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Recommended Practice for Drill Stem Design and Operating Limits
API RECOMMENDED PRACTICE 7G SIXTEENTH EDITION, AUGUST 1998 EFFECTIVE DATE: DECEMBER1,1998
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Strategies for loday's Environmental Partnership
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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 consumers. 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 andto implement cost-effective management practices: To recognize and to respond to community concerns about our raw matcrials, products and operations. To operate our plants and facilities, and to handleraw ourmaterials and productsin a 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 in the safe use, transportation and disposal 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 by handling and disposalof hazardous 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 materials, petroleum products and wastes.
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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 Institute
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SPECIAL NOTES API publications necessarilyaddress problems of a general nature. With respect to particular c r icumstances,local, state,and federal laws and regulations should be reviewed. API is not undertaking to meet the duties of employers, mantrhcmem, or suppliers to warn and properly train and equip their employees, and others exposed, concerning health state, or fedand safetyrisks and precautions, nor undertaking their obligations under local, eral laws. Information concerning safety and healthrisks and proper p a u t i o n s with respect to particular materials and conditions shouldbe obtained h m the employer,the manufacturer or supplier ofthat material, or the material safety data sheet. Nothing contained in any API publication is to be construed as granting any right, by apparatus, or prodimplicationor otherwise, for the manufacture,sale, or use of any method, uct covemi by letters patent. Neither should anything containedin the publication be construed as insuring anyone against liability infiingrnent for of letters patent. Generally,API standards are reviewed andrevised, 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 been granted, upon republication.Status of the publicationcan be ascertained h m the API Exploration andProduction Depaxtment materials is published aunu[telephone (202) 682-8000]. A catalog of API publications and ally and updated quarterly by AFI', 1220L Street, N.W., Washington, D.C. 20005. This document was producedunder API standardization procedures that ensureappropriate notifìcation and participationin the developmentalprocess and is designated as an API standard. Questions concerning the interpretation of the content of this standard or comments and questions concerning the procedures under which this standard was developed director of the Exploration and Production Department, should be direGted in writing to the 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 thedirector. API standards are published tofacilitate the broad availability ofproven, sound engineering and operatingpractices.These standards are not intended to obviate the need for applying 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 anyonefrom 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 with all the applicable requirements of that standard. API does not represent, warrant, or guarantee that such products do in fact conform to the applicableAPI s t a n d a d
AU rights wserved No part of this work may be wpnxhce4 stomd in a retTievaIsystem, or tmnmritted by any m e a ,electronic, mechanical photocopying, receding, or otherwise, 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.
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FOREWORD
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This recommended practice. is under the jurisdictionof the A P I Subcommittee on Standardization 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 operatinglimits of the drill stem. API publications maybe used by anyone desiring to do so. Every effort hasbeen made by the Instituteto assure the accuracy and reliabilityof the data contained in them; however, the Institute makesno representation,w m t y , or guarantee in connection withthis publication and hereby expressly disclaims any liabilityor responsibility for loss or damage resulting of any federal,state, or municipal regulation with which this from its use or for the violation publication may conflict Changes h m the previousedition are denoted withbars in themargins.The bars indicate new content or major editorial changes. Changessection to numben due to reformatting or minor editorial changesare not denoted with bars. Suggested revisionsare invited and shouldbe submitted to the directorof the Exploration and Production Department, American Petroleum Institute, 1220 L Street, N.W., Washington,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.
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CONTENTS
1
SCOPE ............................................................... 1.1 Coverage ....................................................... 1.2 Section Coverage.................................................
1 1 1
2
REFERENCES ........................................................
1
......................................................... 4 PROPERTIES OF DRTLL PIPE AND TOOL JOINTS ......................... 5 PROPERTIESOFDRILLCOLLARS ..................................... 6 PROPERTIESOF -YS ............................................. 7DESIGN CALCULAnONS............................................. 7.1 Design Parameten ............................................... 7.2 SpecialDesignparameterS ........................................ 7.3SupplementalDrillStemMembers .................................. 7.4 Tension Loading ................................................ 7.5CollapseDue to External Fluid Pressure ............................. 7.6Internal Pressure ................................................ TorsionalStrength ............................................... 7.7
1
3DEFINITIONS
3 33 33
46 46 46 46 46 50 51 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
9
LIhaATIONS RELATED TO HOLE DEVIATION ........................ 8.1 FatigueDamage ................................................. 8.2Remedial Action to ReduceFatigue ................................. 8.3 Estimation of CumulativeFatigueDamage ........................... of Fatigued Joints .................................... 8.4Identifìcation 8.5 Wear of Tool Joints and Drill Pipe .................................. Heat Checking of Tool Joints ...................................... 8.6
53 53 54 58
IJMlTATIONSRELATED TO FLOATING VESSELS ......................
59
58
58 59
10 DRILL STEM CORROSION AND SULFIDE STRESS CRACKING ........... 62 10.1Corrosion ...................................................... 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 78 11.3 Critical Buckling Force for Curved Boreholes......................... 11.4 Bending Stresses on Compressively Loaded Drill Pipe in Curved Boreholes 79 11.5 Fatigue Limits for API Drill Pipe ................................... 96 11.6EstimatingCumulativeFatigueDamage ............................. 98 101 11.7 Bending Stresses on Buckled Drill Pipe .............................
12 SPECIAL SERVICE PROBLEMS....................................... 12.1SevereDownhole Vibration....................................... 12.2 Transition from Drill Pipe to Drill Collars ...........................
101 101 108
V
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12.3Pulling on StuckPipe ........................................... 12.4 Jarring ....................................................... 12.5Torque in Washover w o n s ................................... 12.6AllowableHookloadandTorqueCombinations ...................... 12.7 BiaxialLoadingofDrill Pipe ..................................... 12.8FormulasandPhysicalConstants .................................. 12.9 Transition from Elastic to Plastic Collapse........................... 12.10 Effect of Tensile Loadon Collapse Resistance........................ 12.11 Example Calculation of Biaxial Loading............................
108 109 109 109 110 110 110 110 110
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 122 124 13.4 Drill Collar Inspection procedure .................................. 13.5 Drill CobHandlhg System .................................... 124 13.6Kellys ........................................................ 125 .............................................. 126 13.7RecutConnections 13.8 Pin StressRelief Grooves for Rental Tools andOther Short Term Usage Tools ................................................... 126 14 WELDING ON DOWN HOLE DRILLING TOOLS........................
127
.................................
127
15 DYNAMIC LOADING OF DRILL PIPE
16 CLASSIFICATION SIZE A N D “upTORQUE FOR ROCKBES ....... 127 APPENDIX A STRENGTH AND DESIGN FORMULAS ..................... APPENDIX B ARTICLFiS AND TECHNICAL, PAPERS......................
131 145
Figures 1-25 Torsional Strengthand Recommended Make-up Torque Curves .......... 20-32 26 Drill Collar BendingStrength Ratios. 1V2and 1V4Inch ID ................. 39 27 Drill Collar BendingStrength Ratios. 2 and 2V4Inch ID ................... 40 28 Drill Collar Bending Strength Ratios. 2l/, Inch ID ........................ 41 29 Drill Collar Bending StrengthRatios. 213/.. Inch ID....................... 42 43 30 Drill Collar Bending StrengthRatios. 3 Inch ID.......................... 31 Drill Collar Bending StrengthRatios. 3V4Inch ID........................ 44 32 Drill Collar Bending StrengthRatios. 3V2Inch ID........................ 45 33 NewKelly-NewDriveAssembly ..................................... 48 34 NewKelly-NewDriveAssembly ..................................... 48 35 Maximum Height of Tool Joint AboveSlip to Prevent Bending During Tonging ................................................... 53 36 Dogleg Severity Limits for Fatigueof Grade E75 Drill Pipe ................ 55 37 Dogleg Severity Limits for Fatigue of S-135 Drill Pipe .................... 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 per Foot, Range 2Drill Pipe. 43/4 Inch Tool Joints ........................ 60
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42 Lateral Forces on Tool Joints and Range 2Drill Pipe 4V2Inch, 16.6 Pounds per Foot, Range 2 Drill Pipe. 6V4Inch Tool Joints........................ 60 43 Lateral Forces on Tool Joints and Range 2Drill Pipe 5 Inch, 19.5Pounds per Foot,Range 2 Drill 63/8 Inch Tool Joints ........................... 61 44 Lateral Forces on Tool Joints and Range 3Drill Pipe 5 Inch, 19.5Pounds 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 with Hydrogen UnderStandardizedConditions.... 66 46-66 Approximate Axial Compressive Loads at which Sinusoidal Bucklingis Expected to Occur............................................ 68-78 80-94 67a-74a Bending Stress and Fatigue Limits............................... 67b-74b LateralContact Forces andLength .............................. 81-95 . !X' 75 Hole Curvature Adjustment Factor ToAllow for Merences in Tooljoint OD's 76 Median FailureLimits for Am Drillpipe Noncorrosive Service.............. 99 ........... 100 77 Minimum FailureLimits for API Drillpipe Noncorrosive Service 102 78a Bending Stress for High CurvatUtes .................................. 103 78b MeralContact Forces andLength ................................... 104 79a Bending Stress for High CurvatUtes .................................. Length ................................... 105 79b Lateral Contact Forces and 106 80a Bending Stress for High CurvatUtes .................................. Lateral Contact Forces and Length ................................... 107 8Ob Stress or Maximum Shear-Strain Energy Diagram 81 Ellipse of Biaxial Yield Nadai. Collapse of DeepWell Casing.API Drilling and After Holmquist and production Practice (1939) ......................................... 111 Drill String Components ....... 113 82 Marking on Tool Joints for Identification of 83 Recommended Practice for Mill Slot and Groove Method of Drill String Identifìcation............................................... 114 84 Identification of Lengths Covered byInspection Standads................ 116 ...................... 122 85 Drill Pipe and Tool Joint Color Code Identification 123 86 Tong Space and Bench Mark Position................................ 124 87 Drill Collar Elevator............................................... 125 and ............................ 88 Drill Collar Orooves for Elevators Slips 125 89 Drill Collat Wear ................................................. 126 90 Modified Pin Stress-Relief Groove................................... 131 A- 1 Eccentric Hollow Section ofDrill Pipe ................................ 133 A-2 Rotary Shouldered Connection...................................... A-3 Limits for Combined Torsion and Tension for a Rotary Shouldered Connection134 of Dimensions for Bending A 4 Rotary Shouldered Connection Location Strength Ratio Calculations......................................... 136 139 A-5 Buckling Force vs HoleCurvature ................................... 140 A d Buckling Forcevs Hole Curvature ................................... 141 A-7 Buckling Forcevs Hole Curvature ...................................
Pipe.
Tables 1 2 3 4 5 6 7
New Drill Pipe Dimensional Data...................................... 4 5 New Drill Pipe Torsional and Tensile Data............................... Data ........................ 6 New Drill Pipe Collapse and Internal Pressure Used Drill Pipe Torsional and Tensile Data API PremiumClass............... 7 Used Drill Pipe Collapse and Intemal Pressure Data APIPremiumClass ....... 8 Used Drill Pipe Torsional and Tensile Data API Class 2..................... 9 Internal Pressure Data API Class 2............. 10 Used Drill Pipe Collapse and
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MechanicalpropertiesofNewToolJointsandNeworadeE75Drillpipe..... 11 High StrengthDrill Pipe... 13 Mechauid properties of New Tool Joints and New RecommendedMinimum OD and Makeup Torque of Weld-on Qpe Tool
Joints Basedon Torsional Strengthof Box and Drill Pipe................... 15 18 11 Buoyancy Factors .................................................. Rotary Shouldered Connection Interchange List .......................... 19 12 Drill Collar weight (Steel) @ounds per foot) ............................. 34 13 Drill Collar 14 Recommended Make-upTorque1 for Rotary Shouldered COMdOXlS....................................................... 35 S t r e n g t h of Kellys .................................................. 47 15 for Development of Maximum 16 Contact Angle Between Kelly and Bushing Width Wear Pattern................................................. 48 S t r e n g t h of Remachined Kellys ....................................... 49 17 Section Modulus Values ............................................. 53 18 67 19 Effect of Drilling FluidTypeon Coefficient of Friction.................... 79 20 Hole curvaturesthat Prevent Buckling ................................. 96 21 Youngstown Steel Test Results........................................ 22 Fatigue EnduranceLimits Compressively LoadedDrill Pipe ................ 98 98 23 Values Usedin Preparing Figure77 .................................... 115 24 Classification of Used Drill Pipe...................................... 117 25 Classification of UsedTubing Work Strings............................. 26 Hook-Load at Minimum Yield Strengthfor New, PremiumClass (Used), and class 2 (Used) Drill Pipe............................................ 118 27 Hook-Load at MinimumYleld Strengthfor New. PremiumClass (Used). and Class 2 (Used) Tubing Work Strings................................... 120 Drill Collar Groove and Elevator Bore Dimensions ....................... 125 28 29 Maximum Stress at Root ofLast EngagedThread for the Pin of an NC50 Axisymmetric Model .............................................. 126 IADC Roller Bit Classifìcation Chart .................................. 128 30 IADC Bit Classification Codes Fourth Position .......................... 129 31 Recommended Make-up Torque Ranges for Roller Cone Drill Bits .......... 129 32 33 RecommendedMinimum Make-up Torquesfor Diamond Drill Bits......... 130 130 34 Common RollerBit Sizes ........................................... Common Fixed Cutter Bit Sizes ...................................... 130 35 A-1 Rotary Shouldered Connection Thread Element Information ............... 143
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Recommended Practice for Drill Stem Design and Operating Limits 1 scope
3 Definitions
1.1 COVERAGE
3.1bendingstrengthratio: Theratioofthesection modulus of a rotary shouldered box at the point in the box where the pin ends when made up divided by the section modulus of therotary shouldered pin at the last engaged thread.
This recommended practice involves not only the selection of drill string members, but also the consideration of hole angle control, drilling fluids, weight and rotary speed, and other operational procedures.
3.2 bevel diameter: Theouterdiameter ofthe contact face of therotary shouldered connection.
1.2SECTIONCOVERAGE
I
3.3 bit sub: A sub, usually with2 box connections, thatis used to connect the bit to the drill string.
Sections 4, 5, 6, and 7 provide procedures for use in the selection of drill string members. Sections 8,9, 10, 11, 12, 3.4 box connection: A threaded connection on Oil and 15 are related to operating limitations which may reduce Country Tubular Goods (OCTG) that has internal (female) the normal capability of the drill string. Section13 contains a threads. classification system for used drill pipe and used tubing work strings, and identification and inspection procedures for other3.5 calibration system: A documented system of gauge calibration and control. drill string members. Section 14 contains statements regarding welding on down hole tools.Section 16 contains a classi3.6 Class 2: An API service classification for used drill fication system for rock bits. pipe and tubing workstrings.
2 References
3.7 cold working: Plastic deformation of metal at a temperature low enoughto insure or cause permanent strain.
(See also Appendix B.)
RP 5C1 Bull 5C3 Spec 7
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3.8 corrosion: The alteration anddegradaton of material by its environment
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RP 13B-2
Care and Use of Casing and Tubing Bulktin on Formulas and Calculationsfor Casing, Tubing, Drill Pipe, and Line Pipe Properties Specijkation for Rotary Drill Stem Elements
3.9 critical rotary speed: A rotary speed at which harThese vibrations may cause fatigue monic vibrations OCCUT. failms, excessive wear,or bending. 3.10 decarburization: The loss of carbon from the surface of a ferrous alloy as a result of heatingin a medium that at the surface. reacts with the carbon
Recommended Practice for Testing of lkread Compoundrfor Rotary Shouldered connections RecommendedPractice Standard Pnxedure for Field Testing Water-Based Drilling Fluids Recommended Practice Standard Pnxedun?for Field Testing Oil-Based Drilling Fluids
3.1 1 dedendum: The distance between the pitch line and root ofthread. 3.12 dogleg: A term applied to a sharp change of direction in a wellbore or ditch. Applied also to the permanent bending Of roPe Or Pipe3.13doglegseverity: A measureof theamount of change in the inclination and/or direction of a borehole, usually expressed in degrees per 100 feet of course length.
AST" 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 collars.
NACE2 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 thebit.
'Americansociety for Testing Materials, 100 Barr Harbor Drive, West Con-
3.16 drill pipe: A length of tube, usually steel, to which SpeCid threaded COMectiOnsCalledto01 joints attached.
shccken, Pennsylvania 19428. WACE ~ntemao ti na P.O. ,l BOX 218340, Houston, exa as mis-8340. 1
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API RECOMMENDEDPRACT~CE 7G
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3.17 drillstringelement:
Drill pipewithtooljoints
attached. 3.18 failure: Improper performauce of a device or equipment that prevents completion its of designfunction. 3.19 fatigue: The process of progressive localizedpermanent structural change occurring in a material subjected to conditions that producefluctuating stresses and strains at some point or points and that may culminate in cracks or complete frilcture after a sufiicient numberof fluctuations. 3.20 fatigue failure: A failure whichoriginates as a result of repeated or fluctuating stresses having maximum values less than the tensile strength of the material. 3.21 fatigue fatigue.
the system with caustic soda or quick lime and an organic acid. Silicak, salt, and phosphate may also be present. Oilbase drilling fluids are differentiated from invert-emulsion drilling fluids (both water-in-oil emulsions) amounts by the of water used, method of controlling viscosity and thixotropic is l ,and fluid loss. properties, wall-buildingmatera 3.31 pin end: A threaded connection on Oil Country Tubular Goods (OCTG)that has external (male)threads. 3.32plainend: Drill pipe,tubing,orcasingwithout threads.The pipe ends may or may not be upset. 3.33premiumclass: An API service classifìcationfor used drill pipe and tubing work strings.
crack A crack resulting from fatigue. See
3.34quenchedandtempered: QuenchhardeningHardening a ferrous alloy by austenitizing and then cooling rapidly enough so that some or allof the austenitetransforms 3.22 forging: (1) Plastically deforming metal, usually hot, to martensite. into desired shapes with compressive force, withor without Tempering-Reheating a quenched-hardened or normalized dies. (2) A shaped metal part formed by the forging method. ferrous alloyto a temperatme below the transformation range at any rate desired. and then cooling 3.23 kelly: The square or hexagonal shaped steel pipeconnecting the swivel to the drill string. The kelly moves through 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 kelly saver sub A short substitutethat is made up 3.36 rotary shoulderedconnection: A connection onto the bottom of the kellyto protect the pin end of the kelly used on drill stringelementswhichhascoarse, tapered operations. h m wear during make-up and break-out threadsand seating shouldem. 3.25 last engaged thread: The last thread on the pin 3.37 shear strength: The stress required to producefracbox or the box engaged withthe pin. engaged with the ture in the plane of cross section, the conditions of loading being such that the directions of force and of mistauce am 3.26 lower kelly valve: An essentially full-opening valve installed immediately below the kelly, with outside diameter parallel and opposite although theirpaths are offset a speciequal to the tool jointoutside diameter. Valvecan be closed to 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. operations. hole for snubbing 3.38 slip area:The sliparea is containedwithin a distanœ 3.27 makeup shoulder: The sealing shoulder on a of 48 inches alongthe pipe body from the juncture of the tool rotary shouldered connection. joint OD and the elevator shoulder. 3.28 minimum make-up torque: The minimum makeup torque is the minimum amount of torque necessary to develop an arbitrarily derived tensile stress in the pin or compressive stress in the box. This arbitrarily derivedstress level is perceived as being SufEcient in most drilling conditions to prevent downhole make-up and to prevent shoulder separation frombending loads. 329 minimum OD: For tool jointson drill pipe with rotary shouldered connections, the minimum OD is the minimum boxODthatwillall~theconnectiontoremainasstrongasa specifìedpercentage of the drill pipe tube in torsion.
