniform bit rotation in which the bit 3. Actions-run shock sub or hydraulic thruster, adjust slows or even stops rotatingmomentarily, causing the WOB/RPM, consider changing bit style, change length of drillstring to periodically torque up and then spin f e . re BHA. This mechanism sets up the primary torsional vibrations e. Other mechanis-some field data and theoreticalstud- i the string. n ies indicate that certain "critical speeds" exist which excite 2. Sympto=surface torque fluctuations>15 percent of resonant vibrations. previous editions of Recommended Prac- average (below 1 Hz or stalling), increased MWD shock tice 7G gave formulas and graphs for predicting these critical counts, cutter impact damage, drillstring washouts/twist- speeds. However, severe vibrations have routinely mea- been offs, comedion over-torque or back-off. sured a RPM other than those by simple t give these Note: 1 Hzisonecyclepersecond. calCUlElti0~. 3. A c t i o d u c e WOB and increase RF", m i d e r a 12.2 TRANSITION FROM DRILL PIPE TO DRILL less aggressive bit, modify mud lubricity, reducestabilizer COLLARS rotational drag (change blade design number of blades, or use non-rotating s a i i e or roller reamer), adjust stabi- tblzr Frequent failure in the joints of drill pipe just above the lizer placement, smooth well profile, rotary feedback add drill collars suggestsabnormallyhighbending stresses in sy - these joints. This condition is particularly evident when the b. Drillstringwhirk hole angle is increasing with depth and the bit rotated off is bottom. Low rates of change of hole angle combined with 1. Mwhanisnr--the BHA (ordrillpipe) gears mund the deviated holes maymult in sharp bending ofthe first joint of borehole. The violent whirling motion slams the drill- drill pipe above theo l r .When joints are moved h m this clas string against the borehole. The mechanism can cause location and rotated to other sections, the effect is to lose ~odandlateralvibmtim. . . washouts/twist-offs,localized identity of these damaged joints. When these joints later fail 2S" through accumulaton of additional fatigue d a , every a g me tool joint and/or stabilizer wear, increased average torque, joint in the string becomes suspect One practice to reduce 5 to 2OHz lateral vibrations even if bit off-bottom. f a i l m a the transition zone and improve control over the t to 3. Actions-Ht bitoff bottom and stop rotation, then damag~jointsistousenineortenjoin~ofheavywallpipe, reduce R M avoid drill collar weight in excess of 1.15 to P , or smaller chill c b above the o l r .Thesejoints are o, just clas 1.25 timesWOB, use packed hole assembly,reduce stabi- marked for identiíìcation, and used in the transition zone. lzr rotational drag, adjust saiie placement, modify ie tblzr TheyareinspectedmmGrequentlythanregulardrillpipeto mud po et sconsider drilling with a downhole r p ri , e motor. reduce the likelihood of service failures. The use of heavy c. Bit whirl: wall pipe reduces the stress level in the joints and ensures 1. Mechanism"esentric d o n of the bit about a point longer life in this severe seMce condition. other than its geometric center c u e by b i t h e m asd gearing (analogous to a planetary gear). This mechauism 12.3 PULLING ON STUCK PIPE induces high frequency lateral and t s vibmtion of odri the bit and drihhiug. It is normally notconsidered good practice to pull on stuck drill pipe beyond the minimum tensile yield strength for the 2 Symptoms-atter impact damage, uneven bit gauge size,grade, weight, and classif~cation the pipe in use (see of W=, 0 v e r - p hole, reduce ROP, 10 to 50 Hz lateraV ~ mies 4,6, and 21). For example, assuming a string 5-in.,of torsional vibrations. 19.5 lb/ft Grade E drill pipe is stuck, the following approxi- 3. Actions-lift bit off bottomand stop rotation, then mate values for maximum hook load would apply: Feduce RF" and increase WOB, comider changing bit (flattex profile, anti-whirl), use slow RF" when tagging PremiumClass: 3 1 1,535 lbs bottom and when reaming, pickoff bottom before s t o p Class 2: 270,432lbsCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • ~ STD.API/PETRO RP 7G-ENGL L998 m 0732290 Ob09777 555 m PRACTICE FOR DRILLSTEM DESIGN REC~MMENDED AND OPERATING LIMITS 109 The stretch in the drill pipe due to its own weight sus- 12.5 TORQUE IN WASHOVER OPERATIONS pended in a fluid should be considered when working with Although little data are available on torque loads during drill pipe andthe propex formulas to use for stretch when free or stuck should used. be washover operations, they are significant. Friction and drag on the wash pipe cause considerable increases in torque on 12.3.1 Example I (see A.6 for derivation): the tooljoints and drill pipe, and should be considered when pipe is to be usedin this type service. This is particularly true in 0 O Determine the stretch a 1 , O foot string of drill pipe O in directionally drilled wells and deep straight holes with in freely suspended 10 lWgal drilling fluid. small tolerances.(See 12.6.) e = L ’ [65.44 - 1.44 W B ] (22) 12.6 ALLOWABLE HOOKLOAD AND TORQUE 9.625 x lo7 COMBINATIONS and Allowable hookloads torque combinations stuck drill for - - 10’W2 [65.44- 1.44 X 101 strings maybe determined by use of the following formulx 9.62s X lo7 = 53.03 i . n, where = length offree drill pipe, feet, W = weight of drilling fluid, lb/gal, , where I e = stretch, inches. QT = minimum torsional yieldstrength under tension, lb-ft., 12.3.2 Example II (see A.4 for derivation): J = polar moment of inertia: Determine thefree length in a 1 , O foot string 4V2-in. 0 O O of IC OD 16.60 1Wft drill pipe which is stuck, and which stretches = - (D4-d4) fortubes, 32 49 i .due to differential pull of OOO lbs. n a 80, D = outside diameter, inches, d = inside diameter, inches, 735,294 X e X W,, Y = minimum unit yield strength, psi, , L, = (23) P S = minimumunit sh=strength,psi: , 735.294 x 49 x 16.60 (S, = 0.577 Y,,,), 80,OOO P = total loadin tension, pounds, A = cross section area = 7476 f . t, An example of torque which be applied the pipe the may to where which is stuck while imposing a tensile load follows: as is 4 = length of free drill pipe, feet, e = differential stretch, inches, Assume: Wb, weight of drill pipe, pounds per foot, = a 3V2-in.OD 13.30lb Grade E drill pipe. . P = differential pull, pounds. b. 3V2-in,I tool joints. F c. Stuck point: 4OOO feet. 12.4 JARRING d Tensile pull: 100,OOOpounds. It is common practice during fishing, testing, coring and e. New drill pipe. other operations to run rotary jars to aid in k i n g stuck Lkn: assemblies. Normally, the are run below severaldrill col- jars lars which actto concentrate the blowt the fish. It is neces- a sary to take the proper stretch produce the r e q u i d blow. to 0.096167 x 9.00 QT = 3.5 Themomentumofthemoving mass of drill collars and stretched drill pipe returning to normal causes theblow after the jar hammer is tripped.A hammer force of t r e to four he C&= 17,216 lb-ft. times the excess of pull over pipe weight possible depend- is ing on type and size of pipe, number (weight) of collars, drill For further information on allowablehookloads,torque drag, jar travel, etc.This force may be large enough to dam- application, and pump pressure use, see Stall and Blenkam: age the stuck drill pipe and should be considered when jarring Allowable Hook Load and Toque Combinations For Stuck operations are planned. Drill Sm*ngs.12COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL L998 m 0732290 Ob09760 277 H 110 API RECOMMENDED PRACTICE 7 6 12.7 BIAXIAL LOADING OF DRILL PIPE 12.10 EFFECT OFTENSILE LOAD ON COLLAPSE RESISTANCE The collapse resistance of drill pipe corrected for the effect of tension loading maybe calculated by reference to Figure The effect of tensile load applies onlyto greater than tran- 81 and the use of formulas and physical constants contained sition loadon normally elastic items, and to any loadon plas- in 12.8, 12.9,12.10,and 12.11. tic collapseitems. In either case, the value determined from the plasticcollapse formula (Appendix A) to be modifìed. is 12.8 FORMULAS AND PHYSICAL CONSTANTS M e t h d Substitute the tensile load value in formula (4), z. 12.8, to find a value forSubstitute this value in formula (2), The ellipse of biaxial yield stress shown in Figure46 is for 12.8, to permit solution fur Next, substitute the value rof r. in use in the rauge of plastic collapse only, andhgives t e relation formula (3), 128, to obtain the effective collapse resistance between axial stress @si)in terms of average yield stress (psi) under tension. and effective collapse resistance interms of nominal plastic collapse resistance. This relationship is depicted in the fol- 12.1 1 EXAMPLE CALCULATION OF BIAXIAL lowing form& LOADING 12 + rz + z2= 1, having solutionsas follows: An example of the calculation ofdrill pipe! collapse resis- tance, corrected for the effect of tensile load as follows: is Given: String of 5-inch OD, 19.50 lb per ft, Grade E P m z = - r+J= m Class drill pipe. m i 2 ,and (1) Required: Determine the collapse resistance c for oe tension loading during drill stem test, with drill pipe empty Z + J X and 15 lb per gal.mudbehindthe drill pipe. Tensionof r= * (2) 50,000 lb on the joint above the packer. 2 Solution:Findreduced cross section area of Premium where Class drill pipe as follows: a Nominal OD = 5 inches, nominal wall thickness = 0.362 Effective collapse resistance under tension (psi) r= (3)Y inches. Nominal plastic collapse resistance (psi) b. Nominal I = 4.276 inches. D c. Reduced wall thickness for pxemium. Total tensile loading (pounds) Z = (4) d Class = (0.8)(0.362) = 0.28% inches. Cross section area x Average yieldstrength * e. Reduced OD for premium class = 4.8552 inches. f. crOss-sectional area for premium. Average yieldstrengths in psiare as follows: g. Class=reducedODarea-nominalIDarea . GradeE75 . ... . .. . . 85,000 = 18.5141 - 14.3603 = 4.1538 sq.inches. G a e 5 ... . . r dm . ... 110,000 h Tension load on bottom joint = 50,000 z 4.1538 . . GradeG105 .... ... 120,000 = 12037 psi. i. Average yieldsh-ength for Grade E drill pipe = 85,000 psi. Grades135 ... . .. . . 145,000 j. Percent tensilestress to average yieldsh-ength 12.9 TRANSITION FROM ELASTIC PLASTIC TO =-85,000 x 100 = 14.16percent 12037 COLLAPSE IL Enter F i- 81 at 14.16 percent on upper right horizontal M;rterial in the elastic range whenunder no tensile load, scale and drop vertically to intersect right-hand portion of the transfers to the plastic m e when subjected to sufiicient g ellipse. proceed horizontally to the left and intersectNominal axial load. Axial loading, below the transition load, has no collapse Resistance (cente~ vertical scale)t 92 percent a effect on elastic c l a s . At transition point, the collapse olpe L Minimum collapse resistance for premium class ("de 5) resistance under tension equals the nominal elastic collapse, = 7041 p is. and also equals a tension factor (r)times collapse resistance m.correctedco~seresistancefor~ectoftension as calculated h m the nominal plastic formula. = (7041)(.92) = 6478 psi. M e t h d Determine values for both elastic and plasticcol- CAUZZON: No safety factors are included in this example lapse from applicable formulas in Appendix substitute in A, calculation formula (3). 12.8 and solve for r. Then, solve formula (l), Nok:Use~val~forcrosssectionalarea.tensirmaudc~llapaerating 12.8, for z. For the t t l tension (transition) load, substitute oa fortheappropriateclass~~~2)0fuseddrillpi~beingconsid- value of z in fonnula 12.8. (4). dCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • ~~ STD.API/PETRO RP 7G-ENGL L998 0732290 Ob09783 303 RECOMMENDED DRILL PRACTICE FOR SIEM DESIGN OPERATING AND LIMITS 111 h Collapse OCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD-APIIPETRO P R 7G-ENGL 1998 m 0732290 Ob09782 0 4 T m 112 A P I RECOMMENDEDP M C E 7 6 13 Identification, Inspection and body in-service failures OCCUT near the upset runout within or - Classification of Drill Stem the slip area Special attention to these critical fail- aseas Components should be perfomed during inspection t facilitate crack o L detection in drill strings which have been subjected to abnor- 13.1DRILLSTRINGMARKINGAND mally high bending stresses. Drill pipe which has just been IDENTIFICATION inspected and found fret of cracks may develop cracks after Sections of drill string manufadwed in accordance with very short additional service through the additionof damage Am Speciscation7 are ideded with the markings shown in to previously accumulated fatigue damage. Figure 82. It is recommended t a drill string members not ht covered by Specificationalso be stencilled at the baseCracks String 7 of the 13.2.2 Drill I pin as shown in Figure 82. It is a s recommended that drill lo of A crack is a single line rupturethe pipe surface. The u rp string members be marked using the mill slot and groove ture shall (a) be of sufficient length to shown by magnetic be method as shown in Figure 83. iron particles used in magnetic particle inspection or @) be identifiable by visual inspection of the outside of the tube 13.2INSPECTION STANDARDSDRILL PIPE andor optical or ultrasonicshear-wave inspection of the ANDTUBING WORK STRINGS inside of the tube. Drill pipe tubes, tool joints, drill collars and Through efforts of joint committees of API and M I X , found to contain cracks should be considered unfitfor further inspection standards for the classifìcation of used drill pipe drilling service. Shop repair of some tooljoints and drill col- have been established. The procedure outlinedin Table was 24 lars, containing cracks, may be possible if the unaffected area adopted as tentative at the 1964 Standardization Conference of the tool joint or drill collarp r i s body emt. and was revised and approved as standard at the 1%8 Stan- dardizationconference.Additional revisions were made at the 13.2.3 Measurement of Pipe Wall 1970 Standardization Conference to add premium Class. At Tube body conditions will be classifìed on the basis of the the 1971 Conference, it was determined that the drill pipe lowest wall thickness measurement obtained and remaining the classificationpracedurebe removed h m an appendix to API wall requirements contained in Table The only acceptable 24. Spezification 7 and placed inPI Recommended practice 7G. A wall thickness measurements are those made with pipe-wall At the 1979 Stan-on Conference, Table was revised 25 micrometers,ultrasonicinstruments, or gamma-ray devices to also cover classification of tubing workstrings. used that the operator can demonstrateto be w t i 2 percent accu- ihn The guidelines established in this recommended practice r a ~ y u ~ Of test blocks by e sized to approximate pipe wall thick- havebeeninuseforseveralyears.Useofthepracticeand ness. When using highly sensitive ultrasonicinstmment, care a classification guide have apparently been successful when must be taken to ensure that detection o an inclusion or lami- f applied in general application. There may be situations w h m nation is not interpreted a wall thickness measurement as additional inspectionsare nquiml. 13.2.4 Determination of Cross Sectional Area 13.2.1 Limitations of Inspection Capability (Optional) Most failures of drill pipe result from some form metal of Detemine cross sectionalarea by LW of a d r c indicating iet fatigue.A fatigue failure is one which originates as a d t of instnunent ta the operator can demonstrate to be within 2 ht repeated M fluctuating stresses having mx m values less aim percent accuracy by use of apipe section approximately the than the tensile strength of thematerial. Fatigue fractms are Sameasthepipebeingins~IntheabSenceofsuchan progressive, beginning as minute cracks that grow under the taken instrument, integrate wall thickness measurements at 1- action of the fluctuahg srs. The rate of propagation is tes inch intervals around the tube. related to the applied cyclic loads and under certain condi- tions may be extremely rapid. The failure does not normally 13.2.5 Procedure and exhilit extensive plastic deformation is therefore difficult to detect until such time as consided.de damage has U e drill pipe should be classified according to the pmce sd occuncedThereisnoacceptedmeansofinspectingtodeter- d m of "e 24 and as illustratedin Figure 84, d i m e n s i o n A. l minethe amount of accumulated fatigue damage or the Hook loads a minimumyield strength for New,premium and t remaining life in pipe at a givenstress level the Class 2 d d l pipe are listed in Table 26. Values recommended presently accepted means of inspection are limited to loca- for minimum OD and make-up tuque of weld-on tool joints tion of cracks,pits, and other surface marks; measurement of usedwiththeNew,premiumandclass2~pipearelisted r e m g wall thickness; measwementof outside diameter, in Table 10. Maximum allowable hook loads for New, Pre- and calculation ofremaining cross sectional area Recent mium and Class 2 tubing work strings ( l o classified in as industry statistics confirmmajor that aof tube accordance with Table are listed in Table 27. 24) (Text cie m page 122.) o d n n t nCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL L998 m 0 7 3 2 2 9 0 Ob09783 T8b of Sample markings at base pin 1 2 3 4 5 1 Manufacturers Symbol: Tool Joint ZZ Company (fictional for example only) 2 Month Welded: Wune 3 Year Welded: 70-1 970 4 Pipe Manufacturers Symbol: N-United S a e Steel Company tts 5 Drill Pipe Grade: E-Grade E75 drill pipe Notes: Tool joint manufacturers symbol, month welded, year welded, pipe manufacturer,and drill pipe grade symbol shall be stenciledat the base of the pin as shown above. Pipe manufactum symbol and drill pipe grade symbol applied shall be as represented by manufactum. Supplier, owner, or user shall be indicated on documents such as m l l icertificationpapers or purchase orders. TOOL JOINT MANUFACXJRERS SYMBOL Refer to the eleventh edition 1993 of the IADCDrilling Manual* (Section B-1-9) a list of Tool Joint Manufacturers symbols. for *Available h htemational Association o Drilling Contractors f P.O. Box 4287,Houston, TX 77210. Month and Year Welded Pipe Manufacturers year (Pipe Mills or Processors) 1 througb 12 Last two digits of year AdW. Drill Pipe Grade Mill Symbol Mill Symbol Grade svmbol Algoma X Amco A E75 ................. E British Steel American seamless AI x95 ................. x seamless n b e s L m B B&W W G105 ................ G Dalmine D CFm C S135................. S Kawasaki H J&L J Heavy Weight Drill Pipe Nippon I Lone Star L (Double stencil pipe grade symbol.) NKK K Ohio O Mannesmann M Republic R The "manufactu& may be either a pipemill o processor. See r A I Specification 5D,Specificatton for Drill Pipe. P Reynolds Aluminum RA TI Z These symbols are provided for pipe manufacturer sumitomo S Thbenluse Tu identificationandhave been assigned at pipe m n f c r r a ua t es u S i b SD vœst VA requests. Manufactmrs included i this list may not be current n M I Specification 5D licensedpipe m n f cues A list of a ua t r r . TamSa T wheeling Piusburgh P current licensed pipe manufacturen is availablei the Composite n us Steel N Youngstown Y List of Manujàcturers, (Licensedfor Use o the API Monogram). f Vallourw: V Pipe mills may upset andheat íreat t e own drill pipe, or they hir m a y have this done according to their specificatiom.In either own U d U case, the mills assigned symbol should used on each drillstring be assembly sinœ they are the pipe mauufacturcr. Symbol heat Pipe processors maybuy "green" tubes and upset and treat TFW these according to theirown specifications. In this case, the OMS processors assigned symbol should be used on each d d string assemhly sinœ they are the pipe manufacturer. PI - Figure 82-Mark1ngon Tool Joints for Identification of Drill String ComponentsCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • 114 API REC~MMENDED PRACTICE 7 6 No maddngs Standard weight gradeE75 drill pipe Standard weight grade G105 drill pipe rW7 Standard weight gradeX95 drill pipe Standard weight grade S135 drill pipe kld Heavy weight gradeE75 drill pipe Heavy weight grade G105 drill pipe - " Heavy weight grade X% drill pipe Heavy weight grade S135 drill pipe Drill pipe Weight cade (1) (2) () 3 (4) (1) (2) () 3 (4) SizeOD NominalWei& Wall- Weightcode SizeOD Nomindweight WallIhicloless Weightcode inchCs bFfi inchCs N& inchCs bperft inches N& 231, 4.85 .190 1 4VZ 20.00 A30 3 6.65. .280 2 22.82 .m 4 2.6 46 S50 5 2% 6.85 .217 1 25.50 575 6 .6 32 1.0 042 2 5 1.5 62 .2% 1 311 95 .0 .254 1 .6 32 1.0 95 2 13.3W .368 2 2.0 56 .m 3 1.0 55 .4 9 I 3 511, 19.M) .304 1 4 11.85 .262 1 21.w .6 31 2 14.00. .330 2 24.70 .415 3 271 4% 1.0 57 13.75 .380 3 1 20 5. 2 27.70 .330 362 2 3 .5 37 1.0 66. 2 *a ~Sstandardweightfndrillpipesizt. Figure 83"Recommended Practice for Mill Slot and Groove Method of Drill String IdentificationCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL L998 m 0732290 Ob09785 859 m RECOMMENDEDPRACTICE FOR DRU SIEM DESIGN AND OPERATING LIMITS 115 Table 24"Classification of Used Drill Pipe (Ausizes, weights and g a e .Nominal dimension is basis for all calculations.) rds class 2 class 3 Yellow Bands Orange Bands P p condition ie Two center h c h Marks ThreeCenterPlmchMarks L EXTERIOR CONDITIONS" k OD- .. Wl al Remamug wall notless Remaining wl not less al than 80% than 70% B. Dents and mashes Diame&r IIxiuction not Diameterreductionnot oyer 3% of OD over 4% of OD crushing, necking Dam duction not il m Diameterreduction not over 3% of OD over 4% of OD Depth not to exceed 1 % 0 Depth not to exceed 2%0 of the average adjacent of the average adjacent wall5 wall5 Diameterreductionnot Diameter d u c h l not o e 3% o OD vr f over 4% of OD 2. string shot Diameterincreasenot DiametainCTlXSnot over 3% o OD f over 4%of OD E Corrosion, and gouges . cuts, 1 Corrosion . Remaining wall not less Remaining wl not less al than8096 than 70% 2. Cuts and gouges Iangitudiual Remainingwall not less Remabhg wl not less al than8096 than 70% Remaining wall not less Remaining wall not less than 80% t a 85 hn0 F Cracks3 . None None None I.INTERIOR CONDITIONS I A. Conosive pitting Wl al Remaining wall not less not Remaining wall less than 80% measured from than 70% measured from base of deepest pit base of deepest pit B. Emsion and weat Wl al Remaining wall not less Remaining wall not less than8096 than 70% c. cmw None None NOne Tepremium classificationis recommendedfor serviœ w e e it is anticipateclthat torsionalor tensile limits for Class 2 drill pipe and tubing wo& strings w h hr lbe l i exceeded. These limits for Fremium Class and Class 2 drill pipe are specified i Tables 4 and 6, respectively.PremiumClass shall be identified with two white a bands, plusone center punch mark on the 35 degree a 18 dm shoulder ofthe pin end tool joint e qemaining wall shall not be less t a thevalue i LE.2,defects may be ground out providing the remaining wall is not reducedbelow value shawn i LE.l o hn n the n f this table andsuch grinding to be approximatelyfaired i t outer contour of pipe. no the any classificationw k nacks or washouts a p a, the pipe wbe identified with the red band and considered unfita fuaherdrilling