3.39 stress-relief feature:A modiiìcation performedon rotary should& connectionswhich removes the unengaged threads of the pin or box. This process makes thejoint m m flexible andreduces the likelihood of fatigue crachg in this highlystressedarea 3.40 swivel: Device at thetop of the drill stem whichpermits simultaneous circulation and rotation. 3.41tensile s t r e n g t h : The maximum tensile stress which a material is capable of sustaining. Tensile strength is calculated from themaximum load duringa tension test carried to N@UEand the original cross-sectional area of the specimen.
3.30 oil muds: The term “oil-base drilling fluid” is applied to a special type drilling fluid where oil is the contin3.42 test pressure: A pressure above working pressure uous phase and water the dispersed phase. Such fluids contain a vessel. blown asphalt and usually 1to 5 percent water emulsified into used to demonstrate structural integrity of pressure
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RECOMMENDED PRACTICE FOR DRILLSTEM DESIGN AND OPERATING LIMrrS
3.43 thread form: The formof threadis the thread profde in an axial plane for a length of one pitch. 3.44 tolerance: The amount of variation permitted.
3.45 tool joint: A heavy coupling element for drill pipe having coarse,t a p e d threads and sealing shoulders designed to sustain the weight of thedrill stem, withstand thestrain of repeated make-up and break-out, resist fatigue, resist additional make-up during drilling, and provide a l e a k - p f seal. The male section (pin) is attached to one end of a length of (box) is attached to the other drill pipe and the female section end Tool joints may be welded to the drill pipe, screwed onto the pipe, or a combination of screwed on and welded. 3.46 upper kelly cock: A valve immediately above the kelly that can be closed to confinepressures inside the drill string. 3.47 upset: A pipe end with increased wall thickness. The outside diameter may be increased, or the inside diameter may be reduced, or both. Upsets are usually formed by hot forging the pipe end.
3.48 working gauges: Gauges used for gaugingproduct threads. 3.49 working pressure: The pressure to which a particular piece of equipment is subjected during normal operations. 3.50 working temperature: The temperature to which a particular piece ofequipment is subjectedduring normal operatiom.
4 Properties of Drill Pipe andTool Joints 4.1 This section contains aseriesoftables(Tables 1 through 11) designed to present the dimensional, mechanical, and performance properties of new and used drill pipe. Tables are also included listing these properties for tool joints used with newand useddrill pipe. 4.2 All drill pipeandtool included inSection 4.
joint p p e r t i e s tables are
4.3 Values listed in drill pipe tables are based on accepted standards of the industry and calculated from formulas in AppendixA. 4.4 Recommended drift diameters for new drill string assemblies are shown in column 8 of Tables 8 and 9. Drift bars must be a minimum of four inches long. The drift bar must pass through the upset area but need not penetratemore than twelve inches beyond the basetheofelevator shoulder. 4.5 The torsionalstrength of a tooljoint is a functionof several variables. These include the strength of the steel,connection size, thread form, lead, taper and coefficient of friction on mating surfaces, threads, or s h o u l h . The coefficient of fric-
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
m 3
tion for thepurposes of this recommended practice is assumed a constant; it has been demonstrated,however, that new tooljoints and servicetempenahm often affect thecoefficient of friction of the tool joint system. While new tool joints typically exhibit a low coefficientfriction, of service temperatures greater than 300°F can dramatically increase or decrease the coefficient of friction depending primarily on thread compound. The torquerequired to yield arotary shouldered connection may be obtained from the equation in Section A.8. 4.6 The pin or box area, whichever contmls, is the largest factor and is subject to the widest variation. The tool joint outside diameter (OD) and inside diameter (ID) largely determine the strength of the joint in torsion. The OD affects the boxareaandtheIDaffectsthepinareaChoiceofODandID determines the areas of the pin and box and establishes the theoretical torsional strength, assuming all other factors are constant. 4.7 The greatest reduction in theoretical torsional strength of a tool joint during its service occurs life with OD wear.At whatever point the tooljoint box area becomes the smalleror controlling a m , any further reduction in ODcauses a direct reduction in torsional strength. If the box area controls when thetooljointis new, initial OD wear reduces torsional strength. If the pin controls when new, some OD wear may occur before the torsional strength is affeckd Conversely, it is possible to increase torsional strength by making joints with oversize OD andreducedID. 4.8 Minimum OD,box shoulder, and make-up torque values listed in Table 10 were determined using the following criteria: 4.8.1 Calculationsforrecommendedtool joint make-up torque are based on the use of a thread compound containing 40 to 60 percent by weight of finely powdered metallic zinc applied to all threads and shoulders, and containing not more than 0.3 percent total active sulfur (referencethecaution regarding the use of hazardous materials in Spedìcation 7, Appendix G). Calculationsare also basedon a tensilestress of 60 percent of theminimum tensile yieldfor tool joints. 4.8.2 In calculation of torsional strengths of tooljoints, both new and worn, the bevels ofthe tool joint shouldersare disregarded. 4.8.3 premium Class Drill String is based on drill pipe having aminimum wall thickness of80 percent. 4.8.4 Class 2 drill string allows drill pipe with a minimum wall thickness of70 percent. 4.8.5 The tool joint to pipe torsional ratios that are used here (20.80) are recOmmendations only andit shouldbe realized that other combinations of dimensions maybe used. A given assembly that is suitable for certain service may be inadequate for some areas and overdesigned for others.
API REWMENDED PRACTICE 7 6
4
Table l-New Size
mainEnd
in
Nominalweight -and Couplings,
D
lWit
Wit
.280
234 6.26
.217 .362
OD
4.43
4.85
13.75
ID
Wall Thickness in.
sq.in.
Cu. in.
d
A
Z
6.65
1.995 1.815
1. W 2 1.8429
1.321 1.733
2%6.16 9.72
6.85 10.40
2.441 2.151
1.8120 2.8579
2.241 3.204
311,
9.50 13.30 40 49 15.5
8.81 12.31 14.63
2.992 2.764 2.602
2.5902
.368
3.523 5.144 5.847
11..262 85 14.00 15.70
10.46 12.93 14.69
.330 .380
3.476 3.340 3.240
3.0767 3.8048 4.3216
6.458 7.157
16..337 60 20.00 .430 22.82
14.98 18.69 21.36
S00
3.958 3.826 3.640 3.500
3.6004 4.4074 5.4981 6.2832
7.184 8.543 10.232 11.345
16.25 .362 19. 50 25.60
14.87 17.93 24.03
4.408 4.276 4.000
4.3743 5.2746 7.0686
9.718 11.415 14.491
19.20 21.9 30 61 24.7 A15 0
19.81 22.54
4.892 4.778 4.670
4.%24 5.8282 6.62%
12.221 14.062 15.688
5.965 5.901
6.5262 7.1227
19.572 21.156
Weight1
.254
411,
5
.304
511,16.87
6% .362
WmArea P o l a r s e c t i d Body of P i $ Modulus3
in.
4
12.24
Drill Pipe Dimensional Data
24.22
25.20 .330 27.70
.2%
.m
22.19
3.6209 4.3037
5.400
'1Wft = 3.3996X A (COL 6) 'A = 0.7854(D- a)
M=0.1%35
1
(-D"
Dg
4.9 Many sizes and styles of connections are hte~hangeable with certain other sizes and styles of connections.These conditionsdiffer only in name and in some cases thread form. If the thread farms are interchangeable, the connections are interchangeable.
I
'zhese interchangeableconnections are listed inTable 12. !
1 I
l l
4.10 The curves of Figures 1 through 25 depict thetheoretical torsional yield strength of a number of commonly used tool jointconnections over a wide range of inside and outside diameters. The coefficient of fiiction on mating flrfaces, threadsandshoulders, is assumedto be 0.08 (See Section 3 of Am RP 7A1,Recommended Pmctice for lèstìng ofn2mad Compound for Rotary Shouldered Connections). The m a b up torque should be based on a tensile stress level of 60 percent of the minimum yield for tooljoints.
~
4.1 1 The curves may be usedby taking the followingsteps: 4.1 1.1 Select the appropriatelytitled curve for the size and type tool joint COMection being studied.
the under consid4.1 1.2 Extend a horizontal line from OD eration to the curve andread the torsional strength representing the box. 4.1 1.3 Extend a vertical line from theID to the curve and read the torsional strength representingthe pin. 4.11.4 The d e r of the two torsional strengths thus obtained is the theoretical torsionalstrength of the tooljoint, 4.1 1.5 It is emphasized that the values obtained from the curves am theoreticalvalues of torsional strength. Tool joints in the field, subject to many factors not included in determination of points for the curves,may vary h m these values. 4.1 1.6 The curves are most useful to show the relative torsional strengths of joints for variations in OD and ID, both new and after wear. In each case,the smaller value should be
used. (Text continuedm page 33.)
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
RECOMMENDED PRACTICE
FOR DRU ~
5
STEM DESIGNAND OPERATING LIMITS
~~______
~____
____
~~
~~
Table 2 4 e w Drill Pipe Torsionaland Tensile Data
4.85
51.
234 7917.
6.85
176071.
6250.
10.40
SI,
89402.6% 70580.
385820.
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.
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.
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.
848230.
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.
19.20
44074.
55826.
61703.
79332.
372181.
471429.
521053.
669925.
21.90
50710.
64233.
70994.
91278.
437 1 16.
553681.
611963.
786809.
24.70
56574.
71660.
79204.
101833.
497222.
629814.
696111.
894999.
4V2
5
m 2 . 14146.
4
98812.
8574.
6.65
3'12
13.75
123902. 6668. 97817.
2'4
8. 16176. 14635. 11554.
50
136944.
25.20
76295. 27.70
881035. 489464.685250. 619988. 67665 m 534199. . 137330. 106813.
'Based on the shear m g h t equalto 57.7 percent of minimumyield strength and nominal wall thickness. Minimum tasionalyield strength calculated fimu Equation A.15.
ZMinimumtensilestrengthcalculatedfromEquationA.13.
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
l. 961556. 747877.
5
RP 7G-ENGL
STD.API/PETRO
1998
API RECOMMENDED-CE
6
0732290 Ob09b7b 965
m
76
Table %New Drill Pipe Collapse and Internal Pressure Data
OD m.
lb/&
5
5'1,
6%
G105 E75
S135
15456.
19035.
10500.
13300.
14700.
18900.
15599.
19759.
21839.
28079.
15474.
19600.
21663.
27853.
10467.
12940.
14020.
17034.
9907.
12548.
13869.
17832.
10.40
16M9.
20911.
23112.
29716.
16526.
20933.
23137.
29747.
9.50
loool.
12077.
13055.
15748.
9525.
12065.
13335.
17145.
13.30
14113.
17877.
19758.
25404.
13800.
17480.
19320.
24840.
15.50
16774.
21247.
23434.
30194.
16838.
21328.
23573.
30308.
11.85
8381.
9978.
10708.
12618.
8597.
10889.
12036.
15474.
14.00
11354.
14382.
158%.
20141.
10828.
13716.
15159.
19491.
15.70
128%.
16335.
18055.
23213.
12469.
15794.
17456.
22444.
274
414
x95x95 13984.
6.65
4
S135 E75 G105
..
M m m m Y i e l d Strength, psi
11040.
234
3V2
Ml.r.lmumvalues,psi
couplings
13.75
7173.
8412.
8956.
10283.
7904.
10012.
11066.
14228.
16.60
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.
16.25
6938.
8108.
8616.
9831.
7770.
9842.
10818.
13986.
19.50
9962.
12026.
12999.
15672.
9503.
12037.
13304.
17105.
25.60
13500.
17100.
18900.
24300.
13125.
16625.
18375.
23625.
19.20
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.
9903.
12544.
13865.
17826.
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
;
50
RECOMMENDEDPRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS
7
Table &Used Drill Pipe Torsional and Tensile Data API Premium Class
Size
OD m.
New Weight NominalW/ Threadsand couplings lWft
5215.
6705.
76893.
97398.
107650.
138407.
4811.
6093.
6735.
8659.
107616.
136313.
150662.
193709.
6332.
8020.
8865.
11397.
106946.
135465.
149725.
192503.
8858.
11220.
12401.
15945.
166535.
210945.
233149.
299764.
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.
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.
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.
409026.
452082.
581248.
22.82
31587.
40010.
44222.
56856.
367566.
465584.
514593.
661620.
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.
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.
60192.
77312.
85450.
109864.
422419.
535064.
591387.
760354.
2V8 10.40 3v2
5
SV2
6%
E75
47 19.
6.65
4'4
S135
TensileDataBasedonUniformWear Load at Minimum Xeld Strength, lb x95 G105 5135
3725.
234
4
E75
'-orsional Yield Strength Based OU UniformW=, ft-lb x95 G105
25.20 27.70
'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
85
STD.API/PETRORP
~
7G-ENGL
0732290 Ob09678 738
L998
~~
Table W s e d Drill Pipe Collapse and Internal Pressure Data API Premium Class
___
~
8522.
10161.
10912.
12891.
9600.
12160.
13440.
17280.
6.65
13378.
16945.
18729.
24080.
14147.
17920.
19806.
25465.
6.85
7640.
9017.
9633.
11186.
9057.
11473.
12680.
16303.
10.40
14223.
18016.
19912
m.
19139.
21153.
27197.
9.50
7074.
8284.
8813.
10093.
8709.
11031.
12192.
15675.
13.30
12015.
15218.
16820.
21626.
12617.
15982.
17664.
22711.
15.50
14472.
18331.
20260.
26049.
15394.
19499.
21552.
27710.
11.85
5704.
6508.
6827.
7445.
7860.
9956.
11004.
14148.
14.00
9012.
10795.
11622.
13836.
9900.
12540.
13860.
17820.
15.70
10914.
13825.
15190.
18593.
11400.
14440.
15960.
20520.
13.75
4686.
5190.
5352.
5908.
7227.
9154.
10117.
13008.
16.60
7525.
8868.
9467.
10964.
8987.
11383.
12581.
16176.
20.00
10975.
13901.
15350.
18806.
11467.
14524.
16053.
22.82
12655.
16030.
17718.
22780.
13333.
16889.
18667.
20640. m.
16.25
4490.
4935.
5067.
5661.
7104.
8998.
9946.
12787.
19.50
7041.
8241.
8765.
10029.
8688.
11005.
12163.
15638.
25.60
11458.
14514.
16042.
20510.
12000.
15ux).
16800.
21600.
19.20
3736.
4130.
4336.
47
6633.
8401.
9286.
11939.
21.90
5730.
6542.
6865.
7496.
7876.
9977.
11027.
14177.
24.70
7635.
901
9626.
11177.
9055.
11469.
12676.
16298.
25.20
2931.
3252
3353.
3429.
5977.
7571.
8368.
10759.
27.70
3615.
4029.
4222.
4562.
6557.
8306.
9180.
11803.
234
2%
3V2
5
5'4
6%
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
1.
14.
151
10.
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 API Class 2 New Weight Nominal W/ Threads '+TorsionalYield and
Size
4.85
OD
COuplingS
m.
lWft
Strength
Based OU UniformWear, A-lb E75
x95S135
G105
E75
84469. 120035.
231~ 5232.
4130.
167043. 129922.2% 117549.
0627.
9615.
9.50
7591.
6.65 92801. 6.85
167167. W71. 130019. 117636. 9871. 5484. 7677.
6946.
10.40
13.30
12365.
15663.
17312.
22258.
183398.
232304.
256757.
3301 16.
15.50
13828.
17515.
19359.
24890.
215967.
273558.
302354.
388741.
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.
17715.
22439.
24801.
3 1887.
185389.
234827.
259545.
333701.
m.
26483.
29271.
37634.
225771.
285977.
316080.
406388.
34404.
38026.
48890.
402163. 317497.
4444%.
571495.
4V2 16.60
34645.
93360.
3V2
4
13.75
Tensile Data Based on Unifonn Wear Load at Minimum Yield Strength, lb x95S135 G 105
31346.
24747.
20.00
27161.
22.82
5
511,
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.
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
48497.67896. 61430. 6% 472131.427166. 25.20337236. 87295.
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 mwear on outside diameter and tensiledata based on 30 pacent uniform wear on outside diameter.
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
607026.
5
5
API RECOMMENDED PRACTICE 7 6
10
Table 7"used Drill Pipe Collapse and Internal Pressure Data API Class 2
7996.
8491.
9664.
8400.
10640.
11760.
15120.
12138.
15375.
16993.
21849.
12379.
15680.
17331.
22282.
6055.
6963.
7335.
8123.
7925.
10039.
11095.
14265.
10.40
12938.
16388.
18113.
23288.
13221.
16746.
18509.
23798.
9.50
5544.
6301.
65%.
7137.
7620.
%52.
10668.
13716.
13.30
10858.
13753.
15042.
183%.
11040.
13984.
15456.
19872.
15.50
13174.
16686.
18443.
23712.
13470.
17062.
18858.
24244.
11.85
4311.
4702.
4876.
5436.
6878.
8712.
%29.
12380.
14.00
7295.
8570.
9134.
10520.
8663.
10973.
12128.
15593.
15.70
953l.
11468.
12374.
14840.
9975.
12635.
13%5.
17955.
13.75
3397.
3845.
4016.
4287.
6323.
8010.
8853.
11382.
16.60
5951.
6828.
7185.
7923.
7863.
9960.
11009.
14154.
2o.m
%3 1.
11598.