service. p er li f 4 A n API Recommendedpractice 7G inspectioncannot be made with drill pipe rubbers on the pipe. adjacent wl is determined by measuring the wall thickness on each side of the cut or gouge adjacent to the deepest pd . al eo nnCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL 1998 0732290 Ob0978b 795 W 116 API RECOMMENDED PRACTlCE 76 I I I I I I I I I I I I I I I I I I o I I I ICOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL L998 m 0732290 Ob09787 b2L RECOMMENDED PRACTICEFOR D R U STEM DESIGNAND OPERATING LIMITS 117 Table 25-Classification of Used Tubing Work Strings critical service class premiumclass2 class 2 pipe Body Condition One White Band T h White Bands Blue Bands L EXTERIOR CONDlTXONS A. OD wear Wall Remaining wall not less Remaining wall not less .. Remamlngwall not less than 87V,% than 80% than 70% B. Deuts and mashes Diameterductionnot Diameter d u c t i o n not Diameterreduction not over 2% of OD over 3%of OD over 4% o OD f Crushing, necking Diameterductionnot Diameter reduction not Diameterreduction not over 2% o OD f over 3% of OD over 4% of OD Depth not to exceed 10% Depth not to exceed 10% Depth not exceed 20% to ofthe average adjacent oftheaverageadjacent of the average adjacent wall5 Wall5 wall5 Diameter reduction not Diameter reduction not Diameter duction not over 2%of OD over 3% of OD over 4% of OD 2. string shot Diameter increasenot Diameterincreasenot Diameterincreasenot over 2%of OD over 3% of OD over 4% of OD E. Conosion,cuts, and gouges 1. Corrosion Remaining wall not less Remainingwall not less Remaining wall not less than 87V2% than 80% than 70% 2. Cuts and gouges LLmgitudiUal Remaining wall not less Remainingwall not less .. Remauung wall not less than 87V2% than 80% than 70% TaSeS rnvre not Remaining wall less Remainingwall not less .. Remauung wall not less than 87V2% than 80% than 80% F Cracks . None None N m ~ IL INTERIOR CONDITIONS (Tube and Upset) A. Corrosivepitting Wall Remainingwall not less Remaining wall not less Remaining wall not less than 871/2%measured than 80% measured h m than70%measuredhm h m base of deepest pit base of deepest pit base o deepest pit f B. Erosion and wear Wall Remaining wall not less less Remaining wall not Remaining wall not less than 87V2% than8096 than 70% API dimensions I l l a inch Am dimensions Y, ,inch API dimensions V I 6 inch less than specified b r d oe less than bored lesthans@edbored ID ID ID D cracks4 . None None None h criticalservice classilìcation is recommendedfor service wherr:new or like new specifications apply. Criticalservice classification tubing work strings shall Te be identifìed with one white band The pu classification is recommended for service where it is anticipated that torsionor tensile limits for class 2 tubing work strings will be exceeded Re- m im m classification tubing work strings shall be identilied with two white bands. im %emaining wall shall not be less than the value in I.E.2. Defe& may be ground out providing the mmaining wall is not reduced below the value shown in LEA of this table and such grinding to be approximately faired into outer contour of the tubing. any classification where cracks or washouts appear,the tubing w ideutiíied with red band and lbe i the consideredunfit for fuaher service. sAverage adjacent wall is determinedby measuring the wall thickness on each side f the cut or gouge adjacent the deepest penetration. o to 6Applidleto Intemal Upsets which have been boredCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D - A P I / P E T R O RP 7G-ENGL L998 m 0732290 Ob09788 5b8 m 118 API RECOMMENDED R A m C E 7 6 P - Table 26"Hook-Load a MinimumYield Strength for New, Premium Class (Used), and C a s 2 (Used)Drill Pipe t ls NW C class2 l b l A i n . i l L i n . S q . i n . p s i lb ia i. n S. qh % lb in. in. Sq.in. % lb 4.85 2375 0.190 1.9950.152 1.304278.61 75000. 97817. 2.2990 1.0252 76893. 22610 0.133 0.8891 68.17 66686. 95000. 123902 97398. 84469. 105000. 136944. 93360. 107650. 176071. 135000. 6.65 2375 0.280 1.815 1.8429 75000. 138214. 22630 0.224 1.4349 77.86 107616. 227 .00 0.1% 1.2383 67.19 92871. 175072. 95000. 1 1oMoo. 193500. 150662 130019. 167167. 135000. 248786. 193709. 6.85 2875 0.217 24 41 1.8120 0.174 75000. 78.69 135902. 2.7882 1.4260 106946. 27448 0.152 1.2374 68.29 92801. 172143. 95000. 190263. 105000. 135000. 244624. 167043. 192503. 274 10.40 2875 0362 2.151 28579 75000. 214344. 2.7302 0.290 22205 77.70 166535. 26578 1.9141 0.253 143557. 66.97 95000. 271503. 210945. 181839. 105000. 300082 233149. m0 8. 135000. 385820. 299764. 258403. 1 3.500 9.50 0.254 2992 25902 75000. 194264. 3.3984 0.243 20397 78.75 152979. 3.3476 0.178 1.7706 6.6 83 132793. m 246068. . 193774. 168204. 105000. rimo. 214171. 185910. 135000. 349676. 275363. 292. 307 13.30 75000. 3.500 0.368 2.764 3.6209 nm1 . 3.3528 0.294 28281 78.12 212150. 3.2792 o m 24453 183398. 67.53 95000. 343988. 268723. 232304. 1oMoo. 380197. 297010. 256757. 135000. 488825. 381870. 330116. 1550 3500 0.449 2602 43037 75000. 322775. 33204 0.39 3.316 7.5 76 mm. 3.2306 0.314 287% 66.91 215967. m 484. . 088 317452 rims. 1oMoo. 451885. 350868. 302354. 135000. 580995. 451115. 388741. 4 11.85 A000 0.262 230755. 3.476 3.0767 75M)o. 3.8952 0.210 24269 78.88 182016. 3.8428 0.183 21084 68.53 158132 m 229. . 920 230554. 200. 031 105000. 323057. 254823. 221385. 13"). 415360. 3n630. 284638. 4 14.00 3.8048 4.000 75000. 0.330 285359. 3.340 3.8680 024 .6 29891 78.56 224182 3 . m 0.231 25915 68.11 194363. 95000. 361454. 283%3. 246193. 105000. 399502 313854. 272108. 135000. 513646. 4433527. 349853. 4 15.70 75000. 4.000 0.380 3.240 4.3216 324118. 3.8480 034 .0 3.3847 3.7720 78.32 253851. 026 .6 29298 67.80 219738. m. 410550. 321544. 278335. 105000. 453765. 355391. 307633. 135000. 583413. 456931. 395526. 13.7575000. 4.500 0.271 3.958 3.6005 nom. 4.3916 0.217 28434 78.97 213258. 43374 0.190 24719 68.65 185390. m. 342043. nom. 234827. 105000. 378047. 298562 294. 556 135000. 486061. 383865. 333702COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL 1998 m 0732290 Ob09789 4T4 m RECQMMENDEDPRACTICE FOR DRILL STEM DESIGN OPERATING AND L” 119 Table 2Wook-Load at MinimumYield Strength for New, Premium Class (Used), and Class 2 (Used) Drill Pipe (Continued) in. Ib/An i. i. n in. s: . qi n psi lb in. in. sq. in. I lb i n in. s.in. q % lb 4V2 16.60 75000. 0.270 4.2978225771. 4.500 330558. 78.70 0.236 0.337 3.826 4.3652260165. 68.30 4.4074 3.4689 3.0103 418707. 95000.364231. 462781. 105000. 595004. 135000. 4’1, 20.00 4.500 0.430 3.640 5.4981 4.3280 322916. 67.78 75000. 0.344 4.2420 279502 412358. 78.31 0.301 4.3055 3.7267J 522320. 95000. 409026. 354035. 452082 lo”). 577301. 742244. 135000. 4V2 22.82 75000. 4.500 471239. 0.500 3.500 6.2832 4.3000 040 .0 4.90094.2000317497. 78.00 0.350 367566. 67.37 4.2333 596903. 95000. 659735. 105000. 848230. 135000. 5 16.25 75000. 0.237 4.8224 5.000 328073. 78.99 0.207 0.296 4.8816 4.408 4.3743 3.4554 3.0042 259155. 68.68 225316. 415559. 95000. 459302 1Mooo. 590531. 135000. 5 19.50 75000. 0.290 4.7828 270432 5.000 395595. 78.75 0.253 0.362 4.276 4.8552 311535. 68.36 5.2746 4.1538 3.6058 501087. 95000. 553833. 105000. 712070. 135000. 5 25.60 75000. 5.000 530144. 0.500 4.000 4.8000 7.0686 040 .0 5.5292 4.7000 358731. 78.22 0.350 414690. 67.67 4.7831 525274. 9500. 671515. 580566. lo”). 742201. 954259. 135000. 19.20 75000. 0.243 5.3176 5.500 372181. 79.06 0.213 0.304 5.3784 4.892 4.9624 3.9235 3.4127 294260. 68.77 255954. 471429. 95000. 521053. 105000. 669925. 135000. 21.90 75000. 0.289 5.2834 299533. 5.500 437116. 78.88 0.253 0.361 4.778 5.3556 344780. 68.52 5.8282 4.5971 3.9938 553681. 95000. 611963. 105000. 786809. 135000. 24.70 75000. 0.332 5.2510 5.500 497222. 78.69 0.290 0.415 5.3340 4.670 6.62% 5.2171 4.5271 391285. 68.29 339533. 629814. 95000. 696111. 105000. 894999. 135000. 25.20 75000. 6.625 489464. 0.330 6.4930 5.965 6.5262 0.264 5.1662 6.427068.90 79.16 0.231337236. 387466.4.4965 619988. 95000. 685250. 105000. 881035. 135000. 607026. 27.70 75000. 0.290 6.4078 367455. 6.625 534199. 79.08 0.253 0.362 5.901 6.4802 422419. 68.79 7.1227 5.6323 4.8994 676652. 95000. 747879. 105000. %1558. 135000. COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
    • S T D - A P I I P E T R O RP 7G-ENGL L998 m 0732290 Ob09790 L L b m 120 PRAcnc€76 API RECO~~MENDED inmin in in.sq.in psi Ib in in qi.n % lb in in s. qh % lb 0.3326 0.824 0.113 1.050 55000. 18295. 1.20 1.0048 000 .9 0.2597 14283. 78.07 0.9822 0.2244 0.079 12343. 67.47 75000. 24948. 19477. 16832 800 00. 2661 1. 20775. 17954. 105000. 34927. 27267. 23564. 1.50 1.050 0.154 0.742 0.4335 55000. 23842. 0.9884 0.123 0.3349 77.25 18418. 0.9576 0.108 0.2878 66.39 15829. 75000. 32512 25115. 21585. 800 00. 34679. 26790. 204 32. 105000. 45516. 35161. 30219. 1.80 1.315 0.133 1.049 0.4939 55000. 27163. 1.2618 0.106 0.3862 78.20 21242 1.2352 0.093 0.3340 67.64 18372 75000. 37041. 28%6. 25053. 800 00. 39510. 30897. 26724. 105000. 51857. 40552 35075. 225 1.315 0.179 0.957 0.6388 55000. 35135. 1.2434 0.143 0.4950 77.48 27222 1.2076 0.125 0.4260 66.69 23432 75000. 47912 37122 31953. 800 00. 51106. 395%. 34083. 105000. 67077. 51970. 44734. 240 1.660 0.140 1.380 0 6 8 .65 55000. 36769. 1.6040 0.1 12 0.5250 78.53 28873. 1.5760 0.098 0.4550 68.07 25027. 75000. 50140. 39373. 34128. 80000. 53482 41998. 36403. 105000. 701%. 55122 47779. 3.02 1.660 0.191 1.278 0.8815 55000. 48481. 1.5836 0.153 0.6868 77.92 37776. 1.5454 0.134 0.5930 67.27 32613. 75000. 66110. 51513. 44472 80000. 70517. 54947. 47437. 105000. 954 25. 72118. 62261. 3.20 1.660 0.198 1.264 0 9 9 .04 55000. 50018. 1.5808 0.158 0.7078 77.83 38930. 15412 0.139 0.6107 67.16 33590. 75000. 626 80. 53087. 45805. 800 00. 72753. 56626. 48858. 105000. 95489. 74322 64126. 29 .0 1.900 0.145 1.610 0.7995 55000. 43970. 1.w.o 0.116 0.6290 78.68 34595. 1.8130 0.101 0.5457 68.26 30016. 75000. 59959. 47175. 40931. 1 800 00. 63957. 50320. 43660. 105000. 83943. 66045. 57304. 4.19 1.900 0.219 1.462 1.1565 55Ooo. 63610. 1.8124 0.175 0.9011 77.92 49562 1.7686 0.153 0.m9 67.26 42787. 75000. 86741. 67584. 58345. 80000. 92523. 72090. 62235. 1owW)o. 121437. w1a 81684. 3.25 2Vs 2063 0.156 1.751 0.9346 55000. 51403. 20006 0.125 0.7354 78.69 4 4 0 1.9694 0 5 . 0.109 0.6382 68.28 35099. 75000. 70095. 55158. 47862 800 00. 74768. 58836. 51053. 105000. 98133. 71222 6m07. Z3/a 4.70 2375 0.190 1.995 13042 55000. 71733. 22990 0.152 1.0252 78.61 56388. 22610 0.133 0.8891 68.17 493 80. 75000. 97817. 76893. 666 68. 800 00. 104339. 82019. 71132 lQso00. 136944. 107650. 93360. W a 2.375 5.30 0.218 1.939 1.4773 55ooo. 81249. 2.2878 0.174 1.1579 78.38 63686. 2.2442 0.153 1.0027 67.88 55150. 75000. 110794. 86844. 75205. 80000. 118181. 92634. 80218. 105000. 155112 121581. 105286.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D - A P I I P E T R O RP 7G-ENGL L998 m 0732290 Ob09791 052 W RECOMMENDEDPRACTICE FOR DRIUSTEM DESIGN N OPERATING LIMITS AD 121 Table 274ook-Load at Minimum Yield Sren @r New Premium Class (Used), and Class 2 (Used) Tubing Wo Stnngs (Cbntnued) P (Hookloadvaluesinthistablerary~~yfromtcnsiledf~~samem~sizeandclasslistedin(5) (4) (3) (2) 0) (9) (18) (8) (17) (16) (15) (14) (11) (10) (13 (12) NW C Remiurnclass class2 8 W in. in. Ib"A in. ia qin. psi lb in. in. sq.in. % lb in. in. qi .n % lb 5.95 2375 0 2 4 1.867 0.203 . 5 1.6925 78.08 55000. 93087. 2.2734 1.3216 72686. 22226 0.178 1.1422 67.49 62820. 126936. 75000. 105725. 80000. 135399. 177711. 105000. 6.50 2875 0.217 2.441 1.8120 55000. 99661. 2.7882 0.174 1.4260 78.69 76427. 27448 0.152 1.2374 68.29 88054. 75000. 135902 92801. 106946. 80000. 144962 98988. 114076. 190263. 105000. 129922 21 7, 8.70 2875 0.308 2.259 2.4839 55000. 136612 2.7518 0.246 1.9394 78.08 106667. 26902 0.216 1.6761 67.48 92186. 186289. 75000. 8M0 198708. 0 1. 155152 134089. 105000. 260805. 203637. 175992 28 1 9.50 2875 0 3 0 2.195 2.7390 2.6710 . 4 2.7077 0.272 0.238 55000.2.1081 1.8192 148926. 77.85 67.18 115945.100053. 203080. 75000. 168647. 80000. 216619. 145532 284313. 1050M). 271a 10.70 2875 0.392 168180. 2.091 3.0578 55000. 27182 0.314 23690 77.47 1302%. 26398 0.274 20391 66.68 112151. 229337. 75000. 177~~76. 152933. 80000. 244626. 189522 163128. 105000. 321072 214106. 248747. 271a 11.00 2875 0.405 2.7130 2.6320 2.065 0.324 0.283 3.1427 2.4317 55000. 77.38 172848.133744. 20917 66.56 115042 235702. 75000. 194536. 80000. 251415. 329983. 105000. 12.80 199151. 3.500 3.3528 0.368 2.764 3.6209 0.294 55000. 28287 78.12 0.258 155577. 3.2792 24453 67.53 134492. 271569. 75000. 226293. 800 00. 289674. 380197. 105000. 3V2 12.95 202485. 3.500 3.3500 0.375 2.750 0.300 3.6816 55000. 28746 78.08 0.263 158101. 67.48 3.2750136637. 2.4843 276117. 75000. 80000. 294524. 229965. 260853. 105000. 386563. 301828. 3V2 15.80 55000. 0.381 3.2144 3.500 248715. 77.48 0.333 0.476 2.548 3.3096 4.5221 3.5038 3.0160 192708. 66.69 165879. 339156. 75000. 80000. 361767. 280302. 241278. 474819. 105000. 3V2 16.7055000. 3.500 263484. 0.510 3.2960 2.480 4.7906 0.408 3.7018 0.357 77.27 3.1818 2035%. 66.42 3.1940 17Mo1. 3592%. 75000. 296140. 80000. 383249. 503015. 105000. 4V2 15.5055000. 4.500 0.337 3.826 4.4074 220. 449 4.3652 4.2978 0.270 0.236 3.4689 3.0103 78.70 68.30 190788.165565. 260165. 330558. 75000. l. 277509. 80000. 352595. 364231. 105000. 462781. 19.2055000. 4.500 0.430 3.640 5.4981 3023%. 4.3280 4.2420 0.344 0.301 4.3055 3.7267 78.31 67.78 236805. 204968. 412358. 75000. 344443. 800 00. 439848. 577301. 105000. COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
    • STD.API/PETRORP7G-ENGL L998 0732290 Ob09792 T99 122 API REC~MMENDED PRACTlCE 76 13.2.6 InspectionClassificationMarking 13.3.2.1 Required Inspections Following are required inspections: A permanent mark or marks signifying the classification of the pipe (for example, refer to Table 24, Note 1) should be a Outside diameter measurement-measure tool joint out- stamped as follows: side diameter at a distance of 1 inch from the shoulder and determineclassificationfrom data in Table 10. Minimum a On the 3 5 d e p or 18degree sloping shoulder of the . pin shoulder width should be used when tool joints are worn end tool joinL eccentrically. b. Or in some other low-stressed section of the tool joint b. Shoulder conditiowheck shouldersforgalls,nicks, where the marking normally carry through operations. will washes, fìns, or any other matter which would affect the pressure holding capacity of the joint and conditions which c. Cold steel stenciling should avoided on outer surface of be has may affect joint stability. Make certain joint a minimum tube body. 1/32in. x 45 degree OD shoulder bevel. d. One center punch denotes premium,two denote Class 2 and three denote Class 3. 13.3.2.2 Optional Inspections Following are optional i s e to s n p ci n : 13.3 TOOLJOINTS a Shoulder width-using data in Table 10, determine mini- mumshoulderwidthacceptablefortool joint in class as 13.3.1 Color Coding governed by the outside diameter. b. visual thread inspectioMe t r a profile is checked to hed The classification system for used drill pipe outlined in detect over-torque, imd3ìcient torque, lapped threads, and Table 24 includes a color code designation to identify the drill stretching. Threads are visually inspected to detect handling pipe class. The same system is recommended for tool joint damage,corrosion damage and galling. class identification. In addition, it is recommended that the c. Box swell a d r pin stretch-these are indications of no tool jointbe identified as (1) field repairable,or (2) scrap or over-torquingandtheir presence greatly affects the future shop mpaimble. This color code system for tool joints and performance of tool for the joint The lead gauge the onlystan- is drill pipe is shown in figure 85. dard method for measuring stretch. On used tool joints, pin it is recommended that pins having stretch which exceeds 0.006 13.3.2 Inspection Standard inch in 2 inches should be recut Al pins which have been l stretched should inspectedfor c a k . be rcs The followingrecommended inspection standard for used It is recommended ta box counterbores (Qc),API Speci- ht tool joints initially included an appendix to Am Speci- was as fication 7, Table 25, be checked. If the Qc diameter is more fication 7. It was moved to Am Recommended Practice 7G than 0 0 1 inch inch) outside the allowed tolerance, .3 then by committee action at the1971 StandardizationConference. the box should be recut. Tool joint condltion bands Classificationpaint bands for drill pipe and tool joints ” LStencils for permanentmaking for classification o drill pipebody f l’&lJointandDrill NIUlltUdcolca ’bolJoint Ca o l PipeClassiscation dB& condition o Bauds f Remilrm class ...............m white ScrapaShopRepairable ............ Red class 2. .................... one Y l o elw Field Repairable. ................. .Green class 3 . .................... oneorange scrap ........................ .oneRed Figure 85-Drill Pipe and Tool Joint Color Code IdentificationCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD-APIIPETRO RP 7G-ENGL 1998 m 0732290 Ob09793 925 m RECOMMENDEDPRACTICE FOR DRIU STEM DESIGN OPERATING LIMITS AND 123 d Magnetic particle inspection"if evidence of pin stretch- The use of other types of tongs,or devices designed the for ing is found, magnetic particle inspection should be of made purpose of making and breaking c o ~ e c t i o lmay require a l~ the entire pin threaded especially the last engaged thread Werent minimum tong space than what would be deter- area, area,todetermineiftransversecracksarepresent. mined for manual tongs. In this case, the user should apply In highly stressed drilling environments orif evidence of the criteria necessary to ensure that the intent recom- of this damage, such as cracking is noted, magnetic particle inspec- mendation is satisfied. tion should be made of the entire box threaded a e , espe- ra Such minimum tong space should not be construed as a cially the last engaged thread area, to determineif transverse means by which tool jointsare acceptable or not with regard to the strength or integrity of the connection as otherwise cracks are present. this specified in recommended practice. Longitudinal or irregular orientation of cracking occur may as a result of f i t o heat checking (see 8.6). In that case rcin 1.. General 333 magnetic particle inspection of both box and p n tool joint i surfaces, excluding any hardband area, should be performed, a Gauging-wear, plasticdeformation,mechanical with an emphasis detection of longitudinal cracks. on damage and lack of cleanliness may contribute to errone- all ous figures when plug and ring gauges are applied to used For crack detection, the wet fluorescent magnetic particle connections. Therefore, ring and plug standoffs should not be method is preferred for tool joint inspections. Tool joints used to determine rejection r continued use ofrotary shoul- o found to contain cracks in the threaded areas or within the deml connections. tool joint body, excluding any hardband should be con- area, b. Repair of damaged shoulders-when refacing a darn- sidered unfitfor further drilling service. Shoprepair of some aged tool joint shoulder, a minimum of material should cracked tool joints may be possibleif the unaffected area of be removed. It is a goodpractice to remove not more than the tool joint permits. body /,,-inch from a box or pin shoulder at any one refacing e. Minimum tong s w f e r to Figure 86. The criteria for and not more than /,,-inch cumulatively. determining theminimum tong space fortool joints on used It is suggested t a a benchmark provided for the deter- ht be on drill pipe shouldbe based safe and efficient tonging opera- mination of the amount of material which may be removed tions on the rig floor, primarily when manual tongs use. are in This from the tool joint makeup shoulder. benchmark should In this regard, there should be sufEcient tong space allow to be applied to new or recut tool joints after facing to gauge. fl engagement ofthe tong dies, plus adequate amount of ul an The form of the benchmark be a 3/,sinch diameter circle may tong space remainingo allow the driller andor floorhand to t with a bar tangent the circle parallel the makeup shoul- to to visually verify that the mating shoulders connection are of the 86. der, as shown in Figure The distance from the shoulder to unencumbered to allow pmper make-up or break-out of the the bar should be V,, inch. Variations of this benchmark or connection without damage. other type benchmarks maybe available from tool jointman- It is also recommended that any hard banded surfaces of ufacturers or machine shops. the pin or box tool joint tong space be excludedfrom the area of tong die engagement stated above when as minimum tong 13.3.4 Coverage I space is detemined. This practice w l ensure t a optimum li ht Figure 84, dimension A, indicatesthelengthcovered gripping ofthe tongs achieved and that damage to tong dies is under the drill pipe classification system recommended in is minimized. In the case where tool joint diameters have 13.2.5.Figure 84, dimension B,indicates the length covered been worn to the extent that the original hard banding has under the tool joint inspection standard in 13.3.2. The length been substantially removed, the user may include this area in notcoveredbyinspectionstandards is indicated under a determining the minimum tong space. CAUZON heading by dimension C, Figure 84.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services Figure 86-Tong Space and Bench c Mark Position