12520.
15033.
10033.
12709.
14047.
18060.
22.82
11458.
14514.
16042.
20510.
11667.
1471-9.
16333.
21000.
16.25
3275.
36%.
3850.
4065.
6216.
7874.
8702.
11 189.
19.50
5514.
6262.
6552.
7079.
7602.
9629.
10643.
13684.
25.60
10338.
12640.
13685.
16587.
10500.
13300.
14700.
18900.
19u)
2835.
3128.
3215.
3265.
5804.
735
8125.
10447.
21.90
4334.
4733.
4899.
5465.
6892.
8730.
9649.
12405.
24.70
m.
6957.
7329.
8115.
7923.
10035.
11092.
14261.
2227.
2343.
2346.
2346.
5230.
6625.
7322.
9414.
2765.
3037.
3113.
3148.
5737.
7267.
8032.
10327.
234 6.65 2V8
3'12
5
511,
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
l.
STDmAPIIPETRO RP 7G-ENGL 3998
W 0732290 0609683 222
m
RECOMMENDEDPRACTICE FOR DRU STEM DESIGNAND OPERAllNG LIMITS
Tool Joint Data
DIill Pipe Data Nominal Weight' Size
in.
4.85
Nominal
Approx.
Weight lbift
lm
upset
234
6.65
OD
com.
in.
ID in.
in
pipe3
Tool Jointo
Pb+
Tool Join@
1.625
97817.
313681.
4763.
6875.b
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
6.99
EU
N a 6 0
1.625
138214.
313681.
6250.
6875.b
6.89
Eu Iu Eu
OH
1.625
138214.
294620.
6250.
6484.b
N
m
PAC
1.250
138214.
238504.
6250.
4688.P
SN90
1.670
138214.
202850.
6250.
5129.p
NC310
2.000
135902.
447130.
8083.
12053.p
OH
2.253
135902.
223937.
8083.
5585.P
2.2%
135902.
260783.
8083.
7628.p
2.253
135902.
289264.
8083.
7197.p
6.93
N Eu
7.05
Eu
7.31
Eu
wo
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
Sm90
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.B
10.58
NC380
2563
194264.
587308.
14146.
18107.p
OH
2.804
194264.
392071.
14146.
1 1870.p
9.99
Eu EU EU
Sm90
2.847
194264.
366705.
14146.
12650.p
10.14
Eu
wo
2.804
194264.
419797.
14146.
12878.p
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 Iu
OH
2.414
271569.
559582.
18551.
17305.p
13.40
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
11.85
13.00
Iu Eu
H90
2688
230755.
913708.
19474.
35374.p
NC460
3.125
230755.
901164.
19474.
33625.p
Eu Eu
OH
3.287
230755.
621357.
19474.
21976.p
12.91
wo
3.313
230755.
782987.
19474.
28809.p
15.04
Iu
N c 4 0
2.688
285359.
711611.
23288.
23487.p
3'1,
9.84
3'12
4
?srpe
Eu
7.50
274
10.40
13.30
lb
5.26
6.78
9.50
Torsional Yield, &lb
meld, Tensile
Drift
4.95
6.71
6.85
11
13.52 12.10
14.00
S
m
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 Institute Licensed by Information Handling Services
API RECoMMENDED PRACTICE 76
12
DlillPipeD;lta Nominal
Si m.
Weight Ib/ft
14.00
15.70
13.75
Appmx. Weight1 15.02
Eu
cnm.
in.
Tensile Yield, lb
ID in.
D a DiamEte9 Tool
Torsional A-lb Yield,
Tool
f i @
in.
pipe'
J&P
3.125
285359.
759875.
23288.
27289.p 15170.P
Joint6
14.35
Iu
2.438
285359.
512035.
23288.
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
15.23
Iu Eu
3.125
270034.
938403.
25907.
38925.p
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
18.14
IEU
2.875
330558.
976156.
30807.
34780.p
17.92
IEU
3.125
330558.
938403.
30807.
38925.p
17.95
Eu
3.625
330558.
939096.
30807.
37676.p
17.07
Eu IEU
3.625
330558.
713979.
30807.
27243.p
2.563
330558.
587308.
30807.
18346.P
18.37
IEU
3.125
330558.
901164.
30807.
33993.p
21.64
IEU
2.875
412358.
976156.
36901.
34780.p
21.64
IEU
2.875
412358.
1085665.
36901.
45152.p
36901.
41235.p
16.79
20.00
OD
'Qpe
upset
15.36
16.60
Tool Joint Data
2159
Eu
3.452
412358.
1025980.
22.09
IEU
2.875
412358.
1048426.
36901.
39659.p
24.11
3.452
471239.
1025980.
40912.
41235.p
24.56
Eu IEU
2.875
471239.
1048426.
40912.
3%59.p
22.28
IEU
3.625
395595.
1448407.
41167.
60338.b
20.85
IEU
3.625
395595.
939095.
41167.
37676.p
28.27
IEU
3.375
530144.
1619231.
52257.
60338.b
26.85
IEU
3.375
530144.
1109920.
52257.
44673.p
21.90
23.78
3.875
437116.
1265802.
unlo.
56045.p
24.70
26.30
IEU 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.p
22.82
19.50
25.60
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
RECOMMENDED PRACTICE FOR DRU S T E M DESIGN AND OPERATING L"
DrillPipeData NominalNominal Approx. Weight' Size Weight in. l m lbht 6.65
in.
in
pipe'
Tool Joint4
pipe'
Joint5
3% 3V4
1.625 1.670
175072 175072.
313681. 270223.
7917. 7917.
6875.b 6884.p
7.11 6.99
EU4105 EU4105
31 ', 3V,
1.625 1.670
193500. 193500.
313681. 270223.
8751. 8751.
6875.b 6884.P
11.09 10.95
EU-x95 EU-X95
4lI8 4
1.875 1.875
271503. 271503.
495726. 443971.
14635. 14635.
13389.p 13218.p
10.40
11.09 10.95
EU4105 EU4105
4'Ia 4
1.875 1.875
300082. 300082.
495726. 443971.
16176. 16176.
13389.p 13218.p
10.40
11.55 11.26
EU-S135 EU-S 135
4Va 4l1,
1.500 1.500
385820. 385820.
623844. 572089.
20798. 20798.
17170.p 17213.p
14.60 14.62 14.06
EU-x95 EU-X95 EU-X95
SV4 5
343988. 343988. 343988.
664050.
4314
2.619 2.438 2.438
649158. 596066.
23498. 23498. 23498.
23833.p 20326.p m79.p
13.30
14.71 14.06
EU4105 EU-GlOS
5 4V4
2.313 2.438
380197. 380197.
708063. 596066.
25972 25972.
22213.p 20879.p
13.30
14.92 14.65 15.13
EU-S135 EU-S135 EU-S 135
5 5
5%
2.000 2.000 2.313
488825. 488825. 488825.
8424.40. 789348. 897161.
33392. 33392. 33392.
26515.P 28U78.p 29930.p
15.50
16.82
EU-x95
5
2.313
408848.
708063.
26708.
22213.p
15.50
17.03 16.97
EU4105 EUG105
5 SI4
2.000 2.438
451885. 451885.
842440. 838257.
29520. 29520.
26515.p 27760.p
15.50
17.57
EU-S135
SI2
2.125
580995.
979996.
37954.
32943.p
14.00
15.34 15.63 16.19
N-X95 N-X95 EU-X95
5'1, SI2
2.563 2.688 3.125
361454. 361454. 361454.
776406. 913708. 901164.
29498. 29498. 29498.
25673.p 35374.p 33625.p
14.00
15.91 15.63 16.19
N4105 N-G105 EU-G105
511,
2.313 2.688 3.125
399502. 399502. 399502.
897161. 913708. 901 164.
32603. 32603. 32603.
301 14.p 35374.p 33625.p
16.19 15.63 16.42
N-S135 N-S135 EU-S 135
5'1,
5'1, 6
1.875 2.688 2.875
513646. 513646. 513646.
1080135. 913708. 1048426.
41918. 41918. 41918.
36363.p 35374.p 39229.p
15.70
17.52 17.23 17.80
lux95 N-x95 EU-X95
5V2 5'12 6
2.313 2.688 3.125
410550. 410550. 410550.
897161. 913708. 901164.
32692. 32692. 32692
301 14.p 35374.p 33625.p
15.70
17.52 17.23 17.80
N-G105 N-G105 EUG105
5'12 5'1, 6
2.313 2.688 3.125
453765. 453765. 453765.
897161. 913708. 901164.
36134. 36134. 36134.
301 14.p 35374.p 33625.9
15.70
18.02
EU4135
6
2.875
583413.
1048426.
46458.
39229.p
274
3lI2
4
corm.
Drift Diameter? Tool
EU-x95 EU-X95
6.65
13.30
Typeupset
ID in.
7.1 1 6.99
231,
10.40
Mechauicalhpexties Xeld, lb T m i o d Yield, &lb
Tool Tensile Joint Data OD
13
14.00
6 5lI2 6
16.60
4lI2
18.33 18.11 18.36 18.79
IEU-x95 IEU-x95 EU-X95 IEU-x95
6 6 6% 6V4
2875 3.125 3.625 2.875
418707. 418707. 418707. 418707.
976156. 938403. 939095. 1048426.
39022. 39022. 39022. 39022.
34780.p 38925.p 37676.p 3%59.p
16.60
4V2
18.33 18.33 18.36 18.79
IEU-G105 IEU-G105 EU4105 IEU-G105
6 6 6% 6'14
2.625 3.125 3.625 2.875
462781. 46278l. 46278l. 46278l.
976156. 1085665. 939095. 1048426.
43130. 43130. 43130. 43130.
34780.p 45152.p 37676.p 39659.p
19.19
IEU-S 135
6l1,
2.375
595004.
1235337.
55453.
44769.p
16.60
(Table continued on next page.) COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
STD.API/PETRO
RP ?G-ENGL L998
m
0 7 3 2 2 9 0 0609684 T 3 1 M
API RECOMMENDEDPRACTlCE 7 6
14
Table 9"echanical
Properties of New TodJoints and New High Strength Drill Pipe (Continued)
18.62 19.00
EU4135 EU-S 135
3'1, 231,
3.375 2.625
595004. 595004.
1109920. 1183908.
55453. 55453.
44673.p 44871.p
22.39 21.78 22.08 22.67
m-x95 Eux95 EU-X95 IEU-x95
211, 3'Ib 3'12
2.375 3.125 3.375 2.625
522320. 522320. 522320. 522320.
1235337. 938403. 1109920. 1183908.
46741. 46741. 46741. 46741.
44265.p 38925.p 44673.p 44871.p
22.39 22.00 22.08 22.86
IEU-G105 IEU-G105 EUX3105 IEU-G105
214 3 3lI2 211,
2.375 2.875 3.375 2.375
577301. 577301. 577301. 577301.
1235337. 1085665. 1109920. 1307608.
51661. 51661. 51661. 51661.
44265.p 45152.p 44673.p 4%30.p
20.00
23.03 23.03
EU-S135 EU-S135
3 211,
2.875 2.125
742244. 742244.
1416225. 1419527.
66421. 66421.
57800.p 53936.p
22.82
25.13 24.24 24.77
IEU-x95 N-X95 IEU-X95
21 ', 3l1, 231,
2.125 3.375 2.625
596903. 596903. 596903.
1347256. 1109920. 1183908.
51821. 51821. 51821.
48912.p 44673.p 44871.p
22.82
24.72 24.96
EU43105 IEU-G105
3'1, 211,
3.125 2.375
659735. 659735.
1268963. 1307608.
57276. 57276.
51447.p 4%30.p
22.82
25.41
EU-S135
231,
2.625
848230.
1551706.
73641.
63406.p
501087. 501087. 501087.
1448407. 1176265. 1109920.
52144. 52144. 52144.
60338.b 51807.p 44673.p
20.00
20.00
231,
22.62 21.93 21.45
IEU-x95 m-x95 IEu-x95
3% 3'1, 3'1,
3.625 3.125 3.375
19.50
22.62 22.15 21.93
IEU-G105 IEUX3105 IEU-G105
331, 3 3lIb
3.625 2.875 3.125
553833. 553833. 553833.
1448407. 1323527. 1268963.
57633. 57633. 57633.
60338.b 58398.p 51447.p
19.50
23.48 22.61
IEU-S135 EU-S135
3'1, 231,
3.375 2.625
712070. 712070.
1619231. 1551706.
74100. 74100.
72627.p 63406.p
25.60
28.59 27.87
IEU-x95 IEU-X95
3'1, 3
3.375 2.875
671515. 671515.
1619231. 1416225.
66192. 66192.
60338.b 56984.b
25.60
29.16 28.32 29.43
IEU-Gl05 IEUGlM EU4135
3'1, 231, 3'1,
3.375 2.625 3.125
742201. 742201. 954259.
1619231. 1551706. 1778274.
73159. 73159. 94062.
72627.p 63406.b 76156.b
24.53 24.80
m-m IEU-x95
3% 3lI2
3.625 3.125
553681. 553681.
1448407. 1268877.
64233. 64233.
60338.b 59091.p
21.90
25.38
IEUGl05
3l1,
3.375
611963.
1619231.
70994.
21.90 24.70
26.50 27.85
m4135
m-m
3 3l1,
2.875 3.375
7809. 629814.
1925536. 1619231.
91278. 71660.
=.P 873419 726279
24.70 24.70
27.85
27.n
IEU43105 EU4135
3V2 3
3.375 2.875
696111. 894999.
1619231. 1925536.
79204. 101833.
72627.p 87341.p 73661.p 86237.p la9226.p
1950
25.60 21.90
25.20 25.20 25.20
27.15
m-m
2820 29.63
IEUX3105 EU4135
5 4V4 4l/,
4.875 4.625 4.125
619988. 685250. 881035.
1448416. 1678145. 2102260.
89402. 98812. 127044.
27.70 27.70
30.1 1 30.1 1 31.54
m-x95 EU43105 EUS135
431, 4% 411,
4.625 4.625 4.125
676651. 747250. 961556.
1678145. 1678145. 2102260.
106813. 137330.
27.70
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
96640.
86237.p 86237.p 1092269
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 Torqueof Weld-on Type Tool Joints Based on Torsional Strengthof Box and Drill Pipe
Drill Pipe
Tool New
Nom Nominal Size Weight -Upset in. lWft a n d m 231,
Min.
Joint Data
Conn.
New OD m.
New
ID in.
Make-up T-d fi-lb
%.BOX Make-up OD Shoulder Torque for Tool withEccen- b&. OD Joint Wear tricwear tricJoint Joint Tool in. in. ft-lb
Min. OD Tool
in.
%.BOX Make-up Shoulder Torque fa with Eccen- Min. OD Tool Joint m. ft-lb
4.85 4.85 4.85 4.85
EUE75 EU-E75 EU-E75 EU475
NC26 W.O. 234 OHLW 234 SLHW
3% 3% 314 3v,
4,125 B 2,586 P 2,713 P 3,074 P
1,945 1,994 1,830 1,996
6.65 6.65 6.65 6.65
WE75 EU-E75 EU-E75 EU-E75
231, PAC NC26 231, SLHW 231, OHSW
271, 334 3v4 31/,
2,813 P 4,125 B 3,074 P 3,891 B
2,455 2,467 2549 2,324
2318
6.65
EUX95
NC26
6.65
EU-G105
NC26
3% 33/,
4,125 B
234
4,125 B
27j8
6.85 6.85 6.85 6.85
EU-E75 EU-E75 EU-E75 EU-E75
NC31 274 wo 274 OHL.W 271~SGHW
41/, 4V8 pl, 374
7,122 P 4,318 P 3,351 P 4,575 P
3,154 3,216 3297 3.397
10.40 10.40 10.40 10.40 10.40 10.40
EVE75 IU-E75 WE75 EVE75 EUE75 WE75
NC3 1 274 XII NC26 274 OHSW 271, S L H ~ 274 PAC
414 41/, 334 37/8 374 31/,
7,122 P 7,969 P 4,125 B 5,270 P 6,773 P 3,439 P
4,597 4,357 4,125 4273 4,529 3,439
4 '.4
10.40 10.40
EU-x95 EU-x95
NU1 271, SGHW
41/, 37/,
7,918 P 6,773 P
5,726 5,702
5/32 5/32
10.40
EU-G105
NC31
411,
7,918 P
6.1 10
4,969 4,915 5,345
10.40
EU-Sl35
NC31
434
10,167P
7,694
6,893
9.50 9.50 9.50 9.50
EU-E75 EU-E75 EU-E75 EU-E75
NC38 NC38 3'4 OHLW 3V2SGH90
431, 431, 43/, 454
7,688 P 10,864P 7,218 P 7.584 P
5,773 5,773 5,340 5,521
13.30 13.30 13.30 13.30 13.30 13.30 13.30
EWE75 WE75 EU-E75 EWE75 EU-X95 EU-X95 EU-X95
NC38 NC3 l2 331, OHSW 3V2H90 NC38 3V2SGHW 3V2H90
43/, 41/, 43/, 5'1,
10,864P 7,122 P 10,387 P 14,300P 12,196 P 11,137 P 14,300P
7274 6,893 7,278 7,064 8,822 8,742 8,826
5
13,328 P
9,879
742
12,569 12,614
'1%
234
274
2718
311,
5
454 511,
2y6 231,
'164
1,689 1,746 1,589 1,726
'164
2,055
"16
2204
I132
%4
5454
1,996 2075
3,005
342
2734
3,279
7/y(
3,005
'Il6
2,804
314
13.30 EU-G105
NU8
314
13.30 13.30
EU-S135 EU-S135
NC40 NC38
5
17,958 P 15,909P
15.50
EUE75
NC38
5
12,196 P
7,785
15.50
EU-X95
NC38
5
13,328 P
9,879
15.50 15.50
EU-G105 EU-G105
NC38 NC40
5 514
15,909 P 16,656P
10,957 11,363
3v2
15.50
EU-S135
NC40
s/,
19,766P
14,419
4
11.85 EU-E75 11.85 EU-E75
NC46 4 WO
6 5%
20,175 P 17385 P
7,843 7,843
"16
'I16
2,876
5/64
2666
"16
2,666
7164 %2
7/64 7k4
"la
%2
'1%
1 3/32
3.867 3.664 3,839 3.941 3,770 3.439
4.797 4,797 4,868 5,003
5
u68
13/64
6110
%2
6399
7454
3/~6 9/64
%2
8,822
7132
9,595
"Iw
6,487 7,785 7,647 7,646 8,822 10,768 10,957 6,769 9,348
"164 5/a
11,963 6,476 6,476
(Table conhued on next page.) COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
m
0732290 D b 0 9 b 8 b 804
m
API REC~MMENDED PRACTICE 7 6
16
Table 1+Recommended Minimum OD* and Make-upToque of Weld-on Type Tool Joints of Box and Drill Pipe(Continued) Based on Torsional Strength (2)
(3
(1)
(6)
C (9) I)
(8)
(13)
((12) 10)
(11) class2
m B O x
New Tool Joint Data Nominal Size in.