    • 124 API RECOWENDED PRACTICE 76 13.4 DRILL COLLAR INSPECTION PROCEDURE bore of the elevator shouldl o be checked and corrected at as t i time as excessive slack between collar gmove diameta hs inspection produre for useddrill collars is The following and elevator bore decreases shoulder suppoa area and can recommended: shift also let too much load to the elevator door. a VhaUy inspect full length to determine obvious damage . 13.5.4 The following inspection procedure for drill collar condition. and overall is handling systems recommended: b. Measure OD and ID of both ends. C. T h ~ ~ ~ ~cleanl box and pin t r a s Follow immedi- gh y hed. a Thoroughly clean and examine elevator adapter for cracks. ately with wet fluorescent magnetic particle inspection for b. Check links (commonly called bails) for cracks and mea- detection of cracks. A magnifying minor may be used in sure them eye to eye to be c r a n they are within l inch of eti crack detection of the box t r a s Drill collars found to con- hed. being the same length. tain cracks should be considexedunfìt for further drilling c. Thoroughlycleanandexamine drill collarelevator for service. Shop repair of cracked drill collars is typically possi- cracks with magnetic particle inspection. Make certain that ble if the unaffected area of the drill collar p r i s emt. elevatorsafetylatchworkseasilyandworkseverytime. d. Use a p 6 l e gauge to check thread form andto check for Check top seat of elevator to be certain it is square. Check stretched p n . is elevator top bore as follows: e. Check box counterbolediameter for swelling.In addition, 1. Center-latch elevator-latch elevator, then wedge front useastrai~tedgeonthecrestsofthethreadsinthebox and back of elevator open and measure a largest part of t checkingforrockingdue to swellingofthe box. Some top bore straight across between ln am . This method ik r s machine shops may cut box counterbores larger t a API hn will m a u e total wear in bore (of which there will be esr sna stherefm, a check of the diameter of the counter- adr , t d on very little), and wearhinge pin and latch u f c s Wear srae. bore may givea misleading result. should not be allowed to go above ‘/,,-inch on elevators for 5V8-inches and smaller drill collars, and VI6inch for f. Check box andpin shoulders for damage. field repair- All drill collm larger than 5’/8-inche~. able damage shallbe repaired byrefacingandbeveling. Ehcessive to shoulders should be repaired in reputa- 2. S i d e d m elevators-latch elevator, wedge then latch - ble machine shops with standard gauges. open. Measure top bore h m h nto back. Use same t API allowance wear center-latch as for elevators. I d. Check elevator shoulder on drill collar to be certain it is 13.5 DRILL COLLAR HANDLING SYSTEMS s u r . (See 13.4for inspection procedure for the cla. q ae drill olr) 13.5.1 While the recent increased usageofgrooved drill e. Examine drill collar slips for general condition and for collars has helped save time in tripping, it has i n- & correct size range for the collars being r n Look for cracks, u. some potential dangen to rig floor operations. These p - b missing cotter keys, loose liners, dull liner teeth,bent back lemscanbeminimizedbystdctadherencetoregthlysched- tapers ( h m catching on drill collar shoulder),and bent uledinspections. handles. f.Examine safety clampforgeneral condition. Look for 136.2 When the elevatorshoulda on a drill collar is new it cracks, missing cotter keys, galled or stlipped threads, is square and has sufficient area in contact w t the elevator. ih munded-off nuts or wrenches, dullteeth,bmken slipsprings, (See Figures 87 and 88, and ‘Wle 2 fa suggested dimen- 8 and slips that do not move up and down easily. sions on new drill collars and elevators.) As the collar is used for drilling, however, it wears as shown in Figure 89. Elevator contact area is decreased by collar OD wear and elevator spreading load is increased by angle and radius W d u p on the collar and cOrzeSpOnding w t x on the elevator Seat. Hevator capacity is drastically reduced by spleading action as most all drill collar elevators are intended for use with square shoulders only. As an example, withl/,,-inch wear on the collar OD, 1/32- inch radius worn on the comer, and a Sdegree angle on the shoulder, elevator capacity be reduced byas much as 40 t can o 60percent., depending on collar size and elevatore i n dsg. 13.5.3 Before this danger point is reached, the collar and elevator should shopped and the shoulders brought back be to a square amdition. Be very sure the elevator shoulderradius on the driU collar is cold worked when shoulderis m r e . ok d (See section 14 for welding procedure l m t t o s ) The top iiain. Figure 874rill Collar ElevatorCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • RECOMMENDED FOR PRACTICE DRU STEM DESIGNAND OPERATlNG L" 125- OD +1116 maximum Figure 88-Drill Collar Grooves for Elevators and Slips Table 28-Drill Collar Groove and Elevator Bore Dimensions 13.6 KELLYS i - Original drill I kellys: size collar The following inspection procedure is recommended for used I a Follow a l steps listed in 13.4 for drill collar inspection l Worn drill collar PIocedUre- b. Examine junction between upsets and drive section for cracks. c. Check comers of drive section for narrow wear surface particularly on hexagonal kellys. If wear surface does not extend a least V 3 -SS t flat, the kelly drive bushings should be adjusted if possible andor examined for wear. d. Kelly straightness can checked eitherf two ways: be o 1. Bywatching for excessive swing of the swivel and traveling block while drilling, or 2. By placing square kellys on level supports (one a each t end of drive section), stretching a heavy cord from one end ofa vertical face of the squareo the other, t measuring deflection, rolling kelly 90 degrees, and repeating proce- dure. On hexagonkellys,usethesamemethodexcept 4% kelly will need to be placed in 120degree V-blocks so side face of drive section is vertical and deflection mea- surements taken on t r e successive sides (turning kelly he I Figure 89-Drill Collar Wear through 60 degrees each time). ICOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD-APIIPETRO P R ?G-ENGL L998 m 0732290 Ob09796 634 126 API RECOMMENDEDPRACnCE 7 6 13.7 RECUTCONNECTIONS rental tools, a modified pin stress relief groove is recorn- The following is recommended for recut connections: mended. It is recommendedt a the modified pin stress relief ht groove conform to Figwe 9 .Dimensions forDm are found 0 a When rotary shoulderedconnections are inspectedand in Table 16 of API Specification7. found to qr recutting, the recut u ie connection should comply c. Recommended initial width of the modified stress relief with the requirements of the section entitled “Gauging Prac- groove is 3/4 (+Vl6, 4)inches. After reworking for damaged tice, Rotary Shouldered Connections” of API Speciscation 7. t r a s and shoulders, the width of the modified relief hed stress b. It is recommended that a benchmark be applied to the l1I4 groove should not exceed inches. recut connection suggested in 13.3.3.b. as d. Technical data-stms at theroot of thelastengaged thread of the pin depends on the width of the stress relief 13.8 PIN STRESS RELIEF GROOVES FOR groove (SRG). Table 29 shows calculated relative stresses for RENTALTOOLS AND OTHER SHORTTERM an NC50 axisymmetric finite element model with 6V,-inch USAGETOOLS box OD and 3-inch pinD A pin with no stress relief groove I. Following are recommendations for pin stress relief is the basis for comparison. grooves for t l and other short usage tools: ma term Table 29”aximum Stress at Rootof Last Engaged a Laboratory fatigue tests and tests under actual service con- Thread for the Pin of an NC50 hisymmetric Model ditionshavedemonstratedthebeneficialeffectsof stress relief contours at the pin shoulder. It is recommended t a .ht, Load condition Note 1 Note 2 where fatigue failures at pointsf high stress are a problem, o SRG Mx u amm Maximum i uaxirmun M mm ai u x relief grooves beprovided. Rental components suchas subs, width, E4ylivalent Axial Equivalent Axial drilling jars, vibration dampenem, stabilizers, m e r s , etc., inches StreSS stress stress Stress are usuallyemployed for relativelyshort periods of time % 84% 82% 83% 81% before being returned to service centers for inspection and 1 70% 56% 63% 53% repair. Connection repairs are made primarily because of gall- 11 1. 75% 63% 73% 64% ing,shoulderleaksandhandlingdamageswhile repairs caused by fatigue failures secondary in occurrence. are No SRG l m 100% 100% 100% providers of short term usage rental tools havebeen reluc- Notes: tant to take advantage of the benefits of stress relief grooves 1 Make-up only at 562,000 pounds axial force OII shoulder. . because of the material loss in repairing shoulder andt r ahed 2 1 1 5 0 0 pounds axial~ O Iapplies t~ connection Which clulse~ u .,2,0 I bl - damage. Refacing the pin shoulder and reconditioning the das p r t o . eaain threads is restricted by the tolerance the groove width per on 3.Equivalentstressisequalto0.707[(~-~+(~-q)2+(~-~~’R u ,q, q are principle stresses. , and Am Speciscation7. 4.Ineachcsseshown,equivalentstressattherootoftheLestEngaged b.To encomge the use of stress relief grooves on pins of l’?mxdhasexceededtkyieldstrengthbecausethesefmiteelementcalcula- short term usage tools, the following is recommended. For ti~hanbeeamadeforliacarelasticmataialbeha~~.~Thebehaviorofan tools returned to a service facility after each well, such as actualpin is elastic-plastic. I Nab:~’Igble16ofAPISpecificstion7 forDimensimDm Figure 9O“odified Pin Stress-Relief GrooveCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D = A P I / P E T R O RP 7G-ENGL L998 m 0732290 Ob09797 570 REC~MMENDED PRACTICE FOR DRIU STEM DESIGNAND OPERATING LIMITS 127 Note that the least is expected for a groove of 1 stress width 16 Classification Size and Make-up inch. Consequently, inoperations where fatigue failures a are Toque for Rock Bits problem, a groove width of 1inch isrecommended. (SeeFig- ure 16 of API SpecXcation 7.) 16.1 A classi6cationsystemfordesignating roller cone rock bits according to the of bit (steel tooth insert), the type or 14 Welding on Down Hole DrillingTools type of formation drilled, and mechanical features of the bit, 14.1 Usually the materials used in the manufacture downof was developed by a special subcommittee within the Inter” hole drilling equipment (tool joints, drill collars, s a i i e s tblzr tional Association of Drilling Contractors (IADC). The sys- and s b ) AISI-4135,4137,4140, o 4145 steels. u s are r tem was accepted by IADC in March 1987 and approval by API was proposed by the IADC subcommittee. Following 14.2 These are alloy steels and are normally in the heat API task group review it was recommended that A P I accept treated state, these materials are not weldable unless proper this system of classificationforbitdesignation.Thetask procedures are used to prevent cracking and to recondition the p u p recommendation was adopted by the Committee on sections where welding has been performed. Standardization of DrillingandServicingEquipmentand subsequently approvedby letter ballot. It was further deter- 14.3 It should be emphasized ht areas welded can only be ta mined that the approved form be included in API Recom- reconditioned and cannot be restored to their original state mended practice 7G. free of metallurgical chauge unless a complete heat treatment is performedafter welding, which cannot be done field. in the 16.2 Bits’maybeclassifiedanddesignatedbyanalpha- numeric code on the bitcarton with a series t r e numbem of h e 15 Dynamic Loading Of Drill Pipe and one letter keyed to the classification system shown in Note: For quantitative rmdts, see Refmœ 15, Appendix C. Tables 30 and 3l. 15.1 When running a stand of drill pipe into or out of the 16.3 Series numbers 1, 2, and 3 are reservedformilled hole, the pipe is subjected not to its static weight, but to a tooth bits in the medium, andhard formation categories. soft, dynamic load. Series numbem 4,5,6,7, and 8 are for insert bits in thesoft, 15.2 The dynamic loadoscillates between values whichare medium, hard, and extremely formations. hard greater and smaller than the static load (the greater values may exceed the yield), which resultsin fatigue, i.e., shorten- 16.4 Type numbers 1 through 4 designate formation hard- ing of pipe life. ness subclassificationfrom softest to hardest w t i each ihn series classification. 15.3 Dynamic loadingmay exceed yield in longstrings, such as 1, O feet. 0 O O 16.5 Thesevencolumnlistingsundertheheading,Fea- tures, include seven features common to the milled tooth and 15.4 Dynamic loadingincreases with the length ofdrill col- i s r bits ofmost m n f c u e s Columns 8 and 9 have been net auatrr. lar string. removed and reserved for future bit development. 15.5 In theeventthesmallestvalueofthedynamicload tries to become negative, thepipe is kicked off the slips, and 16.6 The form is designed to include only one manufac- the string may be dropped into the hole. turer’s listingon each sheet, and allow each specific bit to des- ignation in only one classi6cation position. It is mxzdg eu , 15.6 Thelikelihoodofdynamicloadingresulting in a however, t a many bitswr l efficiently in a range of types ht ld i l l i jumpoff (kicking of the slips) increases as the drill pipe and perhaps in more than one series. Particular attention is string becomes shorter and the collar string becomes longer. therefore invited to the note on the form which contains a 15.7 For a long drill pipe string, such as l0,OOO feet, a statement ofthis principle. Itis the responsibility of the manu- jumpoff is possibleonly if drill pipe,afterhavingbeen facturer and user to determine the range efficient use in spe- of pulled from the slips, dropped at avery high velocity, such is cific instances. as 16 Wsec. 16.7 I using the form shown in Table 30, in conjunction n 15.8 Dynamic phenomena are severe only when damping with Table 3 1, the manufacturer assigns to each bit design is small, whichmay be the case in exceptional holes, in three numbers and one letter that correspond with aspedìc which there are no doglegs, thedeviation is small, them s s - block on the form. The sequencebe followed is: to sectional area of the annulus is large, and the mud viscosity Frt number designates Series. is and weightare low. Second number designates m. 15.9 In case of small damping, the running time of a stand Third number designates Feature.. of drill pipe should notbe less than 15 seconds. Letter designates additional features, shown in Table1. as 3COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL L998 m 0732290 Ob09798 407 m 128 API REC~MMENDED PRACTICE 7G sapas m m OQ ijg P œ ICOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD-APIIPETRO RP 7G-ENGL L998 m 0732290 Ob09799 3 4 3 m RECOMMENDED PRACTICE FOR DRIU STEM DESIGNAND OPERATING LIMITS 129 Table 31"IADC Bit ClassificationCodes Table 32"Recommended Make-up Torque Ranges Fourth Position for Roller Cone Drill Bits Thefollowingcodesareusedinthe4thpositionofthe4-character Mi u imm n Mx u ai m m IADC bit classification code to indicate additional desien features: Make-upT r u oqe Make-upTorque COdeFeature COdeFeature connection Mb Mb A Air apiain plcto N B O C C n e Jet etr P D DeviationControl Q E kteudedJe& R ~r welds3 ed nie o fc F S sa d r steel ~ 0 0 t h~ode14 t n ad G Ex&aGauge/BodyRotection T H .. V I V J JetDefldon W K x ChiselInSerts L Y W al x C ls t I M z OtherIllsxtShapes Note: Basisofcalculationsforlecommendedmake-uptorq~assumedtheuse Journal bearingbits wt air circulationnozzles. ih of a thread compound containing 0to 60 percent by weightof finely 4 2Full extension (weldedtubes wt nozzles). wmal extensions should ih be noted elsewhere. powdenxi metallic zinc or 60 percent by weight of finely powdered 3 F o r percussion applidons. metallic lead, with not more than 0 3 percent total active . applied 4 M i l l e d tooth b t w t nune of the extra features listed in this table. is ih thoroughly t all threads and shoulders(see the caution regarding the use o As an example,a d toothbit designed for t e softest s r s softesttype ed h e , e i ofbazradoPsmaterialsinAppendixGofAPISpecificafion7).Duetothe- in that s r e ,wt standard gauge,and no exirafeatures. will be designated e i s ih 1-1-1-S on the bit calton.The manufacturerwill also list this bit designation imgular geometry of the ID bore in r l e cone bits, torque valves are olr b s d on estimated cross-sectional ateas and have been proven by field ae inthisblockontheform experience. 16.8 Classification forms a e available h m : International r 16.10 Common sizes for roller bits are listed in Table 34. Association of Drilling Contractors (IADC), P.O. Box 4287, Sizes other than those shown maybe availablein limited cut- Houston, Texas 77210. ting structure types. 16.9 Recommended torque for roller cone bits isshown in Common sizes for fixed cutter bits are listed in Table 35. Table 32. Recommendedtorque for diamond drill bits is S i z e s other than those shown may be available in limited cut- shown in Table 33. ting s t r u m types.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • - Table 33-Recommended Minimum Make-up Toques Table 34-Common Roller Bit Sizes for Diamond DrillBits Size of Bit, S z o Bit ie f Bit Sub in. i. n PinID OD Make-upme conneclion in. in. M b 3% 94 234 m REG 1 1791* 3 3718 9% 2419 3M O* 4314 1W8 918 11 m3* 4617 6 12v4 4658 64 13V2 6V, 14V4 5171* 6306* @12 16 7660 @14 17V2 12451* 20 16476* 834 22 * 17551 17757 812 24 81 3, 26 371W 37857 38193 38527 Table 35-Common Fwed Cutter Bit Sizes 482w Size of Bit, S z of Bit, ie mo4* in. i. n 59966 31 7, 811, 60430 834 60895 412 912 4314 918 9111 6 1V18 6V8 12v4 6V4 14314 16 6V2 @I, 17V2 7%COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO7G-ENGL RP L998 m 0732290 Ob09803 8 2 1 H-~ APPENDIX A-STRENGTH AND DESIGN FORMULAS A.1TorsionalStrengthofEccentrically N t : To~ional oe yield strengths for Premium Class, Table 4, and Class 2, Table 6 were calculatedfrom Equation Al, using the assumption that wear is Worn Drill Pipe uniform on the externalsurface. Assume 1: Eccentric hollow circular section (seeFigure A-1). Reference: Formulusfor Stress & Strain, Roark, 3rd Edition. A.2 Safety Factors Values for various performancepperties of drill pipe are given in Tables2 through 7 The values shown minimum . are values and do not include factorsof safety. In the design of drill pipe strings, factors of safety should used as are con- be sidered necessary for the particular application. A.3 Collapse Pressure for Drill Pipe Note: See API Bulletin 5C3 for derivationof equations in k 3 . in The minimum collapse pressures given Tables 3 , 5 , and 7 are calculated values determined from equations in API Bulletin 5C3. Quatiom A.2 through A S are simplified e q ~ a - tions t a yield similar results. The Dlt ratio determines the ht since each formulais based on a specifìc applicable formula, Dlt ratio range. For minimum collapse failure in the plastic range with minimum yield stress limitations: the external pressure that generates minimum yield stress on the inside wall of tube. a ( D / t )- 1 I Figure A-1-Eccentric Hollow Section of Drill Pipe Applicable Dlt ratios for application of Equation are as A.2 follows: xS,(D4-d) Grade Dlt Ratio T = 12xl6xDxF’ E75 .............................................. 13.60andless where X95. ............................................. .12.85 and less F = I + - 4N2$ 32N2q2 + G105. ............................................. 12.57 and less (1-N2) ( 1 - N ’ ) ( 1 - $ ) S135 .............................................. 11.92andless 48N’( 1 + 2N2 + 3 h p + 2N6)q3 + For minimum collapse failurethe plastic range: in ( 1 - N ’ )( 1 - h p )( 1 - N 6 ) ’ N = dD / , q = -e PC = Y m [D /L ) - B ] - C ( t D’ T = torque, ft-lbs., S, = minimum shear strength, psi, Factors and applicable Dlt ratios for application of h a u- D = outside diameter,in., tion A.3 are as follows: d = inside diameter,in. Formula Factors Assume 2 The internal diameter, remains constant and d, Glade A B C Dlt Ratio at the nominal of the pipe throughout life. ID its 13.601806 3.054 E75 0.0642 to 22.91 Assume 3: The external diameter D is d + t nominal + t x95 3.124 0.0743 2404 12.85 to 21.33 minimum; i.e., all wear occurs on one sd.This diameter is ie G105 3.162 009 .74 2702 12.57 to 20.70 not the same diameter for as uniform wear. S135 3.278 0.0946 3601 11.92to 19.18COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • ~~ ~~ STD.API/PETRO RP 7G-ENGL L998 m 0732290 Ob09802 7bB m 132 PRACTlCE RECOMMENDED API 76 For minimum collapse faihm in conversion or transtion where zonebetweenelasticandplasticrange: r, = length offree drill pipe, R, E = modulus of elasticity,lbh.? e = differentialstretch,in., W, = weight per foot of pipe, lbdft., P = differentialpull, lbs. Factors and applicableDlt ratios for application of Equa- where E = 30 x 106, this formula becomes: tion A.4 are as follows: 735,294 x e x W,, FonnulaFactas L, = P Grade A B Dlt R t o ai E75 1.m 0.0418 22.91 to 32.05 Internal Pressure 0.0482 2.029 21.33 to 28.36 A.5 x95 G10 2.053 0.0515 20.70 to 26.89 A.5.1 DRILL PIPE 0.0615 S135 2.133 19.18 t 23.44 o p . = 2Y,t - For minimumcollapse failure in the elastic range: D where 46.95 x lo6 Pi = internal pressure, psi, P, = Y = materialminimum yield strength,psi, , - ( D / t ) [ ( D / t ) 11 t = remaining wall thickness of tube, in., D = nominal outside diameter oftube, in. Applicable Dlt ratios for application of Equation AS are as follows: (irade mt Ratio ~~~~ E75.. .......................................... 32.05 andgreater X95 ........................................... .28.36andgreater G 1 0 ........................................... 26.89andgreater 115.2 KELLYS S135. .......................................... . 34 a d r ae 2 . 4 n ge t r where PC = minimumcollapse prtsmle, p s i *D = nominal outside diameter,in., where *t = nominal wall thickness,in., Pi = internal pressure,psi, Y = , material minimumyield strength, psi. Y = material minimum yield strength, psi, , Nokc Dm. = distance across drive section flats, in., * C o l l a p s t p m s u r s f o r d d r i l l p i p e m e d lbyadjustinghenomi- t = minimumwall,in. naloutside~,D,andwallthi~f,asifthewearisuniformonthe outpideofthepipebodydtheinside"constaatvaluesof Nt:bdmniaiteiimnalhcnsotedaciad oeleiesotshmnruwltikesfhdnetmn DandtfoPeachclaasofuseddrillpipefollaw..~~are~obe~in ~bedetuminedmeachcasethroughtheuseofau~thic~ 8pplicable Epation k2, A.3. A.4. o A 5 depending on the Dlt ratio, to r ., g u e ri i r eie a g os l d v . m c a determiaecollapseplessum. Runium Qasp: t = (0.80) (nominalwall), D = nominalOD - ( . 0 (nom- 04) A.6 Stretch of Suspended Drill Pipe inal wan) Class 2: t = (0.70) (nominelW u, D = nominalOD - (0.60) (nominalwall) a) When pipe is freely suspended in a fluid, the stretch due to its own weight is: A4 Free Length of Stuck Pipe - 2 The dation between difhmtial stretch and free length of L1 e = - [Wa-2Wf(1-p)], astuckstringofsteelpipeduetoadifferentialpullis: 24E where e = shtchin., L, = length of freedrill pipe, R,COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD*API/PETRO RP 7G-ENGL L998 m 0732290 Ob09803 b T 4 m RECOMMENDEDPRACTICE FOR DRU STEM DESIGN AND OPERATING LIMITS 133 E = modulus of elasticity, psi, A.8 Toque Calculations for Rotary W, = weight of pipe material, lb/cu ft., Shouldered Connections (see Table W, = weight of fluid, lb/cu ft.. A-1 and Figure A-2) m = Poissonsratio. A.8.1 TORQUE TO YIELD A ROTARY For steel pipe where W,= 489.5 lb/cu ft, E = 30 x 106 psi SHOULDERED CONNECTION and p = 0.28,this formula will be: e="-- [489.5 - 1.44W,] , (A.11) 72 X lo7 or where e = [65.44- 1.44W,], (A.12) 5 = tuming momentor torque required to yield, ft-lbs., 9.625 x lo7 Y = material minimum yield strength, psi, , where p = lead of thread in., W = weight of fluid, Ib/cuf. , i, f = coefficient of friction mating s r c s threads on ua e , f Wg = weight of fluid, lb/gal. and shoulders,assumed 0 0 for thread com- .8 pounds containing 4 to 60 percent by weight of 0 A.7 Tension fmely powdered metallic zinc. (Reference cau- the tion regarding use of hazardous the materials in P = Y,A, (A.13) Appendix G of Specification7) ., where q = V 2 included angle ofthread (Figures 21 or 22, P = minimumtensile strength, lbs., Specification7), degrees, 1 Y,,, material minimumyield strength, psi, = A = cross-section area, s .i .(Table 1, Column 6, for q n C + [ C - ( L , , - . 6 2 5 ) x t p r ~ 42 ] R, = drill pipe). 