4
4
4
New
NOm
weight W U P W
ID
New
lblft
corm.
5'1,
11.85
IU-E75
40HLW 4 H90
14.00 14.00 14.00 14.00 14.00
IU-E75 EU-E75 IU-E75 EU475 IU-E75
NC40 NC46 4 SIP 4 OHSW 4 H90
14.00 14.00 14.00
IU-X95
in.
Make-up
Tasue6
OD
SI2
3"In 2VI6
fi-lb 13,186 P 21224 P
S I 4 6 @I0 5'1, 5'1,
2VI6 3V4 294, 31 '4 2u1,6
14,092P 20,175 P 9,102 P 16,320 P 21,224 P
NC40
SI4
EU-X% IU-X95
NC46 4 H90
6 SI2
211116 15,404 P 3V3 20.175 P 2u116 21324 P
14.00 IU-G105 14.00 EU4105 14.00 IUG105
NC40 NC46 4 H90
511,
andGrade 11.85 EU-E75
6 SI2
m.
271,~ 3V3 2VI6
Make-up Toque for with Eccen- Min. OD tdc Wear Tool Joint in. ft-b %.Box
Make-up Shoulder Toque for with Eccen- Min. OD tric Wear Tool Joint in. fi-lb
91a 7J64 V16 9/61
Isla
'I4 3116
Y,
shoulder
7,866 7,630 9,017 9233 8,782 9,131 8,986
'164 3J32
3116
7,877 7,843 7,817 7,839 7,630 9,595 9,937 9,673 10,768 10,647 11,065
Il.,
14,288
'I32
7Ja 134,
5 7J64
11,363 11,363 11,065
'va
151a llla
'J32 5J32
18,068 P 20,175 P 21224 P
7132 7 1 ~
12,569 12,813 1 ~
23,538 P
¶Ip
15,787
Ila
10,179 9,937 9,673
"Iw
5J32
'la
12,569 12,813 n,a1
"la "la 3116
~
1
6,593 6,962
4
14.00
EU3135
3NC46
6
4
15.70 15.70 15.70
IU-E75 EU4375 WE75
NC40 NC46 4 H90
SI4 6 5V,
2VI6 3'13 2u116
15,404 P 20,175 P 21224 P
15.70 15.70 15.70
IU-X95 EU-X95 IU-x95
NC40
SI,
2llL6
3 NC46 4 H90
6 5V,
2'VI6
18,068 P 23,538 P 21224 P
15.70 EU4105 15.70 IU-GlOS
3 NC46 4 H90
6 SI,
V ' a
2YI6
23,538 P 21224 P
'I4
13,547 13,922
134,
12,085 11,no
15.70 IU-S135 15.70 EU3135
NC46 NC46
6 6
254 271~
26,982 B 25,118 P
"la 21164
18.083 18,083
'Va
15,035
15,035 "I4
13/64
3314 3314 3'14
20,868 P 20.3% P 16,346 P 22,836 P 23,355 P
12.125 12,085 11,862 11,590 12,215
10,072 10,647 "la 10,375 Va 10,773 51% 10,642
14,945 15,035 14,926 15,441
'la 'la 3116 l3la
12,821 12,813 13,245 13.102
'1, 'I, "la "la
14,231 14,288 14,082 14,625
2'1a
18,083 18,367
4
4 4 4V,
4ll2
4'1, 4V1
4ll1
7 1 ~
16.60 16.60 16.60 16.60 16.60
IEU-E75 EUX75 IEU-E75 EU-E75 IEU-E75
4'31, FH 3V4 NC46 4'11 OHSW NC50 4'11 H-90
6 6l1, YI0 @I8 6
16.60 16.60 16.60 16.60
lEU-X95 IEu-X95
6 6'1, VIg 6
231,
IEu-X95
4'11 FH NC46 NCM 4'1, H-90
16.60 IEUGl05 16.60 IEU-GlO5 16.60 EU4105 16.60 IEU4105
4'12 FH NC46 NC50 3 4'1. H-90
6 6'14 VIg 6
231, 3 YI,
23,843 P 23,795 P 22,836 P 27,091 P
194,
'I4 "la
16,391 16346 16,633 16264
16.60 IEU-S135 16.60 EU-Sl35
NC46 NC50
611, VIg
231,
26923P
3Y2
27,076 P
"la 211a
21930 21,017
20.00 20.00 20.00 20.00
IEU-ms mm75 EUX75 IEu-E75
4V2FH 3
NC46 NCM 4'11 H-90 3
6 6'1, @Ig 6
3 3V0
20.868 P 23,795 P 24.993 P 27,091 P
20.00 20.00 20.00 20.00
IEu-x95 IEu-x95 EU-x95 m-x95
4'12 FH NC46 NCM 4'12 H-903
EUX95
6
et, @I0
6
3V,
3314 3
211, 231~ 3ll2
23,843 P 20.3% P 22,836 P 27,091 P
131~
"I4 51%
3116
'lia 'Ila 'I, 'Va
'1, '1,
14,231 14,288 "la 14,082 'la 13,815 17,861
26359 P
"la 18,083
27.076 P 27,091 P
l7la
l9la
17,497 17,929
'18 '18
l3la
8,444 8,535 8,305 10,768 10,647 11,065
"Iw
vp 131~
134,
"la 3116 91a 'la 151~
V ,
12125 12,oss 12,415 12215 15,665 15,787 15,776 15,441
(Table continued m next W.) COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
STD-API/PETRO RP
7G-ENGL
RECOMMENDED PRACTICE
L978
m 0732270 0607687 790 m
FOR DRU STEM DESIGNAND OPERATING LIMITS
17
Table 1&Recommended Minimum OD* and Make-up Toque of Weld-on TypeTool Joints Based on Torsional Strengthof Box and Drill Pipe (Continued) (3) (1) (13)
(4)
(12) (2)
(11)
(10)
(9) (5)
(8)(6)
(7)
premiumclass
m Pipe lWft
New JointTool
Data
New OD
New
Make-up
ID
in.
m.
Torqd ft-lb
Min. OD Tool Joint
class 2
Make-up Shoulder 'Ibrquefor withEccen- Min. OD eicWear ToolJoint in. &lb Min. BOX
Min. OD
&.BOX Make-up Shoulder Torque for with Eccen- Min. OD tdc Wear Tool Joint in. %lb
Nominal Nom Size -Upset Weight in. andGrade
C0nn.
20.00 IEU-GlOS 20.00 EU-G105
NC46 NC50
29,778 P 27,076 P
19,644 20,127
17,311 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 19.50
EU-X95 EUX95
NC50 5 H-90
27,076 P 31,084 P
20,127 19,862
17,497 17,116
NC50
m.
Tool Joint
in.
19.50 EU-G105 19.50 EUG105
5 H-90
3 1,025P 35,039 P
21,914 21,727
19244 18,940
19.50 IEU-S135 19.50 IEU-S135
NB0 51f2FH
38,044 P 43,490 P
28,381 28,737
24,645 24,412
25.60 25.60
EU-E75 EU475
NC50 5112FH
27,076 P 37,742 B
20,127 20,205
17,497 17,127
25.60 25.60
IEU-X95 Eux95
NC50 511, FH
34,680 P 37,742 B
25,569 25,483
21,914 22294
25.60 EU-G105 25.60 IEU-Gl05
NC50 5l/, FH
38,044 P 43,490 P
27,437 27,645
23,728 24,412
25.60 IEU-S135
5'1, FH
47,230 B
35,446
30,943
21.90
5V2FH
33560 P
19,172
17,127
5V2FU 5'12 H-W
37,742 B 35,454 P
24,412 24,414
21m 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
5'1, FH
33,560 P
22294
19,172
24.70 IEU-X95
5'1, 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 EU-x95 EU-G105 IEU-S135
@I8FH VI8FH @I8FH @I8FH
44,1% P 44,196 P 5 1,742 P 65,535 P
26,810 35,139 37,983
48204
24,100 29,552 33,730 42,312
27.70
EUE75 IEU-x95 EU-G105 IEU-S135
@I8FH @I8FH @I8FH
44,1% P 51,742 P 51,742 P 65.535 P
29,552 37,983 40,860 52,714
25,451 32,329 36,556 45241
EU-E75
21.90 IEU-x95 21.90 IEU-x95
EU-E75
VI8FH
'The use of outside diameters (OD)smaller than those listed in the. table may be acceptable due to special service requirements. Tool joint with dimensions shown has lower torsional yield ratio than the 0.80 which is generally used. 3Recommended make-uptoque is based on 72,000 psiSWS. 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 an outside diameter less thanAm bevel diameter should be providal with a minimum Vu inch depth x 45 degree bevel on the outside and inside diameter of thebox shoulder and outside diameter of the pin shoulder. 6p=Phlimit,B=B~~limit *Todjoint diameters specifiedare q u i r e d to retain torsid m n g t h in the tool joint comparableto the.torsional strength of the attached drill pipe. These should be adequate for all service.Tool joints with torsional strengths considerablybelow that of the drillpipe may be adequate for much drilling serviœ.
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
~
API RECOMMENDEDPRACTICE 76
18
Table 11 “Buoyancy Factors
33 .a66
.32
(1)
(2)
(3)
Mud Density Wgal
Mud Density WcuA
Buoyancy Factor, Kb
8.4 8.6 8.8
62.84
X72
32 81 31
9.0 92 9.4 9.6 9.8
80 30 .80 29 79
10.0 10.2 10.4 10.6 10.8
29 78
11.0 11.2 11.4 11.6 11.8
77 27
75
12.0 12.2 12.4 12.6 12.8
74 0.24 1.74 3.23
13.0 13.2 13.4 13.6 13.8
4.73 6.22 7.72 0922 0.71
14.0 14.2 14.4 14.6 14.8
2.21
15.0 152 15.4 15.6 15.8
26 76
.768
1520 6.70 8.19
9.69 .752
2.68 4.18 5.67
7.17 8.66 0.16
16.0 162 16.4 16.6 16.8
3.15
17.0 17.2 17.4 17.6 17.8
8.39
18.0 18.5
2.13 5.87
19.0 19.5
131.66
20.0 COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
65.83 68.82
362 359 356 .850
.W .841
332 85.28
326
.a20 89.77
.817 314
94.25
.an .804
97.25
.801
.n4 .771 113.70
121.18
1 134.65
-725
149.61
.694
STD-API/PETRO
RP 7G-ENGL
m 0732290 0609689 513 m
1998
RECOMMENDEDPRACTICE FOR DRIU STEM DESIGN OPERATING AND
LIMITS
19
Table 1"-Rotary Shouldered Connection Interchange List
Full Hole (EH.)
2.876
4
2
271:
3.391
4
2
311,"
4.016
4
2
4"
4.834
4
2
411,"
5.250
4
2
4
4.280
4
3.327 3v2-
(V-0.038 rad) v-0.065 (V-0.038 rad) v-0.065 (V-0.038 rad) v-0.065 (V-0.038 rad) v-0.065 (V-0.038 rad)
N.C. 262 3V2"Slim Hole N.C. 312 4V2"Slim Hole N.C. 382 4V2"Extra Hole N.C. 462 5" Ekdm Hole N.C. 502 5V; Double Streamline
2
v-0.065 (V-0.038 rad)
4V2" Double Streamline N.C. W
4
2
3V," Double Seeamline
3.812
4
2
4V2"
4.834
4
2
5"
5.250
4
2
v-0.065 (V-0.038 rad) v-0.065 (V-0.038 rad) V-0.065 (V-0.038 rad) v-0.065 (V-0.038 rad)
271:
2.876
4
2
311,"
3.391
4
2
4"
3.812
4
2
4V;
4.016
4
2
311;
3.327
4
2
4'1,"
4.280
4
2
5V,"
5.250
4
2
2.876
4
2
V-0.038 rad
31
3.391
4
2
V-0.038 rad
38
4.016
4
2
V-0.038 rad
40
4.280
4
2
V-0.038 rad
46
4.834
4
2
V-0.038 rad
50
5.250
4
2
V-0.038 rad
4V2"
3.812
A
2
v-0.065 (V-0.038 rad)
Extra 271," (E.H.) Q.H.) Hole
Slim Hole (S.H.)
Double Streirmline
(DSL)
Numbered Connection (N.C.) 26
ExtemalFlush @F.)
with two ttxead forms shown may be machined with either thread form without 1~0nnectims %umberedconnections (N.C.) may be machined only with the V-0.038 radius thad form
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
4" Slim Hole 4V2"Extemal Flush 4" IntanalFlush N.C. W 4l1," IntemalFlush N.C. 502 S1I2" Double Streamline
v-0.065 (V-0.038 rad) v-0.065 (V-0.038 rad) v-0.065 (V-0.038 rad) v-0.065 (V-0.038 rad)
234" Internal Flush N.C. 262 21'; Internal Flush N.C. 31a 3V," Exea Hole 4V," Extemal Flush 3V2"Internal Flush N.C. 38,
v-0.065 (V-0.038 rad) v-0.065 (V-0.038 rad) v-0.065 (V-0.038 rad)
21':
gauging or interchangeability.
Extra Hole
4" Full Hole N.C. W 4V2"htemal Flush 5" Extra Hole N.C. 502
Z3/: Intemal Flush 27/gl(Slim Hole 271: Iutemal Flush 3V; Slim Hole 3'1,'' Internal Flush 4'1," Slim Hole 4" Full Hole 4lI; Double Streamline 4" Intemal Flush 4lI; Extra Hole 4V," InternalFlush 5" Extra Hole 4" Slim Hole 3lI; Extra Hole
API RECOMMENDEDPRACnCE 7 6
20
Figures 1 -2+Torsional Strength and Recommended Make-up Toque Curves (All curves based on120,000 psi minimum yield strength and60 percent of minimum yield strength for recommended make-uptoque.)
Tool Joint Pin 1.0.
Figure 1-NC26 Torsional Yield and Make-up
3.375
8 i?
"
3.125 .
"
2.875
I
I
I
8
5: k
7
F
I
8ni
'8 E$! Cr! N
Tool Joint Pin I.D.
Figure 2-234, Open Hole Torsional Yield and Make-up
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
I
8 u!
N
RECOMMENDEDPRACTICE FOR DRU STEM DESIGN 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 Wide Open Torsional Yield and Make-up
O
z
onal yield strength Mb
snded make-uptoque
<
Wb
,
2.875
1
I 8 ~
2
8 Ln 7
Tool Joint Pin I.D.
Figure
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
4-2V8
SLHSO Torsional Yield and Make-up
x
~~
S T D - A P I I P E T R O R P 7G-ENGL 1998
m
0732290 Ob09692 008
API RECOMMENDEDPRACTlCE 76
22
Torsional vield strenath
7
r
7
Tool Joint Pin I.D.
Figure
I
O
R
7
5-2V8
PAC Torsional Meld and Make-up
I
I ¿i
8
I
Cu
cri
Tool Joint PinI.D.
Figure M C 3 1 TorsionalMeld and Make-up
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
O O
u! Cu
I
m
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 DESIGNAND OPERATlNG LIMITS 23
rength
' I rcn O
'
F
L
8
I
9
n!
(u
(u
8Ri
' 5 rc : '
Tool Joint Pin I.D.
Figure
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
8-z7/,
Wide Open Torsional Yield and Make-up
N
8v5
API REC~MMENDED PFIACTICE7 6
24
ni Tool Joint Pin I.D.
Figure 9-2’/,
Open Hole Torsional Yield and Make-up
11 yield strength ftllb
Recommendedmake-up toque ftllb
2.750
I
I I
8
I
i r
7
Tool Joint Pin I.D.
Figure 1C+27/8 PAC Torsional Yield and Make-up
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
I
STD.API/PETRO RP
7G-ENGL
L998
m 0732290 0607695 817 m
RECOMMENDED PRACTICE FOR DRU STEM DESIGNAND OPERATING LIMITS
5.125
4.875
Recommerbded make-up toque Mb
3
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-up
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
25
API REWMMENDED PRACTlCE 7 6
26
trength
Figure l M V 2 FH Torsional Yield and Make-up
Torsional yield strength
Recommended ma Mb
Tool Joint Pin I.D.
Figure 14-3V2
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
Open Hole Torsional Yield and Make-up
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 DESIGNAND OPERATING LIMITS
4.000
"
8
-
ST! v
8 ) n c 8 8 ,
3.750
6
%
O
O
:: m c
.-C
v
8
8
8
(o
o
8
W
O
"
Torsional yield aren Mb
(o
6
O
-O
7
82
PC
O
8
(D
I-"
Recommended make-up toque fttlb
3.500
;j
(o
O
CD
-0
8 v)
3.250
8I r
J
Figure J k1 F F
PAC L Torsional Tool Joint c j Pin Yield I.D.and
N Make-up
4.875 O O O
N
6 O
4.625
i
I
Torsional yield strength Mb
8
I
O
Recommended make-uptoque
8
I
I
Tool Joint Pin I.D.
Figure 16 - 3 V 2
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
XH Torsional Yield and Make-up
I
27
~~
STD.API/PETRO RP
~~
7G-ENGL
API
28
L998
m
0732290 Ob09698 526
RECOMMENDED P M C E 7 6
5.500
Wlb
5 5.000 -
2
f
L
4.500
r-
.-
..
oi
I
ci Tool Joint Pin 1.0.
Figure 174C40TorsionalYield and Make-up
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
ci
m
STD.API/PETRO
RP 71;-ENGL
L998
m
0732290 Ob09699 4b2
RECOMMENDED PRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS
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-up
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
m 29
~~~
S T D - A P I / P E T R O R P 76-ENGL 1998 PRACT~CE RECOMMENDED
30
6.000
m
API
~
0732290Ob09700
T04
76
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!
I
Tool Joint PinI.D.
Figure 22-4V2 H90 TorsionalYield and Make-up
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
Qf
m
STD-APIIPETRO RP 7G-ENGL
m
3778
RECOMMENDEDPRACTICE FOR
0 7 3 2 2 9 0 0607703 740
m
LIMITS
DRIUSTEM DESIGN OPERATING AND
Figure 23-4V2 Open Hole (Standard Weight) Torsional Yield and Make-up
".:
6.500
%-o-
O
8
I
Torsional yield strength Wb
7
SI-
lk 2
5.750
Recom&nded makeup toque Mb
I
I
5N: Tool Joint Pin I.D.