4 Figure A-2-Rotary Shouldered ConnectionCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D m A P I I P E T R O RP 7G-ENGL L998 m 0 7 3 2 2 9 0 Ob09804 5 3 0 m 134 API R E M E N D E D PIUCTICE 76 = length of pin (Specification 7, Table 25, Column where 9), h., OD = outside da ee, , i m t rh R, = i4(OD + Qc), in. Qc = box counterbore (Specification Table 25, 7, The maximumvalue ofR, is limited to the value Column 1l), i . n, OD obtained from the calculated where A, =Ab, E = lpr x i8xVl2 A = cross-section aread, or A, whichever is smaller, s .i . q n A.8.2 MAKE-UPTORQUE FOR ROTARY SHOULDERED CONNECTIONS where x. A, = - [(C- B y - Z ] without relief grooves, P= 4 or where A = A, or Apwhichever is m lm Ap shall be based on s al . pin comectiom without relief grooves, in., sq. S = recommended make-up stress level, psi. where Note: For values o S s e 4.8.1 f rTool Joints and 5 2 for Drill Ch f ,e o o. DX = diameter of relief groove (Specification7, Table 16, Column5), in., A.8.3COMBINEDTORSIONANDTENSIONTO C = pitch diameter of thread a gauge point(Speci6ca- t YIELD A ROTARY SHOULDERED tion 7, Table 25,Column 5). in., CONNECTION ID = h i d e diameter, in., Figure A-3 shows thelimits for combined torsion and ten- sion for a rotary shouldered connection. The connection B = nomenclature is d e i A.8.l. The loads considered this ed n h in H = t h a d height not truncated (Specification 7, Table simplifìedapproach are torsionand tension. Bendingand 26, Column 3), in., internal pressure are notincluded,nor is the contribution of ~- shear stress due to torsion. A design factor of 1.1 should be S = root truncation (Specification , 7, Table 2 ,Column 6 used t provide some safety margin. This safety margin may o 51, ill-, not be sufkient for cases involving severe bending or ele- tpr = taper (Specification7, Table 25, Column 4), i & n, vated temperatm. (See4.5.) The failurecriteriais either torsional yield shoulder sep or Ab= [Oo2- (R-w], &on. T4 T3 1 1 Pin Meld O Applied Torsion Figure A"Limits for Combined Torsion and Tensionfor a Rotary Shouldered ConnectionCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D - A P I I P E T R O R P 7G-ENGL I1998 D 0732290 0609805 477 RECOMAENDED AND OPEFiATlNG LIMITS PRACTICE FOR DRILL STEM DESIGN 135 The endpoints for thelmt lines are defìned by fiveequa- iis J = polar moment of inertia tions: x = - (o”- 8) tubes for 32 Pl = (%)Ap = 0.098175 (o”- &), D = outside diameter, in., d = insidediameter,in., Tl = (‘-)Ab(’+-+R,f) 2n: cose 1.1~12 Rf Y, = material minimum yield strength,psi, P = ttl load in tension, lbs., oa () -A T2 = 1 . y l~ 1 2 P ( 2 1+ A + R 3 f ) 1n p ~ cose Rf A = cross section area, sq.in. A.10 Drill Collar Bending Strength Ratio The bendingstrength ratios in Figures 26 through 32 were determined by application of Equation A.17. The effect of stress-relief features was disregarded. T4 = (+)(+)(E + + R,f ) 11x12 A +A 27~ cose BSR = Z B - 2, Depending on the connecfion geometry, may be greater 23 or smaller than The sameis true forTl and Z . T4. 2 (D4- b4) 0.098 - The line (0,O)to (T4, Pl) represents shoulder separation - - D (A. 17) for low makeup torque. The line O) to (23,Pl) represents (22, (R4-&) pin yield under the combination of torque and tension. The 0.098 - R line (Tl,O ) to (Tl, represents box yield due to torsion. Pl) The horizontal linefrom P1 represents maximum tension D4- b4 load on the pin. D - R4-d ’ A.9 Drill Pipe Torsional Yield Strength R A.9.1 PURE TORSION ONLY where BSR = bending strength ratio, Q= O.096167JYm D . (kW 2, = box section modulus, c .in., u 2, = pin section modulus, CU. in., where D = outside diameter of pin and (Figure A+, in., box Q = minimum torsional yieldstrength,fi-lb., d = inside diameter or bore (FigureA+, i. n, Y = material minimum yield strength,psi, , b = thread mot diameter box threads at end of pin of J = polar moment of inertia (Figure A+, in., x R = thread root diameter of pin threads inch from = - (o” - 8)for tubes shoulder of pin (FigureA+, in. 32 = 0.098175 (o”- &), To use Fquation A.17, &t calculate: s D = outside diameter,in., Dedendwn, b, and R d = insidediameter,in. H A.9.2 TORSION AND TENSION De&& = - -f,, (A.18) 2 where QT = D /Y:-$ , (A.16) H = thread height not truncated, i . n, f , = root truncation, in. where Q = minimum torsional yieldstrength under tension, T t p ~ ( L , , --625) f%, i. b = C- 12 + (2 X dedendum) , (A.19)COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D - A P I I P E T R O RP 7G-ENGL L998 m 0732290 0609806 303 m 136 API RECOMMENDED PRACTICE 76 Pin length, Lpc D" - b4 BSR (NC46-62)= D BOX 1 "I I R (6 2 ) - ( . .54 4 1 2) 04 6.25 (4.465)4- (2.8125)4 4.465 2.64:1 Figure A"-Rotary Shouldered Connection Location of Dimensions for Bending Strength A.11 Torsional Yield Strength of Kelly Ratio Calculations Drive Section The torsional yield strength of the kelly drive section val- where ues listed in Tables 15 and 17 were derived h m the follow- C = pitch diameter a gauge pn,in., t i t ing equation: tpr = taper,insft. - b3)] 0.577Y,,,[0.200(a3 Y= , 12 R = C - (2x & - (tpr x x)J & hV 1 (A.20) where An example of the use ofEquation A.17 in determining the = Y,,, tensile yield, psi, bending strength of a typical drill collar connection is as fol- u = distance across flats, in., lows: b = kellybore,in. Determine thebending strength ratio of drill collar N M 62(61/40Dx213/,~IDconnection. A.12 Bending Strength, Kelly Drive Section D = 6 2 (Specification 7,Table 13,Column 2, .5 ) The yield bending values of the kelly drive in section listed d = 213/16. 1 5 (Specification 7,Table 13,Col- =2 8 2 in Tables15 and 17 were determined by one of the following umn 3. ) ~UatiOns: C = 4 6 6 (Specilìcation 7,Table 25, Column 5), .2 Taper = 2 (Specifìcation 7,Table 25, Column 4, ) a Yield in bending throughc m r of the square drive sec- . oes tion, Ym ft-k Lp = 4 5 (Specification 7,Table 25, Column 9), . H = 0.216005(Specification 7,Table 26,Column 3, ) Ym (0.118u"- 0 0 9b> .6 f = 0.038000(Specifìcation7, Mle 26,Column 5. , ) yBC = 12a Fs calculate dedendum, b, and it r R b. Yield in bending through the faces of the hexagonal drive section Y ft-lb , = H -f,= - .O38000= .O700025 - *216005- 2 2 C - tpr(L,,- .625) Y,,, (0.104a"- 0.085 b> b= + (2x &&h) YBF= 12a 12 b = 4.626 - 2 4 5 - 625)+ (2X .0700025) (. A.13 Approximate Weight of Tool Joint 12 Plus Drill Pipe b = 4.120, Approximate Weight of Tool Drill Pipe Joint Plus R = C - (2x & - (@rx x V J & h 1 ) Assembly, lb/ft = R = 4 6 6 - (2X .7) .2 0- - (2X /B X /1J R = 4.465. (Weight of DrillAdjusted9.4 + Approximate Pipe x 2 Approximate Weight of ToolJoint Substituting thesevalues in Equation A. 1 determines the 6 Length + 29.4 Tool Joint Adjusted bending strength ratio as follows: (A-21)COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • PRACTlCE FOR DRU STEM DESIGN RECOMMENDED AND OPERATING LIMITS 137 where Approximate Adjusted Weight Drill Pipe, lb/ft = of W,,,= W,( 65.5 -MW 65.5 )buoyantweightofpipe(lb/ft), + Upset Weight Plain End Weight 29.4 (A.22) W, = actual weight inair (Ib/ft), MW = mud density (lb/gal), and Plain end weight upset weight are found inA P I Speci- h, = radial tool clearance of joint to fication 5D. Approximate Weight of Tool Joint,=lbs hole (in.), 0.222 L.(D- 8)+ 0.167 (O3 - Dm3)- 0.501 &(D - D,,& DH= diameter of hole (in.), (A.23) TJOD = OD tool joints h , ( ) Dimensionsfor L,D, d, and Dm are in API Specification7 , BL= lateral curvature rate (O/lOOf) t, Figure 6 and Table 7. B, = total curvature rate (O/lOOf) i, Adjusted Length of Tool Joint, = ft R,= - lateral build radius 5730 (ft), BL L + 2.253 ( D - DTE) (A.24) 8 = inclination angle (deg). 12 A.14.2 If the hole curvature is l m t d to the vertical plane, iie A.14 Critical Buckling Force for Curved the buckling equations simplify to the following: Boreh&s27,293J831 ,S 12xh,xF,? A.14.1 The following equations define the range of hole 4xExZ ’ curvatures that buckle pipe in a t r e dimensionally curved he borehole. The pipe buckles whenever the hole curvature is between the minimum and maximum curvatures d e by ed h the equations. if F b < 4 x E x z pipenotbuckled, 12x h,xRL 4xExI if 12xh,xRL’ where B, = minimum vertical curvature rate for buckling 12xh,xFl (+ building, - dropping) (“/lo0 ft), 4xExZ ’ B , = maximum vertical curvaturerate for buckling (+ building, - dropping) (“/lo0 f. i) Fb= buckling force (lb), E = 29.6 x 106 (psi), IC 5730 - (2)) w,x 2 1/2 - sine], I = -(OD4-1D4), 64 W, = buoyant weight equivalent for pipecurved borehole (lb/fi), in where Fb= critical buckling force(+ compressive) (lb), W, = W ( , 65.5 -MW 65.5 ) buoyantweightof pipe (lb/ft), B,,, = minimum vertical curvature to cause buck- rate ling (+ building, - dropping) (O/lOOf) t, , air W = actual weight of pipe in (lb/ft), By- = maximum vertical curvature rate that buckles MW = mud density (lb/gal), pipe (+ building, -dropping)(“/lo0 f) W = equivalent pipe weight , t, required to buckle pipe h, = (””-y) of tooljoint to radial clearance at F b ilXial load, hole (in.), E = 29.6 x 106 psi, DH = diameter of hole (in.), 0.7854(0D4- ZD4) TJOD = OD of tool joint (in.), Z= 16 8 = inclination angle (deg).COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • 138 #I RECOMMENDED M C E 76 P A14.3 figures A-5 and A-6 show the effectof hole curva- turn on the buckling force for 5-inch and 322-inch drillpipe. Figure A-7 shows the effect l t r l curvatureson the buck- of a e a L = length of one joint of pipe (n) i., ling force of 5-inch drillpipe. For lateral and upward curva- E = Young’s modulus 30 x 106 for steel (psi), t r s thecriticalbuckling force increases with the total ue , Z = moment of inertia of pipe (h4) cutvaturerate. - - x( OD4- ZD4) A.15 Bending Stresses on Compressively 6 4 ’ Loaded Drillpipe in Curved F = axial compressive load on pipe (lb), Z = pipebodyZD(in.). D BoreholePIM 1115.1 The type of loading can be determinedby compar- A 1 . If the hole curvatureis less than the critical curva- .52 ture required to begin point contact, the maximum bending ing theactual hole curvature calculated values of the criti- to stress i given b y the following: s cal curval-um that d e h e the transition from no pipe body contact t point contact and f h n point contact to wrap con- o tact. The two critical curvatures are computed from thefol- BxODxFxJxL S = , , lowing equations. 57.3x 1OOx 12X4XZX sin R = 57.3~ lOOx 1 2 x A D -c 573xL where J X L tan --- [ ( 4XJ )4:Jl’ Sb= &=bending B = holecurvature, stress @si), where F = axial compressiveload on pipe (lb), B, = the critical hole curvature that defines tran- the sition from no pipe body contact t point con- o tact (O/lOOf)i, E = Young’s modulus 30 x 106 for steel (psi), AL) = (TJOD-OD), Z = moment of inertia (n) i. TJOD = tooljoint OD(in.), - x( OD4- ZD4) OD = pipe body OD ( ) h , - 6 4 ’ OD = pipebody OD (n)i., ID = pipebodyZD(h). L = length of onejoint of pipe ( n ) i., L = length of onejoint of pipe (n) i., E = Young’s modulus 30 x 106 for steel (psi), Z = moment of inertia of pipe body (h) 1115.3 If the hole curvature is between two critical cur- the vatwescalcdated,thepipewillhavecenterbodypointcon- - IC( -OD4- ZD4) tact and the maximum bending stress i given by the s I 64 following equation: F = axial compressiveload on pipe (lb), ID = pipebody Z (n) D i.. Sb = 4R B, = 57.3 x loox 12xAD r 1’ 2 L 57.3 L where E = Young’s modulus, 29.6 x 1 6 for steel (psi), 0 OD = pipe body OD (n) i., Where ID = pipebodyZD(in.), B, = the critical curvature d that e the transition w u=- L from point contactt wrap contact ( O / l O O f) o i, 25 ’ ALI = (TJOD- OD), L = length of onejoint of drillpipe for point contact TJOD = tool joint OD (h), of pipe body ( ) h, OD = pipebodyOD(h), L = L, forwrap contact ( n ) i.,COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • REC~MMENDED PRACTICE FOR DRILLSTEM DESIGNAND OPERAllNG LIMITS 139 -1o -5 O 5 10 Vertical build r a t e - O / l O0 ít. Figure A-5-Buckling Force vs Hole CurvatureCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • ~ STD.API/PETRO RP 7G-ENGL 1498 W 0732240 Ob09810 834 W 140 API RECOMMENDED P M C E 70 3.541. 