Figure 24-NC50 Torsional Yield and Make-up
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
31
7G-ENGL L998
STD.API/PETRO RP
m
0732290 Ob09702 8 8 7
API RECOMMENDED PRACTICE 76
32
+ Tool Joint Pin I.D.
Figure 25--5V2 FH TorsionalYield and Make-up
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
STD.API/PETRO
RP 7G-ENGL
L998
m
0732290Ob09703
RECOMMENDED PRACTICE FOR DRIU STEM DESIGN OPERATlNG AND
713
m
LIMITS
33
4.12 The recommendedmake-uptorque fora usedtool joint is determined by taking the following steps:
detexminhg the minimum acceptable bending strength ratio for aparticular area and type of operation.
4.1 2.1 Select the appropriately titled curve for thesize and type tool joint connection being studied.
5.7 Certain other precautions should be observed in using these charts.It is imperative that adequate shoulder width and area at the end of the pin be maintained. The calculations involvingbending strength ratios are basedon standard dimensions forall connections.
4.1 2.2 Extend a horizontal line from the OD under consideration to thecurveand read therecommendedmake-up torque representing the box. 4.12.3 Extend a vertical line h m the ID under considerread the recommended make-up torque ation to the curve and representing the pin. 4.12.4 Thesmallerofthe two recommendedmake-up torques thus obtained is the recommended make-up torque for the tool joint. 4.12.5 A make-up torque higher than recommended may be requiredunder extreme conditions.
5 Properties Of Drill Collars 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 sizes. Values in the table may be used to provide the basic information required to calculate the weights of drill collar strings that are not made up of collars having uniform and standard weights. 5.2 Recommended make-up torque valuesfor rotary shouldered drill collar connections are listed in Table14. These values are listed for various connection styles and for commonly used drill collar OD and ID sizes. The table also includes a designation of the W& member @ i n or box) for each connection size and style. or 5.3 Many drill collarconnection failms are aresultof 26 bending stresses ratherthantorsionalstresses.Figures through 32 may be used for determining the most suitable connection tobe used on new drill collars orfor selecting the new connection to be used on collars which havebeen worn down on the outside diameter. 5.4 A connection that has a bendingstrength ratio of 2.50 1 is generallyaccepted as anaveragebalancedconnection. However, theacceptablerange mayvary from 3.20:l to 1.90: 1 depending upon the drilling conditions.
5.8 Minordif€erences between measuredinsidediameter 26 through 32 are of little sigand inside diameters Figures in nifìcance; therefore select thefigure with the inside diameter closest to measured inside diameter. 5.9 The curves in Figures 26 through 32 were determined
from bending strengthratios calculated by using the Section Modulus (Z) as the measure of the capacity of a section to resist any bending momentto which it may be subjected. The effect of stress-relief features is disregarded. The equation, its derivation, and an example of its are useincluded inA.lO.
6 Properties of Kellys 6.1 Kellys are manufactwd with one of two drive confìgurations, square or hexagonal. Dimensions are listed in Tables 2 and 3 entitled “Square Kellys” and “Hexagon Kellys” of API Specification 7. 6.2 Square kellys are furnished as forged or machined in the sections are normaldrive section. On forged kellys, the drive ized and tempered and the ends are quenched and tempered. 6.3 Hexagonal or fully machined square kellys are may be either machined from round bars. Heat treatment 6.3.1 ing;
Full lengthquenchedandtemperedbeforemachin-
I
6.3.2 The drive section nonnalized and tempered and the ends quenched and tempered. It should benoted that fully quenched drivesections have normalized drive higher minimum tensile yield strength than sections when tempered to the same hardness level. For the same hardness level, the ultimate tensile strength may be considered as the samein both cases. 6.4 The following criteria shouldbe considered in selecting square or hexagonal kellys.
6.4.1 It may be noted from Table 15 that the drive section of the hexagonal kellyis strongerthan the drive section of the idly thanthepininsidediameter,theresultingbending square kelly when the appropriate kelly is selected for a given strength ratio will be reduced accordingly. When the bending casing size. 2.00:1, connectiontroublesmay strengthratiofallsbelow Example: A 4V4-inch square kellyor a5V4-inch hexagonal begin.Thesetroublesmayconsistofswollenboxes,split kelly would be selected for use in 85/8-inch casing. thread. boxes, or fatigue cracks in the boxes at the last engaged It should benoted, however, that the connectionson these 5.6 The minimum bending strength ratio acceptable in one two kellys are generally the same unless and the bores (inside operating area may not be acceptable in another. Local operat-diametem) are the same, the kelly with the smaller bore could ing practices experience based on recent predominance of be interpreted to have the greater pin tensile and torsional strength. failuresandotherconditionsshouldbeconsidered when 5.5 As the outside diameter of the box w liwear more rap
Vext continued on page 46.)
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
I
STD=API/PETRO RF "G-ENGL L998
API REMENDED
34
m 0732290 0609704
657'
m
P M C E 76
Table 13"Drill Collar Weight (Steel) (pounds per foot)
20
inches
1
11 ',
2'4
19
18
16
3
21
20
18
22 3V0
22
3'14
26
24
22
3'12 3'33 14
30
29
27
4
40
35
131,
2
2935
32
39
37
43
41
39
37
35
41 ',
46
44
42
3540
38
4'12
51
50
48
46
43
41
4314
52
50
47
54 59
10
12
313
3'1,
64
60
75
72
68 76
3V2
VI,
4
32
4'4
11
3
32
44
56
53
50
68
65
63
60
57
75
73
70
67
64
82
80
78
67 75
72
90
88
85
83
79
61
60
98
%
94
91
88
83
72 80
107
105
102
99
%
85 91
89
80
116
114
111
108
105
93 100
98
89
125
123
120
117
114
110
107
103
98
93
84
134
132
130
127
124
119
116
112
108
103
93
144
142
139
137
133
129
126
122
117
113
102
154
152
150
147
144
139
136
132
128
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
160
155
150
210
208
m
m3
u)(]
195
192
179 188
184
234
232
230
227
224
220
216
212
2 0 9 2 0 6
198
248
245
243
240
237
232
229
225
221
211
261
259
257
254 235 251
239246
243
310
307
302
299
295
371 342
368 347 364
352 361
357
315
317
377
379
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
374
174 216
2 3 0 2 2 5 291
286
281
7G-ENGL
STDmAPI/PETRO RP
L998
m
0732290 Ob09705 5 9 6
m
RECOMMENDED PRACTICE FOR DRILL STEM DESIGNAND OPERATING LIMITS
35
Table 14"Recommended Make-up Torque' for Rotary ShoulderedDrill Collar Connections (See footnotes for use of this table.) (2)
(13)(5)
(1)
(12) (6)
connection Size, 1v4 in.
1'1W 2
OD, 1V4 in.
(11) Q (10) (8) (9) Minimum Make-up Toque ft-lW Bore of Drill collar,i n c h 2134, 2121, 211,
1
3
*2,508 *3,330 3,387
*vos
W 1 *3,028 335
*231 2,574 2,574
1,749 1,749 1,749
*3,797 *4,966 5 m *4,606 5,501
*3,797 4,151 4,151 *4,606 4,668
2926 2,926 2926 3,697 3,697
*3,838 5,166 5.766
*3.838 4.95 1 4,95 1
*3,838 4,002 4,002
Mod. open
*4,089 *5,352 *&O59
*4,089 *5,352 *&O59
*4,089 *5,352 7,433
APIIF NC 31
*4,640 *7,390
*4,640 *7,390
*4,640 *7,390
*4,640 6,853
Regula
*6.466 *7,886 10,47 1
*6,466 *7,886 9,514
*6,466 *7,886 8,394
*6,466 7,115 7,115
5,685 5,685 5,685
Slim Hole
*8,858 10,286
*8,858
8,161 8,161
6,853 6,853
5,391 5,391
*9,038 12,273 12,273
*9,038 10,826 10,826
*9,038 9,202 9302
*5,161 *8,479 11,803 11,803 1 1,803
*5,161 *8,479 10,144 10,144 10,144
*5,161 8,311 8,311 8,311 8,311
NC 23
*2,508 *3,330 4,000
PAC?
API IF NC 26
3V,
2,647 2,647
Slim Hole
Extra Hole
Double streamline
NC 35
9.307
7,411 7.41 1 7,411
Extra Hole Slim Hole Mod.Open
*5,161 *8,479 *12,074 13,283 13,283
API IF NC 38
*9,986 *13,949 16,207 16,207
*9,986 *13,949 14,643 14,643
*9.986 12,907 12,907 12,907
9,986 10,977 10,m 10,977
8,315 8,315 8,315 8,315
*8,786
*17,094 18,522
*8,786 *12,794 16,929 16,929
*8,786 *12,794 15,137 15,137
*8,786 *12,794 13,151 13,151
*8,786 10,408 10,408 10,408
*10,910 *15,290 *19,985 20,539 20,539
*10,910 *15,290 18,886 18,886 18,886
*10,910 *15,290 17,028 17,028 17,028
*10,910 *10,910 14,%9 12125 14,969 12,125 14,969 12,125 14,969 12,125
Slim Hole
H-W
Full Hole
NC 40 Mod. Open Double StFeamline
* 12,794
(Table continued on next page.)
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
STD.API/PETRO
411,
RP 7G-ENGL L998
H-W
* 12,590 *17,401 *%S31 25,408 25,408
*lu90 *17,401 *m31 23,671 23,671
APIRegular
*15,576 *20,609 25,407 25,407 *20,895 *26,453 27,300 27,300
NC 44
411,
API Full Hole
*12,590 *17,401 21,714 21,714 21,714
*12,590 *1u90 *17,401 16,536 19,543 16,536 19,543 16,536 19,543 16,536
* 15,576
*15,576
*20,609
*20,609
23,686 23,686
21,749 21,749
*15,576 *15,576 19,601 16,629 19,601 16,629 19,601 16,629
*20,895 25,510 25,510 25,510
*20,895 23,493 23,493 23,493
*20,895 21,257 21,257 21,257
*12,973 *18,119 *23,605 27,294 27,294
*12,973 *18,119 *23,605 25,272 25,272
*12,973 *12,973 *12,973 *18,119 *18,119 17,900 19,921 17,900 23,028 19,921 17,900 22,028 19,921 17,900 22,028
*17,738 *23,422 28,021 28.021 28,021
*17,738 *17,738 *17,738 20,311 *23,422 22,426 25,676 Z 4 2 6 20,311 25,676 22,426 20,311 25,676 22,426 20,311
*18,019 *23,681 28,732 28,732 28,732
*18,019 *18,019 *18,019 *23,681 23,159 21,051 26,397 23,159 21.051 21,051 26,397 23.159 23,159 21,051 26,397
Extra Hole
NC 46 A P I IF semiIF Double Stmadine Mod. open H-W
5
H-W
$25,360 *31,895 35292 35,292
-3,004 *29,679 *36,742 38,379 3&379 38379 *N508 *41,993 42,719 42,719 *31,941 *39,419 42,481 42,481
*25m *31.895 32,825 32,825
*23.004 *29.679 35.824 35,824 35,824 35,824
$25,360 29,400 29,400 29,400
-560 27,167 27,167 27,167
23,988 23,988 23,988 23,988
*23,004 *29,679 32377 32,277 32277 32,277
%,o04 -9,679 29,966 29.966 29,966 29,966
*23,004 26,675 26,675 26,675 26,675 26,675
*34m *Nm
m
M 0732290Ob0970b422
40,117 40.117 40.117
36,501 36,501 36,501
34,142 34,142 34,142 34,142
30,781 30,781 30,781 30,781
*31.941 *39,419 3939,866
"31,941 36235 36,235 36,235
*31,941 33,868 33,868 33,868
30,495 30,495 30,495 30,495
18,161 18,161 18,161 18,161
("able amtinued m next page.)
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
m
S T D = A P I / P E T R O RP 7G-ENGL 1996
RECOMMENDEDPRACTICE FOR DRILL %M
0732290Ob07707369
m
DESIGNAND OPERATING LIMITS
37
Table 14-Recommended Make-up Torque' for Rotary ShoulderedDrill Collar Connections (Continued) (See footnotes for useof this table.)
SI2
API Full 7 Hole
*32,762 *40,998 *49,661 51,687
*32,762 *40,998 47,756 47,756
*32,762 *40,998 45,190 45,190
*32,762 *m998 41,533 41,533
8
*40,498 *49,060 52,115 52,115
*40,498 48221 48,221 48,221
*40,498 45,680 45,680 45,680
*40,498 42,058 42,058 42,058
7V4 711, 7%
API
NC56
*32,762 *40,998 *49,661 54,515
7V, . 7'12 FI4
@la
APIRegular
7V2 r 1 4 8 SV4
*46,399 *55,627 57,393 57,393
*46,399 53,346 53,346 53,346
*46,399 50,704 50,704 50,704
*46,399 46,936 46,936 46,936
6Vg
H-W
711, 7% 8
*a509 *55,708 60,321 60,321
*46,509 *55,708 56,273 56,273
*46,509 53,629 53,629 53,629
*46,509 49,855 49,855 49,855
*55,131 '65,438 72,670 72,670 72,670
*55,131 *65,438 68,398 68,398 68,398
*55,131 *65,438 65,607 65,607 65,607
*55,131 61,624 61,624 61,624 61,624
*56,641 *67,133 74.626 74,626 74,626 74,626
*56,641 *67,133 70,277 70,277 70,277 70,277
*56,641 *67,133 67,436 67,436 67,436 67,436
*56,641 63,381 63,381 63,381 63,381 63,381
*56,641 59,027 59,027 59,027 59,027 59,027
*67,789 v9544 88,582 88,582 88,582
*67,789 *79,544 83,992 83,992 83,992
*67,789 *79J44 80,991 80,991 80,991
*67,789 76,706 76,706 76,706 76,706
*67,789 72,102 72,102 72,102 72,102
67,184 67,184 67,184 67,184 67,184
*75,781
*75,781 *88,802 %J14 %,214
*75,781 *88,802 90,984 90,984 90,984 90,984
811.
API
NC61
8 8V4 8'12
831~ 9 5'1,
API IF
8 811,
811, 83/4 9 9V4 6518
API Full Hole
81/,
831, 9 9V4 9V2 API
NC70
9 9V4 9V2 10 lOV,
*75,781 V5,781 *75,781 *88,802 *88,802 *88,802 *102,354 *102,354 * l a 3 5 4 113,710 108,841 105,657 113,710 108,841 105,657 113,710 108,841 105,657
*108,194 *108,194 *108,194 *108,194 *108,194 *108,194 *124.051 *124,051 *124,051 *124,051 *124,051 *124,051 140,488 135,119 129,375 *140,491 *140,491 *140,491 154,297 148,%5 145,476 140,488 135,119 129,375 154,297 148,965 145,476 140,488 135,119 129,375
9314
API
NC77
10 lOV, lOV, lov4 11
7
H-9CP
8 8V4 SV,
7V8
APIRegular
8'1, 831.4
*88,802
101,107 101,107 101,107 101,107
%514 96,214
*53,454 *63,738 *74,478
*53,454 *63,738 72,066
*53,454 *63,738 69,265
*53,454 *63,738 65,267
*53,454 60,971 60,971
*53,454 56,382 56,382
*60,402
*60,402
*60,402
*60,402
*60,402
*60,402
V2,169
*72,169
*72,169
*72169
V2.169
*72,169 (Table continued on next page.)
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
STD-API/PETRO RP 7G-ENGL L998
9V4 9V2 H-W
9 9114 9'12
96,301 96,301
91,633 91,633
13,017 13,017 *86,006 *86006 *W,= *99,508
88,580 88,580
84,221 84221
79.536 79,536
74.529 74,529
'73,017 *86,006
*73,017
13,017 *86,006 *5508
u73.017 *86,006
*99,508
*86,006 $99,508
%,285
10 1011, lO1lZ
*109,345 *109,345 *109,345 *109,345 $109,345 *109,345 *125,263 *125,263 *125,263 *125,263 *125,263 125.034 125,034 *141,767 *141,767 141,134 136,146 130,777
H-W
1011, 1ov2
*113,482*113,482 *130,063*130,063
H-W
8V4
8VU
( w i t hlow torqueh) 9 7V8
Ob09708 2T5
API REC~MMENOED PRACTICE 7 6
38
7
m 0732290
M I Resular ( w i t hlow toquetäœ)
H-W ( w i t hlow toque face)
9114
9'12 9% 10 914
10 1011, 1ov2
lW14 ( w i t hlow toque faœ)
11 1111,
H-W
1W14
( w i t hlow torquefaœ)
11 1111,
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
*113,482 *113,482 *113,482 *113,482 *130,063 *130,063 *130,063 *130,063 *68,061 71,361
67,257 67,257
62,845 62,845
58,131 58,131
*73,099 *86,463 91,789 91,789
*73,099 *86,463 87,292 87,292
*73,099 82,457 82,457 82,457
$73,099 77339 77339 77,289
91,667 *91,667 *91,667 *106,260 *l062a * l m 117,112 113,851 109,188 117,112 113,851 109.188
*91,667 104,171 104,171 104,171
*91,667 98,804 98,804 98,804
*68,061 74,235
*112,883 *112,883 *112,883 *112,883 *130,672 *130,672 *130,672 *130,672 147,616 142,430 136,846 130,871
*92,%o *%%o *%%o *%%o *110,781 *110,781 *110,781 *110,781 *129,203 *129,203 *129,203 *129,203
m
7G-ENGL
STDmAPIIPETRORP
L998
0732290 Ob09709 L31
RECOMMENDEDPRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS
39
143' 1.0. 3.5
3.0
2.5
2.0
1.5
3.5
3.0
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
2.5
2.0
1.5 BENDING STRENGTH RATIO
3.0
Figure 26-Drill
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
3.5
3.0
2.5
2.0
BENDING STRENGTH RATIO
Collar Bending Strength Ratios, 1V2-and 13/,-lnch ID
-
1.5
API RECOMMENDED PRACTlCE 7 6
40
2.