13.3 Ib/ft Drill Pipe, 4.75 in Tool Joint 10 ppg mud, 90 deg 6.0 in hole -1o -5 O 5 10 Vertical build ra+o/lOO ft. Figure A H u d d i n g Force vs Hole CurvatureCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • RECOMMENDED AND OPERATING LIMITS PRACTICE FOR DRU STEM DESIGN 141 Figure A-7-Budding Force vs Hole CurvatureCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • 142 API RECOPMENDEDPRACnCE 76 A15.5 The maximum bending stresses cau then be com- A = ( 1 + 4 x R x m ) s i n U -U x s i n 2 ( ~ , L ~ puted usiug the equation for point contact and a pipe body length equal to the & v span length. &e sin u B = 2[ l-T-(l + x y AD)sin(3], A.15.6 One of our major concerns when drilling with pressively loaded com- drillpipe is the magnitudeof the l t r lcon- aea tact forces between the tool and the wall the hole joints of and e = -() m$, the pipe body and the wall ofthe hole. Various authors have J = r+)" (in.), suggested operatinglmt in the range of two to iis three thou- sand pounds or more for tool joint contact faces. are no There generally accepted operating limits for compressively loaded pipe body contact forces. For loading conditions in which 7c I = - - ( o D ~ - I D ~ ) (in.3, there is no pipe body contact, the lateral force on the tool 64 AD = diameter difference tool joint minus pipe body joints is given by: OD, AD = (TJOD - OD) (in.), FxLxB LFTJ = TJOD = tooljoint O D ( h ) , 57.3 x 1 0x 12 0 R = 57.3 x 1OOx l m , where B = holecurvature (O/lOOR). FTJ = lateral force on tool joint (lb), A154 If the hole curvature exceeds the critical curvature L = length of one joint of pipe (h), that separates point contact from wrap contact, we need t o B = hole curvature (V100 R). first compute an effectivepipe length in order to calculate the A.15.7 For loading conditions with pointor wrap contact, maximum bending stress. The &&ve pipe span length is the following equations give the contact forces for the tool calculatedfrom the following equation by and enor until trial joint and the pipe body: the calculated curvature matches the actual hole c r a r : uv t e u 57.3x 100x 1 2 x m B = r - 2 where L, = effective span length (h), = lateral f o m on tool joint (lb), B = holecurvature(Wooft.), AD = aedif€em~ce dm i between tool jointand pipe lateral force F L= OU pipe body (lb), L = L-L,, body* L, = lengthofpipe (h), AD = TJOD-OD(h), L, = L forpoint contact (n) i., TJOD = tool joint OD (h), L, = effective span length for wrap contact, OD = pipe body OD (n) i., 57.3 x loo x 12 I = pipebody ID (h). D R = B B = holecurvature ("/looft), E = Youngs modulus 29.6 x 106 for steel (psi), IC = 6( 4 . ~ - Z D ~ ) , - OD F = axidcompressiveload(Ib), AD = diameterdifference tool jointminus pipe OD (n) i., L, = length of pipe body touching hole(h), AD = TJOD-OD (h), L, = L-L,, x Z = -(OD4-ID4). L = length of one joint pipe (h.). of 64COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • REC~MMENDED PRACTICE FOR DRILL STEM DESIGNAND OPERATING LIMITS 143COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD-API/PETRO RP 76-ENGL 1998 m 0732290 Ob09814 48T m 144 A P I RECX"ENDED PRACTICE 6 7 I I I 1 I l I I I l I I I I I 1COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO RP 7G-ENGL L998 m 0732290 Ob09835 3 L b m APPENDIX B-ARTICLES AND TECHNICAL PAPERS Many of the topics covered Recommended Practice in 7G 16. Huang T., Dareing D.W., ‘%uCkling and Lateralvibra- have been the subject of significant investigation by various tion of Drill Pipe,” Journal OfEngineering lmkstry, for parties in the industry. Following is a partial list of articles November 1968, pp. 613-619. and tcu papers on topics relatedto items found in Rec- ehi d 17. Dming D. W., Livesay B. ‘Zongitudinalandhgular J., ommended Practice 7G. Drillstring Vibrations With Damping,”Journal of Engineer- 1. Axthur Lubinski, “Maximum Permissible Dog-Legs in ing for Indzmry, November 1968, pp. 671-679. Rotary Boreholes,” Journal of Petroleum Technology, Febru- 18. Combes J. D., Baxter R., “Critical RotarySpeeds Can V. ary 1%1. Be Costly,”Petroleum Engineer,September 1969, pp. 60-63. 2. Robert W. Nicholson, ‘MnimizeDrill pipe Damage and 19. Besaisow A. A., et.al., ‘Developmentof a Surface Drill- Hole Problems. Follow Acceptable Dogleg Severityi s ” Lmt, i string Vibration Measurement System,Society of Petro- ” Tmnsactions of the 1974 Intemutionul Association Drill- of leum Engineers (SPE) SPE 14327, presented a the 1985 t ing Contrac&rs ( M C )Rotaty Drilling Conference. Technical Conference,Las Vegas, September 22-25,1985. 3. K. D.Schenk,“Calco Learns AboutDrillingThrough 20. Burgess T. M., McDaniel G. L.,Das P K., ‘Improving . Excessive Doglegs:’ oil and G S Journal, October 12, U 1964. Tm1 Reli&fity Drillstring with M&&Field 4. G. J. Wilson, ‘DoglegControl In Directionally DrilledExperienceand Limitations,” SpE/IADc 16109, presentedat Wells:’ Transactions of TheAmerican InstirUte OfMining, Met- the 1987 SFWIADC Drilling Conference, New Orleans, allurgical, and Pmleum Engineers ( M E ) , 1%7, Vol. 240. March 1987. 5. Hansford,JohnE.andLubinski, Arthur, “Cumulative 21. Halsey G. W.,et. al., “TorqueFeedbackUsed to Cure Fatigue Damageof Drill Pipe in DogLegs,” Journal OfPetro- Slipstick Motion,” SPE 18049, presented at the 1988 Tech- l m Technology,March 1966. e Conference, nical Orleans, March New 1987. 6. Hansford, John E. and Lubinski, Arthm “The Effectof J. 22. Cook R. L., Nicholson W., Sheppard M. C., and West- or Drilling Vessel Pitch Roll on Kelly and Drill Pipe Fatigue,” lake W., ‘FirstReal Time Measurements of Downhole Vibra- Tmactions o MME, 1964, Vol. 23l. f tions, Forces, andPressures Used to Monitor Directional 7. Thad Vreeland, Jr., “Dynamic Stresses In Long Pipe Drill Drilling Operations,”SPElLADc 19651, presented a thet Strings:’ The Petroleum Engineer;May 1%1. 1989 SPE/IADc Drilling Conference, Orleans, Febru- New Oil 8. Henry Bourne, Continental Co., Ponca City, Okla- ary 28 to March 3,1989. homa, Drilling Fluid Corrosion,Unpublished. 23. Warren T. M., Brett J. F., andSinor L. A., ‘Development 9. Edward R Slaughter, E.Ellis Fletcher,Arthur R. Elsear, of a Whirl-Resistant Bit,” SPE 19572, presented a 1989 SPE t and GeorgeK. Manning, “An Investigationof the Effects of San Annual Technical Conference and Exhibition, Antonio, of Hydrogen on the Brittle Failure High Strength Steels:’ October 8-1 l. WADC TR 56-83, June 1955. 24. Yanglie Bang, Zaiyang Xiao, ‘Motion of Reviewingthe 10. H. M. Rollins, ‘Drill Stem Failures Due H$,” Oil and to Section 9 of API RP 7G,” presented at the API Standardiza- Gas Journal, January 24,1966. tion Conference, June 1993. of 11. Walter Main, Discussion Paper by Grant and Texter, 25. Nicholson J.W., “An Integrated Approach to Drilling “Causes and Prevention of Pipe and Tool Joint Trou- Drill Dynamics Planning, Identification, and Control,” SpE/IADc bles,” World Oil, October 1948. 27537, presented at the SPE/IADC Drilling Conference, Dal- las, February15-18,1994. 12. J. C. Stall and K. A. Blenkam, “Allowable Hook Load 26. and Torque Combinations For Stuck Drill String,” Mid-Conti- Fereidoun Abbassian, ‘Dillstring Vibration Primer,”BP nent A P I District Meeting, Paper No. 851-36-M, April 6, Exploration, Unpublished. 1962. 27. Dawson, Rapier, and Paslay, P.R., “Drillpipe Buckling in 13. Armco Steel Corporation, ‘‘OilCountry TubularProd- Inclined Holes,” Jm,October 1984. ucts-Engineering Data,” 1966. 28. Standard DS-I, Drill Stem Design and Inspection, Sec- 14. Arthur Lubinski, ‘Fatigue Range 3 Drill Pipe,”Revue of ond Edition, T.H. Hill Associates, Inc., Houston, Texas, de L’Institut Fmncaisah Petrole, November 2,1977 (English August 1997. translation). 29. Mitchell, R.F., ‘Effects of Well Deviationon Helical 15. Arthur Lubinski, “Dynamic Loading of Drill Pipe During Buckling,” SPE 29462, SPE Production Operabons Sympo- Tripping,” Journal of Petroleum Technology, August 1988. sium, Oklahoma City, A@ 1995. 145COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • S T D = A P I / P E T R OR P 7G-ENGL 1998 0 7 3 2 2 9 0 Ob09816 252 146 API REWENDED 76 PRA~cE 3. Schuh,FJ., ‘The Critical Buckling 0 Folce and Stresses for 35. Morgan, R.P.; Roblin, MJ., “A Method for the Investiga- Pipe in Inched Curved Boreholes,”SpE/IADc 21942, SPEI tion of Fatigue Strength in Seamless Drillpipe,”ASME Con- IADC Drilling Conference, Amsterdam, March 11-14,1991. ference,l h , b a Oklahoma, S p e b x22,1%9. etme 31. Kyllingstad, Aage, “Bucklingof ” d a r Strings in 36. Casner, John, A., ‘Endurance Limit of Drill Pipe,” letter Curved Wells,” Journal ofP m l e w n Science and Engineer- 1/21/95to JohnAltermann. h g , 12,1995, pp. 209-218. 32.Suryanarayana, PVR.; McCann,R.C., “AnExperimental 37. Hansford, J.E.; Lubinski,A., “Cumulative Fatigue Dam- Study of Buckling and Post-Buckling of Laterally Con- age of Drillpipe in Doglegs,”JournalOfPetroleumTechnol- strained Rods,” Journal OfEnergy Resoumes Technology,Vol. ogy, March 1966, pp. 359-363. 177, June 1995, pp. 115-124. 38. Lubinski,Arthur A., 33. Paslay, €?R; Cemocky, E.€?, ‘Bending Stress M c & - in Rotary Boreholes,” “Maximum Permissible Dog-Legs a a Journal o Petroleum Technology, f Feb- tion in Constant curvatureDoglegs with Impact on Drilling ruary l%l. and Casing,” SPE 22547, the SPE 66th Annual Technical Conference and Exposition, Dallas, Texas, October 6-9,39. Acknowledgment:Subcommittee appreciatesthe release 1991. by Mobil Exploration and Production Technical Center, Dal- 34. Acknowledgment: Subcommitteeappreciates the use of las, Texas the report, “Buckling of a Rod Confined to be i of n Shell Exploration productionCompany proprietary BSM and Contact with a Toroidal Surface, Parts I and H,” by Paul R. Bending Stress Cd.oe paslay, October 15,1993.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • ~~ ~ ~~~ ~~ "~ ~~ STD.API/PETRO RP 7G-ENGL L998 m 0732290 06098L7 199 m The American Petroleum Institute provides additional resources and programs to industry which are based API Standards. on For more information, contact: Seminars and Workshops 202-682-8 Ph: 187 Fax: 202-682-8222 Inspector Cedication Programs 202-682-8161 Ph: Fax: 202-962-4739 American Petroleum Institute Ph: 202-962-4791 Quality Registrar Fax: 202-682-8070 Monogram Program Licensing Ph: 202-962-4791 Fax: 202-682-8070 Engine Oil Licensing and 202-682-8233 Ph: Certification System Fax: 202-962-4739 Petroleum Test Laboratory Ph: 202-682-8064 Accreditation Program Fax: 202-962-4739 TrainingPrograms Ph: 202-682-8490 Fax: 202-682-8222 In addition, petroleum industry techcal, patent, and business information is available onlinethrough API EnCompass". Call 212-366-4040 or fax 212-366-4298 to discover more. American To obtain acopy of free the API Petroleum Publications, Programs, and Services Institute fax Catalog, call 202-682-8375 or your request to 202-962-4776. see the Or Helping You online interactive version of the catalog Get The Job Done Right." on our World Wide Web site - http://www.api.org.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
    • STD.API/PETRO P R 7G-ENGL L998 m 0732290 06098LB 025 m Additional copies available from API Publications and Distribution: (202) 682-8375 InformationaboutAPIPublications,ProgramsandServicesis available on the World Wide Web at: http://www.api.org American 1220 L Street, Northwest Petroleum Washington, D.C. 20005-4070 Institute 202-682-8000 Order No. G07G6ACOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services