Ia
TO OBTAINBENDING STRENGTH RATI0,YEASURE QD. 8 1.0.OF DRILLCOLLAR AT POINTS SHOWN IN ABOVE ILLUSTRATION
3.5
3.0 2.5 2.0 1.5 BENDING STRENGTH RATIO
3.5 3.0 2.5 2.0 BENOW STRENGTH RATIO
Figure 27-Drill Collar Bending Strength Ratios,2- and 2V.,-lnch ID
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
1.s
STD.API/PETRO RP ?G-ENGL
LqsA
RECOMMENDED PRACTICE FOR DRIU-M
E O732270 06077LL 8 7 T E
DESIGNAND OPERATING LIMITS
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
BENDING STRENGTH BENDING RATIO STRENGTH
I.S
3.5
3.0
2.5
2.0 RATIO
Figure 28-Drill Collar Bending Strength Ratios, 2V2-lnch ID
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
1.5
~~
STD.API/PETRO
~
RP 7G-ENGL 3998 0732290 Ob09732 72b
API RECOMMENDEDPRACTlCE 7 6
42
13
2161 o.
2 8 1D
'
16'
35
30
2.5
2.0
1.5
3.5
3.02.0
2.5
1.5
O U T
S I
D E
D
I A M
E T E
R
I:.
I 3.5
TO OBTAINBENDING STRENGTH RATI0,MEASURE QD. 8 1.0.OF DRILL COLLAR AT P W T S SHOWN IN ABOVE ILLUSTRATION
3.0
2.5
2.0
1.5
BENDING STRENGTH RATIO
3.5
2.5 2.0 BENblffi STRENGTH RATIO
3.0
Figure 2 W r i l l Collar Bending StrengthRatios, 213/l,-lnch ID
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
-
1.5
STD.API/PETRO
RP 7G-ENGL L998
m
0732290 Ob09733 662 H
REWMMENDEDPRACTICE FOR D R U STEM DESIGNAND OPERATING LIMITS
3' I.D. -
3.5
3.0
43
3 ' 1.D. 2.5
2.0
Figure 3(+l3r¡lI
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
1.5
3.5
3.0
2.5
Collar Bending Strength Ratios, 3-Inch ID
2.0
1.5
~
~~
~
~~~
STD.API/PETRO
RP 7G-ENGL
1998
m
0732290 06097L4 5T9
API RECOMMENDED P W C E 76
44
TO OBTAIN BENDING STRENGTH RAT10,MEAWRE QD. B 1.0. OF DRILL COLLAR AT POINTS SHOWN IN ABOVE ILLUSTRATION 1
3.5
3.0 2.5 2.0 1.5 BENDING STRENGTHBENDING RATIO
3.5
2.5 2.0 STRENGTH RATIO
3.0
Figure 3 1 4 r i l l Collar Bending Strength Ratios, 3V4-lnchID
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
I5
m
S TD.API/PETRO
RP 7G-ENGL
L998
RECOMMENDEDPRACTICE FOR DRILL %M
m
0 7 3 2 2 9 0 O b 0 9 7 3 5 Y35
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 BENDING STRENGTH BENDING RATIO
Figure 32-Drill
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
3.5
30
2.5
2.0
STRENGTH RATIO
Collar Bending Strength Ratios, 3l/,-lnch ID
' 1.3
STD.API/PETRO RP
7G-ENGL L998
0732290 ObO973b 3 7 1
m
API RECOMMENDEDPRACTlCE7G
46
6.42 For a giventensile load, the stress level is less in the
hexagonal section. 6.4.3 Lhe to the lower stress level, the endurance limit of the hexagonal drive section is greater in terms of cycles to failure for a given bending load.
I
m
6.5.1 Remachining Before attemptingto remachine a kelly, it should be fully inspected for fatigue cracks and also dimensionally checked to assure that it is suitable for remilling. The strength of a remachined kelly should be compared withthe strength of the drill pipe with whichthe kelly is to be used. (SeeTable 17 for drive section dimensions andstrengths.)
6.4.4 Surface decarburization (decarb) is inherent in theas forged square kelly which further reduces the endurance limit in terms of cyclesto failurefor a given bending load. Hexago- 6.5.2ReversingEnds nal kellys and fully machined squares have machined surUsuallybothendsofthekellymust be buttwelded faces andare generally free of decarb in the drive section. (stubbed) for this to be possible as the originaltop is too short and the old lower end is too smaU in diameter for the comes6.4.5 It is impractical to remove the decarb from the com- tions to be reversed. The welds shouldbe made in the upset 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 upsetto aid in the prevenwelding p m x x h m s must be used to prevent cracking and to tion of fatiguecracks in this area. Machining ofsquare kellys recondition the sections where welding been has performed. from round bars could eliminate this undesirable condition. 6.6 The internal pressure at minimum yield for the drive section may be calculated from EquationA.9. 6.4.6 The life of the drive section is directly relatedto the A square drive section normally kelly fit with the kelly drive. 7 DesignCalculations will tolerate agreater clearance with acceptable lifethan will a hexagonal section. A diligent effort by the rig personnel to 7.1DESIGNPARAMETERS maintain minimum clearance between the kelly drivesection It is intended to outline a step-by-step procedure to ensure and the bushing will minimize this consideration in kelly complete consideration of factors, and to simpw calculaselection. New roller bushing assemblies working on new tions. Derivaton of formulas may be reviewed in Appendix kellys will develop wear pattems that are essentially flat in A. The following design criteria must be establish& shape on the driving edgeof the kelly. Wearpattems begin as point contacts of zero width near the comer. Thepattern wida Anticipated total depth with this string. ensasthekellyandbushingbegintowearuntilamaximum b. Hole size. wear patternis achieved. The wear rate will be the least when c. Expected mud weight. the maximumwear pattern width is achieved. Figure 33 illusd 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.The information in Table16 f. Length of drill collars, OD, ID, and weightper foot. and Figures33 and 34 may be used to evaluate the clearances g. Desired drill pipe sz i es,and inspection class. between kelly and bushing. This evaluation should be made assoonasawearpatternbecomesapparentafteranew 7.2SPECIALDESIGNPARAMETERS assembly is put into service. If the actual wall thicknesshas been determined byinspecExample: At thetime of evaluation, the wearpattern width tion to exceed that in API tables, higher tensile,co a l pse,and for a 51/4-inch hexagonal kelly is 1.00 inch. internalpressure values maybe used fordrill stem design.
This could meau one of the followingtwo conditions exist: a If the contact angle is less than 8 d e m 37 minutes, the original clearances were acceptable. The wear pattern is not
fully developed b. Ifthecontactangleisgreaterthan8degmes37minutes, the wear pattern is fully developed. The clearance is greater than is recommeadedand should be corrected. 6.5 Techniques for extending life of kellys include remachining drive sections to a d e r size and reversingends.
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
7.3 SUPPLEMENTAL DRILL STEM MEMBERS Machining of the connections to A P I specilìcations and the properheat~tofthematerialshallbe&neon~supple mental dxill stem members, such as subs, stabilizers, tools,etc. 7.4TENSIONLOADING The design of the drill string for statictension loads requim sufficient strength in thetopmost joint of each size, wei@t, grade, and classification of drill pipe to support the submerged weight of all the drill pipe plus the submerged
STD.API/PETRO RP
7G-ENGL
199B
D 0732290 Ob09717 208 D
RECOMMENDEDPRACTICE FOR DRU STEM DESIGNAND OPERATING LIMITS
Table 1-rength (2)
(1)
1)
(1
Lowerpinconnection M Kellysi andm
in.
Recommn&-l
Kelly
Bore in.
..
Size and iStyle n.
OD in.
(6) (10)
of Kellys' 0) (9)
(8)
Internal pressure at Torsional Yield
Yield Tensile
Ipwerpin
Drive
casing OD C~nnection~ Section
lb
47
lb
yield in Bending
yield
Drive
h e rThrough pin Drive
Drive Section fi-lb
Connection
Section
&lb
fi-lb
12,300 29.800 13,000
Section
Psi
211, square
111,
416,000
444 4 ,00
9,650
3s q-
131~
535,000
582,500
14,450
19.500
22,300
25,500
3'12
2'1,
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
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
4'14 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
3V,
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
117,000
206 ,00
I A U values havea safety factor of 1.O and are based on 1 10,000 psi minimum tensile yield (quenched andtempered) for connections and 90,000 psi minimum tensile yield(normalized and tempemi) for the drive section. Fully quenched andtempered drive sections will have higher valuesthan those s hown.Sbear strength is based on 57.7 percent of the minimum tensile yieldstrength. zclearance between protects rubber on kelly saver sub andcasing inside diameter should also be checked. Tensile area calculated at mot of thread V4 inch h m pin shoulder.
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
~
RP 7G-ENGL L998 m 0732290 O b 0 9 7 3 8 L44 m
STD.API/PETRO
API REC~MMENDED PMCE
48
76
5 Il4' 6'
Small contact angle
pattern
Flat surface no curvature luare 3xagonal I O
I
I
l
I
I
I
I
25
SO
.75
1.00
1.25
1.50
200
2.25
Note:DriveEd~winhaveawideflatpatternwithsmall contact angle.
Figure M e w Kelly-New Drive Assembly
Figure M e w Kelly-New Drive Assembly
Table 16"contact Angle Between Kelly and Bushingfor Development of Maximumwidth Wear Pattern
~~
2'1, 5O41'3
-
~~
-
.O15
-
~
5"3Y 11%
.o15
.1w
15"s
.1w
1451'
.O15
5%'
.o60
SO14 1092'
.O15
4V4
.o15
4'48
.o60
9-34'
.o15
13'36' 4O4S
4"W
.m .m
12"16' 89T
.123 .O15
4"17'
8"4
-
451' 6
.O15
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
165Y
.o60
3lI2
5l1,
.lo7
-
.123
-
-
S T D - A P I I P E T R O RP 7G-ENGL
1994
0332290 0609339 080
RECQMMENDEDPRACTICE FOR DRILLSTEM DESIGN AND OPERATING LIMITS
49
Table 1"-Strength of Remachined Kellysl (5)
(1)
(4)
(3)
(2)
R e m a c h n ie d original Kelly size Kelly Kellysize and and 'I)rpe in.
m
in.
LowerPincoMection BOß3 in.
Size and Style
Torsional Xeld
Tensile Xeld
OD
m.
LcnverPin conllection~
Drive
Lowerpin
section
connection
lb.
lb.
Wb
Xeld in Bending TImughDrive
section fvlb
NC50 (4%W
@/S
1,344m
834,400
55,500
36,200
47,800
411, square
4 square
2'18
NC46 (4
6V4
1,011,600
834,400
38,300
36,200
47,800
511, square
5 square
33/,
511, IF
7%
1,924,300
1317,600
92.700
65,000
90200
5 square 511,
3314
58,900
90,200 65,000
809,800
30,600 1,077,100
6Il4
809,800
1,196,800
@/S
9 9 9 9 ,0 0
1,077,600
m
1,217,600 FH 1,356.800 7
3'14 427/32Hex
5'1, Hex
3v4
NC46 (4
3'1,
NC50 (4% W
5V,
5 Hex
6 Hex
SI, Hex
119,900 109,100 4 1,300
6
SI, Hex
4lIa
0
74,000
30.600
78,500
83,300
4Q800
71,100
78,400
80.400
116,XlO 103.800
m
m
Hex
Drive section fvlb
(10)
2'18
(4
Hex
(9)
4 square
511, square
5
(8)
411,sq~
Hex 6'145V4NC46
ex
o
511,5 1,443,400 FH 1,189,Mo 7 5V2IF
7%
1,371,500 1,669,200
'AUvalues have a safety factor of 1.O and ax.based on 1 l0,OOO psi minimum tensile yield(quenched and tempered) for cOnnectiollS and O 9 0 ,O Opsi minimum tensile yield(normaked and for the driw section.Fully quenched and tempeml drive sections will have highex values thau those &mShear . strength is based on 57.7 pacent of the minimumtensile yieldseength. 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 table.
tem)
weight ofthe collars, stabilizer, and This bit. load may becalareas, wall thickness and yield strengths. The yield strength culated as shown inEQuation 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 the collar weight. begins, but the which permanent deformation of the material stress at which a certain total deformation has OcCuITed. This deformation includes all of the elastic deformation as well as P = [
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S T D - A P I I P E T R O R P 7 G - E N G L L778
m
0 7 3 2 2 7 00 6 0 7 7 2 0
8T2
m
API RECWMENDEDPRACTlCE 76
50
MOP=P,-P
(3)
The same values expressed as a ratio may be called the Safety Factor (SF). SF= pa P The selection of the pmper safety factor and/or margin of over pullis of critical importance and shouldbe approached with caution. Failureto provide an adequate safety factorcan result in loss or damage to the drill pipe while an overly conservative choice will result in an unnecessarily heavy and mure expensivedrill string. The designer should consider the overall drilling conditionsin the area, particularly hole drag and the likelihood of becoming stuck The designer must also consider thedegree of risk which is acceptable for the particular well for which the drill string is being designed. Frequently, the safety factoralso includes an allowance for slip crushing and for the dynamic loading, which results from accelefations anddeceledons during hoisting. Slip crushingis not a problem if slips and master bushings are maintained. Inspection class also grades the pipe with regard to slip crushing. l l idesire to determine the maxiN o d y the designer w mum length of a spedìc s z ie, grade and inspection class of drill pipe which can be used to drill a certain well. By combining Equation 1 and either Equation 2 or 3, the following equationsresult:
condition usually occurs during thedrill stem testing and may result in collapse of the drill pipe. The differential pssure requiredto produce collapsehas been calculated for various 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 allowable collapse pressure. PP = P,, SF
where PP = theoretical collapse pressure from tables, psi, SF = safetyfactor, P, = allowable collapse pressure, psi.
When the fluid levels insideand outside the drill pipe are equal and provided the density of thedrilling fluid is constant, the collapsepressure is zero at any depth, i.e., thereis no differential pressure.If, however, there shouldbe no fluid inside the pipe the actual collapse pressure may be calculated by the following equation: L W, P, = 19.251
or W, P, = L 144
where P, L W, W,
Ifthestringistobeataperedstring,i.e.,toco~stofmure
than one size, grade. or inspection class ofdrill pipe, the pipe having the lowest load capacity shouldbe placed just above thedrillcohandthemaximumlengthiscalculatedas
If there is fluid hide the drill pipebut the fluid level is not as high insideas outside or if the fluid insideis not the same weight as the fluid outside, the following equation may be
used:
shown previously. The next stronger pipe is placed nextin the stcingandtheWLterminEquation5or6isrepMbya term representingthe weight in air of the drill collars plus the d d l pipe assemblyin the lower string. Themaximumlength of the next strongerpipe maythen be calculated.An example calculation using the above formulasis included in7.8.
or
7.5 COLLAPSE DUE TO EXTERNAL FLUID PRESSURE
where
Thedrillpipemayatcertaintimesbesubjectedtoanexternal pressure which is higher than the internal pressure. This
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
= netcollapsepressure,psi, = the depthat which P, a cts,R, = weight of drilling fluid, lb/gal, = weight of drillingfluid lb/m ft.
P, =
L W,-(L-Y)Wi 19.25 1
P, =
L W , -(L- Y)W,' 144
Y = depthtofluidinsidedrillpipe,&, W,' = weight of drilling fluid insidepipe, lb/gal, W; = weight of drilling fluid insidepipe, lWcu ft.
STD.API/PETRO
RP 7G-ENGL L998
m
0732290 0607723 739
m
RECOMMENDED PRACTICE FOR DRU STEM DESIGNAND OPERATING LIMITS
7.6 INTERNALPRESSURE
51
where
L, = length of drill collars, feet, Bit, = maximum weight on bit, lb, a = hole angle from vertical, 3 degrees, NP = neutral point design factor determines neutral 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 calculation), The torsional strengthof drill pipe becomes critical when drilling deviated holes, deep holes, reaming, or when the pipe Kb = buOyatlCj' factOr, See Table 1 1, is stuck This is discussed under Sections 8 and 12. calcuW, = weight per foot ofdrill collars in air, lb, lated values of tonional strength for various sizes, grades, and 40,000 L, = inspection classes of drill pipe arep v d ie d in Tables 2,4,6, .998 x .85 x .847 x 90 ' and 8. The basis for these calculations is shown in Appendix = 618 feet, closest length based on 30 foot collars, is A. The actual torqueapplied to the pipe during drillingdif= 630 feet or 21 drill collars. ficult to measure, but may be approximated by the following
Occasionally the drillpipe may also be subjected to a net internal pressure. Tables 3,5,7, and 9 contain calculated values of the differential internalpressure required to yield the drill pipe. Division byan appropriate safety factor will result pressure. in an allowable net internal
equation:
g. Drill string size: weight andg r a d e 4 in 1 ./ x2 16.60 lb/ft x NC46 tool joints, 6'14 in. OD x 3V4 in.ID, Inspection Class 2. Grade E75, with 4V2 in.,
where T = torque deliveredto drill pipe, fi-lbs, HP = horse power usedto produce rotation of pipe, RPM = revolutions per minute. Note:Thetorqueappliedtothedrillstringshouldnotexceedtheactualtool joint make-up torque. The recommnded tool joint make-up toque is shown in Table 10.
7.8 EXAMPLE CALCULATION OF ATYPICAL DRILL STRING DESIGN-BASED ON MARGIN OF OVERPULL Design parametersare as follows:
a. Depth-12,700 feet. b. Hole sjze-7V8 inches. C. Mud Weight-10 lb/& d. Margin of overpull (MOPj50,OOO lb. (assumed for this calculation). e. Desired safety factor in collapse-l'/, (assumed for this calculation). f. Drillcollar data: 1. Length430 feet. 2. OD-6V4 inches. 3. &2V4 inches. 4. Weight per foot-90 lb. If the lengthof drill collars is not known, the followingformula may be used: L, =
Bit, CosaxNPx k b X W ,
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
From Equation 5:
(P,,X -9) - MOP W , X L, wdpl x K b - (225,771 X .9) - 50,000 90 X 630 18.37 18.37 x .847
=
"
"
= 9846 - 3087 = 6759 feet
It is apparent that drill pipe of a higher strength will be required to reach 12,700 feet. Add4V2in. x 16.60 lb/ft Grade X-95, with 4V2 in. X.H.tool joints, 6'4 in. OD x 3 in. ID (18.88 lb/ft) Inspect~onClass Premium. Air weight of Number 1 drill pipe anddrill collars:
Total weight = (L+l x W,,)
+ (Lcx W,)
= (6759 x 18.37) + (630 x 90)
= 124,163 + 56,700 = 180,863 lb.
From Quation 5:
- (329,542 x .9) - 50,000 180,863
"
18.88 x 18.88 .M7 = 15,420 - 9580 = 5840 feet
52
API RECOMMENDED PRACTICE 7 6
This is more drill pipe than required to reach 12,700 feet, so final drill string will consist of the following:
Item Drillcollars SV4"O.D. x 2V4"ID.
630
No. 1 Drill Pipe 4'4" x 16.60 lb, GradeE75,Qass2 105,166 124,163
56,700
48,025
6759
No. 2 Drill Pipe 4'4" x 16.60 lb, Grade x-95,
Remiumclass100,272
5311 12.700 238,121281,135
84,930
Torsional Yield of N," x 16.60lb x Grade E75 x Inspection Class 2 = 20,902 fi-lb. Collapse Pressure of 4V; x 16.60 lb x Grade E75 x Inspection Class2 = 5951 psi. Collapse pressure of 4V21) x 16.60 lb x Grade X-95 x PremiumInspection Class = 8868 psi. From Equation8:
LW, preSsureatbottomofdrillpipe:P,= 19.251 ' L = 12,070 feet, W,= 10 lb/@,
ing make-up and break-outoperations to preVent bending Of the pipe. There is a maximum height that the tooljoint may be positioned above therotary slips and thepipe to resist bending, whilethe maximum recommendedmake-up or " o u t torque is applied to the tool joint Many factors govern this height limitation.Severalof these which shouldbe taken into most serious considerationare:
a The angle of separation between the make-up and breakout tongs, illustratedby Case I andCase II, Figure 35. Case I indicates tongs at 90 degrees and Case II indicates tongs at 180 degrees. b. The minimum yield strengthof the pipe. c. The lengthof the tong handle. d The maximumrecommended make-up torque. H,. =
.O53 Y,LT (VC) (C= I) T
where
H , . = height of tool joint shoulder above slips, R, Y, = minimum tensile yieldstress of pipe, psi, L, = tong ann length, R, P = line pull(load), lbs, 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 may be encounted in drilling to 12,700 feet precautions should be taken to prevent damage to the drill pipe whenmning the string dry below 10,183 feet This is determinedby solving Equation 8 for maximum length of drill pipe, and dividing bythe safety factor in collapse of 1V 8 :
L=
P,x 19.251 W,
Sample calculation: Assume: 4V2-in., 16.60 lb/% Grade E drill pipe, with 4V2-in.X.H. 6'/4-in. OD,3V4-in. ID tool joints. Tong arm 31/2-R Tongs at 90(Case I). Using Equation 13:
+ 1.125
- 5951 x 19.251 10
= 11,456 + 1.125 = 10,183 feet 7.9 DRILL PIPE BENDING RESULTING FROM TONGING OPERATIONS
It is generally known that the tool joint on a length of drill pipe should be kept as close to the rotary slips as possible dur-
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
Y,
= 75,000 psi (for Grade E),
VC = 4.27 i n 3 (Table M),
L, = 3.5 R, T = 16,997 &lb (from Table lo),
STDmAPI/PETRO RP 7G-ENGL L998
m
0732290 Ob09723 501
m
RECOMMENDEDPRACTICE FOR DRILL STEM DESIGNAND OPERATING LIMITS
53
8 Limitations Relatedto Hole Deviation
Table 18-Section Modulus Values
8.1FATIGUEDAMAGE
0.66 0.87
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 angleandor direction, commonly called a dogleg. The amount of fatigue damage on the following: which results depends
10.40
1.12 1.60
8.1.1 Tensile
9.50 13.30 15.50
1.% 2.57 2.92
11.85 14.00 15.70
2.70 3.22 3.58
13.75 16.60 20.00 22.82
3.59 4.27 5.17
24.66 25.50
6.03 6.19
16.25 19.50 25.60
4.86 5.71 7.25
19.20 21.90 24.70
6.11 7.03 7.84
25.20
9.79
234 6.65 6.85
Figure &Maximum
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
5.68
Load in the Pipe at the Dogleg
Following isan example calculation:
a Data: 1. 4V2-inch, 16.60l b &Grade E, Rauge 2 drill pipe (actual weight in air including tooljoints, 17.8 1b/ft) ?/&ch OD, 2'/4-inch ID drill ~ 0 l ( a hc t u a lWeight in air 147 1Wft). 2. 15 lwgal(ll2.21 lb/cu. ft)mud. 3. (buoyancy factot = 0.771) 4. Dogleg depth.3,000 ft. 5. Anticipated total depth: 11,600ft. 6. Drill collar length: 600 ft. 7. Drill pipe lengthat total depth:1 1,000 ft. 8. Length of drill collar string, whose buoyant weight is on bit 100 ft. in excess of the weight b.Solution: Tensile loadin the pipeat the dogleg: [(11,000-3,OOO) 17.8+ 1 0 0 1471 ~ 0.771= 121,1241b
Height of Tool Joint Above Slips to Prevent Bending During Tonging
STD=API/PETRO RP
7G-ENGL L398
m
API REC~MMENDED -CE
54
8.1.2 The Severi¡ of the Dogleg
The number of cycles experiencedin the dogleg,as well as the mechanical dimensions and properties of the pipe itself. Because tension in the pipeis critical, a shallow dogleg in a deep hole often becomes a s o m of difficulty. Rotating off bottom is not a good practice sinœ additional tensile load 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 curvesto reduce fatigue damage. Programs to plan and drill wells to minimize fatigue have been reportedby Schenck3 andWilson4. Such programs are necessary to reduce fatigue damage. 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, theportion of the curve for which there is pipe to-hole contact between tool joints (dashed lines on Figures 36 and 38) becomes longer when tool joint OD becomes smaller, and convenely. The advent of electronic pocketcalculatm makes it easy to use the following equations instead of the curves in Figures 36 and 3 7 . ' ~ ~
0732290 Ob09724 '448
m
76
where D = drillpipeOD,inches, d = drill pipe ID, inches. The maximum permissible bendingstress, S,,is calculated from the buoyant tensile stress, S, @si). in the dogleg with Equations 19 and 20 below. S,is calculated with Equation 18:
where A = cross sectionalarea of drillpipe body, square inches. For GradeE l 4
Equation 19 holds true for values S,ofup to 67,000 psi. FOI Grade S-1351~
Ob
(
= 2000 "1
145qbk)
Equation 20 holds truefor values of upto 133,400 psi. The following equation may be used instead of Figure 38:
c = -108000 F XL T
maximum permissible doglegseverity (hole cur-), degrees per 100 feet,
Young's modulus,psi, 30 x 106 psi, for steel, 10.5 x 106 psi, for aluminum, drill pipe OD, inches, half the distancebetween tool joints, inches, 180 inches, for Range 2. Note.Equation15doesmtholdtr~forRange3."
T = buoyant weight (including tool joints) suspended below the dogleg, pounds, S, = maximum permissible bendingstress,psi, Z = drillpipemomentofinertiawithrespecttoits diamekr, i n 4 ,
calculated by Equation 17.
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
in which F is the lateral forceon tool joint (1000,2000, or 3000 pounds in Figure 38), and the meaning of the other symbols is the same as prwiously. 8.2
REMEDIAL ACTION TO REDUCE FATIGUE
If doglegs ofsuBident magnitude are present or suspected, itisg~practicetostringreamthedogleg~Thisreduces the severity of the hole angle change.With reference to Figure40,thefatiguelifeofdrillpipewillbedecreasedconsiderably whenit is used in a corrosive drilling fluid. For many water-base drilling fluids, the fatigue life of steeldrill stems may be incmsed by maintaining pH a of 9.5 or higher. Refer to 10.1.4 for description of a corrosion monitoring system. S e v d methods are available for monitoring and controlling the cormsivity of drilling fluids. The most commonly used monitoring technique is the use of a comsion ring insertedinthedrillstemForadescriptionofthistechnique see N I Recommended Plactice13B-1, Recommended Pmctice StMdard Pmeabre for Fieid Testing Water-BasedDriUing F l u a .
RECOMMENDEDPRACTICE FOR DRlU STEM DESIGNAND OPERATING LIMITS
55
Dogleg Severity-Degrees Per100 Feet O
1
2
3
4
5
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 Pipe
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
6
S T D - A P I / P E T R OR P
7G-ENGL
L998
m
0732290Ob09726
210
m
API RECWMENMD PRACTlCE 7 6
56
Dogleg Severity-DegreesPer 100 Feet
1
O
4
3
2
I In corrosive environments, reduce dogleg severity to a fraction (0.6 for very severe conditions) of the indicated value.
100
7 0 0 1 joint plus drill pipe all Range 2.
700
6
5
O
I
I
I
I
Figure 37"Dogleg Severity Limits for Fatigue of S-135 Drill Pipe
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
7G-ENGL
STD..LPI/PETRO RP
L998
m
0 7 3 2 2 9 0 Ob09727 L57
m
RECOMMENDED PRACTICE FOR DRILLSl'EM DESIGN AND OPERATING LIMITS
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Dogleg Severity-DegreesPer 100 Feet
O
1
2
3
4
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 Joint
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8.3 ESTIMATION OF CUMULATIVE FATIGUE
DAMAGE
Percent Fatigue Life Ewended in a 30 Foot lntervd
Hansford and Lubinsk.? have developed method a for estimating 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 to use as a guide in the identification of suspect joints. A corzection formula to use for other penetration rates and rotary speeds is as follows:
96 Life Expended= % Life Expendedfrom 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 results of themethod explained in8.3. Howeveryit is the only estimating cumulative fatigue method presently available for damage and should be used if it is possible to identi@ and classify fatigued joints. Thedifkulty lies in identifying and 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~fullyexamined and,if not downgraded or abandoned, watched as closely as possible. Such consideration should be finally governed by experience factors until such time as the analytical method for fatigue predictiongains more reliability.
For: Drill pipe, 31/., 471;' and 5' Grade E steel; rotary speed, 100 rpm; drilling rate, 10 feethour.
Figure 39-Fatigue Damage in Gradual Doglegs (Noncorrosive Environment)
Percent FatigueLife Expended in a30 Foot Interval
8.5 WEAR OFTOOL JOINTS AND DRILL PIPE When drill pipe in a doglegis in tension it ispulled to the inside of the bend with substantial force.lateral The force will increase the wear of pipe the and tool joints. When abrasion 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 at the dogleg. F p i 38 shows curves for 1000,2000, or 3000 lb lateral force on the tool joints; points to the left of these curves w lihave less lateral force, and points to the right more lateral force on the tool joints. F i p s 41, 42, 43, and 44, developed by Lubbki, show lateral force curves for both tool joints and drill pipe for three popular pipe sizes. The first threefi~arefor~pipesizes,Range2.Figure44isfor 5 - i n ~ 419.5lb foot, Range 3 drill pipe. 8.5.1 For conditions represented bypoints located to the i p 41, only tool left of Curve No. 1, such as Point A in f drill pipe between tool jointscontact the wall of joints and not the hole. This should notbe construed to mean the drill pipe
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For: Drill pipe, 3V;, 41h', and 5' Grade E steel; rotary speed, 100 rprn; drilling tate, 10 feethour.
Figure W a t i g u e Damage in GradualDoglegs (ln ExtremelyCorrosive Environment)
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REC~MMENDED PRACTlCE FOR DRILLSTEM DESIGN AND OPERATING LIMITS
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body does not wear at asall, Figure 41 is for a gradual and not 9 Limitations RelatedTo Floating Vessels for an abrupt dogleg. In an abrupt dogleg, drill pipe does con9.1 All possible steps should be taken to avoid subjecting tact the wallof the holehalf way between tool joints,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 afloater that contributeto fatigue of drill pipe are as follows: 8.5.2 Forconditionsrepresentedbypointslocated on 9.1.1 The rotary table is not c e n t e d at all times exactly Curve No. 1, theoretically the drill pipe contacts the wallof the hole withzero force at the midpoint between tool joints. above the subsea borehole. 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 of the floater. Curve No.1 and CurveNo. 2, theoretically the drill pipestill 9.2 This text pertains to prevention of fatigue due to factor contacts the wall of the hole at midpoint only, but with a force b, above. When the derrick is inclined during a part of the roll which is not equal to zero. This force increases from Curve or pitch motion, the upper extremity of the drill string is not No. 1 toward CurveNo. 2. Practically, of course, thecontact vertical while thedrill pipe at some distancebelow the rotary between thedrill pipe and the wall of the hole will be along a table r e &vertical. Thus the drill string is bent. As drill short length located near the midpoint of the joint. pipe is much less rigid than the kelly, most of the bending occurs in the first length of drill pipe below the kelly. This 8.5.4 For conditions represented bypointslocatedtothe subject is studied in a paper titled, Z’he Efect OfDrilLing Vesright of Curve No. 2, theoretically the drill pipecontacts the sel Pitch or Roll on Kelly and Drill Pipe Fatigue, by John E. arc with wallof theholenot at onepoint,butalongan Hamford andArthur Lubinski6 increasing lengthto the rightof CurveNo. 2. 9.3 Based on the Hamford and Lubinskipa@, the followOn each of the Figures41,42,43, and 44,there are in addiing practices mommended to minimize bending and, tion to curves No. 1 and No. 2, two families of curves: one for therefore, fatigue of the first joint of drill pipe, due to roll and the forceon tool joint, and the other for the on drill forcepipe or pitch of a f l o w . body. As an example, consider Figure 41; Point B indicates 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, or a one-plane roller bushing is prefd e p s per 100 feet, then the forceon tool joint is 6OOO lb, erable. and the force on drill pipe body is 3000 lb. 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 of the following means: Tool joints which are rotatedunderhighlateralforce a. For Range 2 drill pipe, use a 54-foot kelly which is ordiagainst the wall of the hole may be damaged as a result of narily used with Range 3 pipe, rather than the usuala f o o t friction heat checking. The heat generated at the surface of kelly. the tool joint by friction with the wall of the hole when under high radialthrust loads may raise the temperature of the tool b. Use a specially made kelly at least 8 feet longer than the 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 and drill pipe. ing hardness as much as 3/16-in.below OD surface. If the 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 than half way up for longperiods as it rotates. This action produces heatedandquenched of time if the maximum angular vessel motion is morethan 5 often accompanied by numerous irregular heat check cracks degrees single amplitude. In this text, long periods of time full secare: longer axial cracks sometimes extending through the 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 of Peímleum Technology, 1961.)’ Maintaining hole angle control so that 2000 lb lateral 9.3.4 If conditions prevent implementing b or c, above, the force is not exceeded w l iminimize or eliminate heat checkfirst joint of drill pipe below the kelly should be removed at the first opportunity and discarded. from the string ing of tool joints.
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API RECOMMENDEDPRACTlCE 7 6
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Forces on Tool Joints and Range 2 Drill Pipe 3V2-lnch,13.3 Pounds per Foot, Range 2 Drill Pipe, 43/,-lnch Tool Joints
Figure 4l"ateral
weg Severily ( M e CurVahrre)-Degreeg 5
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I
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I
Per 1O0 Feet 10
I
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15
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Figure 42"ateral Forces on Tool Joints and Range2 Drill Pipe 4V2-lnch,16.6 Pounds per Foot, Range 2 Drill Pipe, 6V4-lnchTool Joints
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RP 7G-ENGL 1 9 7 8
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0732290Ob09731
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RECOMMENDED PRACTICE FOR DRILL STEM DESIGNAND OPERATING LIMITS
Dogleg Severity (Hole Cunrature~egreesPer 1 0 0 Feet
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 Range3 Drill Pipe 5-lnch, 19.5 Pounds per Foot, Range 3 Drill Pipe, 63/,-lnch Tool Joints
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API RECOMMENDEDPWCE
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the n i d conductivity may result in higher c o n i o n rates. Concentrated salt solutions m usually less corrosive than dilute solutions; however,because of decreased oxygen 10.1 CORROSION solubility. Dissolved salts also may serveas a source of wbon dioxide or hydrogen Sulfidein drilling fluids. 10.1.1 Corrosive Agents Dissolvedsalts in drillingfluids may comefromthe Corrosion maybe de6ned as the alteration and degradarion makeup water, formation &lididow, drilled formations, or of material byits e h n m e n t . The principal corrosive agents drilling fluid additives. affecting drill stem materials in water-base drilling fluids are dissolved gases (oxygen, carbon dioxide, and hydrogensul10.1.1.5 Acids fide), dissolved salts,and acids. Acids corzode metals by loweringthe pH (causing hydrogen evolution) and by dissolving protectiveíilms.Dissolved 10.1.1.1 Oxygen oxygen appreciably accelerates the corrosion rates of acids, Oxygen is the mostcommon corrosive agent. In the presand dissolved hydrogensulfide greatly accelerates hydrogen ence of moistureit causes rustingof steel, the mostcommon embrittlement. form ofcomsion. Oxygen causes uniform corrosion and pitorganic acids (formic, acetic,etc.) Mn be formed in drillting,leading to washouts, twistoffs, andfatiguefailures. ing fluids by bacterial action or by thermal degradation of Since oxygenis soluble in water, and most drilling fluid sysorganic drilling fluid additives. Organic acids and mineral tems are open to the air, the drill stem is continually exposed acids (hydmchloric, hydrofluoric, etc.) may be used during to potentially sevem corrosive conditions. workover operations or stimulating treatments.
10 Drill Stem Corrosion and Sulfide Stress Cracking
10.1.1.2CarbonDioxide
Carbon dioxide dissolves in water to form a weak acid (carbonic acid) that corroda steel in the same manner as other acids (by hydrogen evolution),unless the pH is maintained above6. At higher pH values, carbon dioxide corrosion damage is similar to oxygencorrosiondamage, but at a slower rate. When carbon dioxideandoxygen are both p e n t , however, the corrosion rate is higher than thesum of the rates for each alone. Carbon dioxide in drilling fluids maycome h m the makeup water, gas bearing formaton fluid inflow, thermal decomposition of dissolved salts and organic drilling fluid additives, or bacterial action on organic material in the makeup wateror drilling fluid additives. 10.1.1.3Hydrogen
Sutfide
Hydrogen & d edissolves in water to form an acid somewhat weaker and less corrosive than calnmic acid, although it may causepitting, particularly in thepresence of oxygenand or carbon dioxide. A more signifìmt action of hydrogensulfide is its effect on a form of hydrogenembrittlement known as sulfide stress clacking (see 10.2 for details). Hydrogen sulíìde in drilling fluids may come from the makeup water, gas-bearing formation fluid inflow, bacterial action on dissolved sulfirtes,or thermal degradationof sulfurcontaining drilling fluid additives.
10.1.2 Factors Affecting Corrosion Rates Among the many factors a€fecting corrosionrates of drill stem materials the moreimportant are: 10.1.2.1
pH
This is a scale for measuring hydrogen ion concentration. The pH scale is logarithmic; i.e., each pH increment of 1.0 represents a tenfold change in hydrogen ion concentration. The pH of pure water, fkee of dissolvedgases, is 7.0.pH values less than 7 a increasingly acidic, and pH values greater than 7 are incmshgly alkaline. In the presenceof dissolved oxygen, the corrosionrate of steel in water is relatively constant between pH 4.5 and 9.5; but it increases rapidly at lower pH values,and decreases Slowly at higher pH values.A h num alloys, however, may show increasing corrosion rates at pH valuesgreater than 8.5. 10.1.2.2
Temperature
In general, corrosion rates inmase with inmasing temperature. 10.12.3
Velocity
In general, corrosion rates inarase with higher rates of flow.
Heterogeneity
10.1.1 A Dissolved S a l t s
10.1.24
Dissolved salts (chlorides, carbonates, and sulfates) increase the electrical conductivity of drilling fluids. Since most cormsion pmceses involve electrochemical d o n s ,
Localized variations in compositionor microstructure may increase corrosion rates. Ringworm corrosion,that is sometimes found near the upset areas of drill pipe or tubing that
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U 0732290 Ob09733 450
RECOMMENDEDPRACTICE FOR D R l U STEM DESIGNAND OPERATING LIMITS
has notbeen properly heattreated after upsetting, is an example of corrosion caused by nonuniform grain structure. 10.1.2.5
High Stresses
Highlystressed areas may corrode faster than areas of lower stress. The drill stemjustabovedrill collars often showsabnormal corrosion damage, partiallybecauseof higher stresses andhigh bending moments. 10.1.3 Corrosion Damage
(Forms of Corrosion)
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for an infinitenumber of cycles is knownas the fatigue limit. Remedial action for reducing drill stem fatigue is discussed in Section 8. In a corrosive environment no fatigue limit exists, since failure will ultimately occur from corrosion,even in the absence of cyclic stress. The cumulative effect of corrosion and cyclic stress (corrosion fatigue)greater is than thes u m of the damage from each. Fatigue lifewill always be less in a corrosive environment, even under mildly corrosive conditions that show little orno visible evidence of corrosion.
10.1.4 Detecting and Monitoring Corrosion Corrosion can take many forms and may combine with other types of damage (erosion, wear. fatigue, etc.) to cause The complex interactions between various corrosive agents extremely severe damageor failure. Several forms of com and the many factors controlling corrosion rates make it dBìsion 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 are: 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 Stundard Pmedure for Field Testing Water-BasedDrilling Fluids, During uniform attack, the material corzodes evenly, usucan be used to evaluate corrosive conditions and to follow the ally leaving a coating of corrosion products. The resulting effect of remedial actionstaken to correct undesirable condican lead to failure h m reduction of the loss in wall thickness tions. Preweighed test ringsare placed in recessesat the back material's load-carrying capability. of tool jointbox threads at selected locations throughout the drill stem, exposed to the drilling operation for a period of 10.1.3.2 Localized Attack (Pitting) time, then removed, cleaned, and reweighed. The degree and Corrosion may be localized in small, well-defined areas, severity of pitting observed may be of greater significance causing pits.Their number,depth, andsize may vary considthan the weight loss measurement. erably; and they maybe obscured by corrosion products.PitThe chemical testing of drilling fluids (see API Recomting 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 alkahity, the field whenever possible, especially tests for pH, crevices or other stagnantareas, in highly stressedareas, etc. and the dissolved gases (oxygen, carbon dioxide, and hydroPits can cause washouts and can serve as points of origin for gen sulfide). fatigue cracks. Chlorides, oxygen,carbon dioxide, and hydrogen sullide, and especially combinationsof them, are major 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 be collected in a II2 to 1 gallon Many metals resist corrosion by forming protective oxide (2 to 4 liter) clean container, allowingairanspace of approxfilms or tightly adherent deposits. If these fìlms or deposits imately 1 percent of the container volume and sealing tightly are removed or disturbed by high-velocity fluid flow, abrasive with a suitable stopper. Chemically resisting glass, polyethsuspended solids, excessive turbulence, cavitation, etc., accelylene, and hard rubber are suitable materialsfor most drillerated attack occurs at the fresh metal surface. This combinaing fluid samples. Samples should be analyzed as soon as tionoferosivewearandcorrosionmaycausepitting, possible, and the elapsed time between collection and analyextensive damage, and failure. sis reported.See ASTM D3370, Standard Practicesfor S m pZing Water, for guidance on sampling and shipping 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. If torch cuttingis needed,do it in away that will avoid physiwill develop fatiguecracks that may growuntil completefailcal or metallurgical changesin the area to be examined. Specure occurs. The limiting cyclicstress that a metal cansustain
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API RECOMMENDEDPRACTICE 7 6
h e n s must not be cleaned, wire brushed,or shot blasted in any mannw, and should be wrapped and shipped in a way that will avoid damage to the corrosion products or fracture surfaces.Whenever possible, both fracture surfaces should be supplied.
10.1.8 Extending
Corrosion Fatigue L i
W e generally not a€Fecting corrosion rates,the following measures will extend corrosion fatigue life by lowering the cyclic stress intensity or by increasing the fatigue strength of the material:
a Use thicker-walled components. b. Reduce highstresses near connections by mhimizhg dogInternally coating the ddl pipe and attached tool joints can legs and by maintaining straight hole conditions, insofar as p v i d e effective p r o e tc o i tn against corrosioninthepipe possible. . . . stress concentratomsuch as slip marks,tong bore. In the F e n c e of corrosive agents, however, the corroc. M sionrateoftheddlStemODmaybeincreaxxLDrillpipe marks,gouges, notches, scratches, etc. 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 (SSC) 10.1.7 Corrective Measures to Minimize Corrosion in Water-Base Drilling Fluids In the presence of hydrogen sulfide (H$), tensile-loaded drill stem components may suddenlyfail in a brittle manner The selection and control of appropriate corrective meaat a fraction of their nominal load-carrying capability after sures is usually performed by competent corrosion technoloperforming 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 hydrogen and is much more severe when H,S is present. The a. Control the drilling fluid pH. When practical to do so withbrittle failure of tensile-loaded steel in the presence of H,S is out upsetting otherdesired fluid pmperties, the maintenance sulflde stress clacking (SSC). termed of a pH of 9.5 or higher will minimize corrosion of steel in water-base systems containingdissolvedoxygen. In some 10.2.2 Materials Resistant to SSC drilling fluids,however, corrosion of aluminum drill pipe increases at pH values higherthan 8.5. The latest revision of NACE Standard “01-75, Suyide b. Use appropriate inhibitors and/oroxygenscavengers to Stress Cracking Resistant MekdlicMaterial for Oil Eeld Equip minimize weight loss corrosion. This is pafticularly helpfill ment, should be consulted for materialsthat have been found to with low pH, low solids drilling fluids. Inhibitors must be be satisfactory for drilling and well servicing operations. carefully selected and controlled,because different corzosive Other chemical compositions, hardnesses, and heat treatagents and different drilling fluid systems @aaicularlythose ments should notbe used in sour environments without fully used for air or mist ddling) require Merent types of inhibievaluatingtheir SSC susceptibility intheenvironmentin tors.The use of the wrong type of inhibitor, or the wrong which they will be used. Susceptibilityto SSC depends on the amount,may actuallyincrease corrosion. following c. Use plastic coated drill pipe. C~IC must be exercised to prevent damageto the coating. 10.2.2.1 Strength of the S t e e l d. Use degassers and desandento remove harmful dissolved The higherthe strength (hardness) of the steel, the greater is gases and abrasive material. the swceptibility to SSC. In general, steels having strengths e. Limit oxygen intake by maintaining tight pump connecequivalenttohardnessesupto22HRCmaximumareresistant tions and by minimizing. pit-jetting. to SSC. If the chemical compositionis adjusted to permit the 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 p r o p e r quenching and tempering; steels g.Whentheddlstringislaiddown,stored,ortransported, having strengths equivalent to hardnesses up to 26 HRC maxiwash 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 (as necessary). and coatall surfaces with a suitable corrosion pshowninalateasection)mustbeused;and,thehi~the ventive (seeAm Recommended Practice 5C1,Recovnmended stnmgth q u i r e d ,the greater the necessity for the corrective Pmctice for Care and Use of Casing and Tubing). measures. 10.1.6 DrillPipeCoatings
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RECOMMENDED PRACTICE FOR DRILL STEM DESIGN AND OPERATING LIMITS
10.2.2.2 Total Tensile Load (Stress)on the Steed The higher the total tensile load on the component, the greater is the possibility of failure by SSC. For each strength of steel used, thereappears to be a critical or threshold stress below which SSC will not ww, however, the higher the strength, the lower the thresholdstress.
65
b. Limit gascutting and formation fluid inflow by maintainp e r drilling fluid weight. ing p .. . c. Mlmmlze corrosion by the corrective measures shownin 10.1.7. Note: While use of plastic coated drill pipe can minimize colrosion, plastic coating does not protect susceptible d d l pipe from SSC.
d. Chemically treat for hydrogen sulfide inflows, preferably prior to encountering the sulfide. e. Use the lowest strength drill pipe capable of withstanding Thehighertheamountofatomichydrogenand H2S the required drilling conditions. At any strength level, prop 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 SSCare quite small, but corrective measuresto conf. Reduce unit stresses by using thicker walled components. w l i minimize theatomichydrogen troltheiramounts g.Reduce high stresses at connections bymaintaining absorbed by the steel. as possible. straight hole conditions, insofar h. Minimize stress concentrators such as slip marks, tong 10.2.2.4 Time marks,gouges, notches, scratches, etc. Time is required for atomic hydrogen tobe absorbed and i. After exposure to amur environment, usecare in tripping diffused in steel to the critical concentration required for out of the hole, avoiding sudden shocks and high loads. By controlling the crack initiation and propagation failure. to j. After exposure to a sour environment, remove absorbed factors referredto above, time-to-failure may be sufficiently hydrogen by aging in open air for several days to several lengthened to permit the use of marginally susceptible steels weeks (depending upon conditions of exposure) or bake at for shortduration drilling operations (see Figure 45). 400" to 600°F (204" to 316°C) for several hours. 10.2.2.3 Amount
of Atomic Hydrogen and H2S
10.2.2.5 Temperature The severityof SSC is greatest normal at atmospheric temincreases. At operating temperatma in excess of approximately 135°F (57"C), marginallysusceptiblematerials(thosehaving h&esses higher than 22 to 26 HRC) have been used successfully in potentially embrittling environments. (The higher the hardness of the matera i ,lthe higher the required safe operating tem-.) Caution must be exercised, however4SC failure may occur when the material returnsto normal temperature after it is removed h m the hole. peratures, and decreasesas tem-
Note: Plastic coated drill pipe should not be kated above 400°F (204°C)and should be checked subsequently for holidays and disbondhg.
The removal of hydrogen is hindered by the presence of corrosion products, scale, grease, oil, etc. Cracks that have formed (internallyor externally) prior to removing the hydrogen will not be repaired by the baking orstress relief operations. k Limit drill stem testingin sour environments toas brief a period as possible, using operating procedures that will minimize exposure to SSC conditions. 10.3 DRILLING FLUIDS CONTAINING OIL
10.2.3 Corrective Measures to Minimize SSCin Water-Base Drilling Fluids
10.3.1
Use of Oil Muds for Drill Stem Protection
Comsion and SSC can be minimizedby the use of drilling fluids having oilas the continuous phase. Corrosion does not occur if metal is completely enveloped and wet oil byenvian ronment that is electrically nonconductive. Oil systems used for drilling (oil-base or invert emulsion muds) contain surfactants that stabilize water as emulsitied dropletsand cause preferentialoil-wettingofthemetal. a Control the drilling fluid pH. When practicalto doso without upsetting other desired fluid properties, maintain a pH of Agents that cause corrosion in water (dissolved gases, dissolved salts, and acids) donotdamagetheoil-wetmetal. 10or higher. Therefore, under drilling conditionsthat cause serious probNote: In some drilling fluids, alnminum alloys show slowly i n d g corrolemsof corrosiondamageerosion-corrosion,orcorrosion sion rates at pH values higher than 8.5; and the rate may become excessive at fatigue, drill stem life can be greatly extended by using an oil pH valm higher than 10.5. Therefm,in dill strings containing aluminum mud. drin pipe, the pHshould not exceed 10.5.
The selection and control of appropriate corrective measures is usually performed by competent corrosiontechnologists and specialists.Generally, oneor more of the following measures is used, but certain conditions may require more specialized treatments:
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API REWENDED PRACTICE 7 6
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10.3.2
Monitoring Oil Muds for Drill Stem Protection
An oil mud must be properly prepared and maintainedto protect drill stem from corrosion and SSC. Water will always be present in an oil mud, whether added intentionally, incorporated as a contaminant in the surface system,orfrom exposed drilled formations. Corrosion andSSC may OCCUT if this water is allowed to become free and to wet the drill stem. Factors to be evaluated monitokg in an oil mud include: 10.3.2.1
ElectricalStability
This test measures the voltagerequired to cause current to flow between electrodes immersed in the oil mud (seeAPI RecommendedPractice 13B-2, Recommended Pmctice Standard Procedure for Field Testing Oil-Based Drilling Fluids, for details). The higher the voltage,greater the the stabilityof the emulsion, and the better the protection provided to the drill stem. 10.3.2.2 Alkalinity The acidic dissolved gases(carbon dioxide and hydrogen sulfide) are harmful contaminants for most oil muds. Monitoring the alkalinity of an oil mud can indicate when acidic gases are being encountered so that corrective treatment can beinstituted.
where 9, = critical sliding hole angle, f = coefficient offriction. 11.1.3 The critical sliding hole angle is theangleabove which drill string components mustbe pushed into the hole. Althoughmanyfactors a t € & thecoefficientof friction between the drill string components and the wall of the hole, the type of drilling fluid used has the greatest impact (see Table 19). Water-baseddrillingfluidsgeneratethehighest coefficient to friction andproducecriticalholeanglesof about 71 degrees. Synthetic-based drilling fluids provide the lowest coefficients offriction and produce critical hole angles of about80 degrees. 11.1.4 OperatingSignificantlengthsofthe drill stringin compression can causethepipetohelicallybuckleand induce pipe c u r v m s larger than the curvature of the hole and may cause unacceptable bending stresses. Rotating drill pipe in curvedportions of the hole generates cyclic bending stresses that can also cause fatigue failures. The most effective and efficient drill string design for extended leach and horizontal holes is the lightest weight drill string that can withstand the operating environment Using heavier components or thicker wall tubulm often increases the operating loads without reducing the bending stresses. Table 19-Effect of Drilling Fluid Type on Coefficient of Friction
10.3.23 Corrosion Test Rings Test rings placed in the drill stem bore are used to monitor the corrosionprotection aftorded by oil muds (see AH Recommended Practice 13B-2 for details). A properly functioningoilmudshouldshowlittle or no visualevidenceof corrosion on the test ring.
11 Compressive Service Limits for Drill Pipe (see also Appendices A.14 and A.15) 11.1COMPRESSIVESERVICEAPPLICATIONS 11.1.1 Wheneverdrillinghighangle,extendedreach, or horizontal well bores it is desirable to use compressively loaded portions of the drillstring. Drilling withdrill pipe in compression causes no more damage to the drill pipe than conventionaldrillingoperations as long as theoperating conditions do not exceed the compressive service limits for the pipe. 11.1.2 Drill strings are subject to compressive service conditions whenever significantportions of the borehole exceed the critical sliding hole angle as defined as follows:
e, = arc tan@,
Ddlling Fluid
W ~ - m bd ~ Oil-bas mud Synthetic-basemud
Q p i d Coefficient of fiction
Critical Hole Angle
0.35
71 76 80
&F=
0.25
O. 17
11.2 DRILL PIPE BUCKLING IN STRAIGHT, INCLINED WELL BORES 11.2.1
overview
11.2.1.1 The curves shown in Figures46 through 66 give the approximate axial compressive loads at which sinusoidal buckling is expectedto occur in drill pipe in straight, inclined wellbores.If the drill pipe is being rotatea limiting the drill pipe compressive load to below the estimated buckwill significantly reducethe ling load shown in these curves danger of fatigue damage to the pipe. Conversely, rotating drill pipe whileit is buckled can lead to rapid fatigue damage and failure. 11.2.1.2 These curvesare based on the equations of Dawson and They are reproduced here with permission from Standard DS-1, Drill Stem Design and Inspection.28The assumptions behind these curves include:
a, Pipe weightis newnominalwithX-gradetool joint dimensions (where applicable).If more than one tooljoint is (Text continued on page 78.)
COPYRIGHT American Petroleum Institute Licensed 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
API RECOMMENDEDP M C E 7 6
8
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 Hole size (inches)
16
20
Figure 47-Appmimate Axial Compressive Loads at which Sinusoidal Buckling isExpected to Occur
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
RECOMMENDEDPRACTICE FOR DRU STEM DESIGNAND OPERATING LIMITS
4
6
8
10
16 12
14
69
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
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
at which Sinusoidal Buckling is Expected to Occur
STD.API/PETRO RP 7G-ENGL
L998
m
0732290 O b 0 9 7 4 0 690
m
API RECOMMENDED PRACTICE 7 6
70
Figure !%-Approxm i ate
Axial Compressive Loads at which Sinusoidal Budding is Expected to Occur
Figure
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
RP 7G-ENGL
STD.API/PETRO
0732290 Ob09743 527
L998
RECOMMENDED PRACTICE FOR DRILLSTEM DESIGN OPERATING AND
71
LIMITS
I."
.... ...... ......1 ......I...... i......i-...... ....i...... 1 ..... .......L......I.......i ......+......!.......!....__i......[....... i...... ...... !....I ......i...... L ...... ..... ...... ....... ...... ...... .......i/......i.......c. ......i.......i...... .....l.,.." ....... .......i....... . . . . .... ........ ....... . ........ i....... ............... . i.......i.......1.............. . 4...............i . .......i... . 3V,-inch, 15.50 ppf 12 ppg mud
1:: i 4
I::+
...... ......i....... ....... . I l I ~
6
.
.
I
I
8
;
10
i
.
......_................................... . ............... . . i. ...... :............... . 1. .......................................... . i
i
1
1
1
i
1
;
1
;
;
i
i
1
l
12 18 14 Hole size (inches)
i
i
1
1
1
I
16
1
I
1
1
1
1
1
20
Figure 52-Approximate Axial Compressive Loads at which Sinusoidal Buckling is Expectedto Occur
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
I
STD.API/PETRO
RP 7G-ENGL
L998
m
0732290 Ob09742 4b3
m
API REC~MMENDED PRACTlCE 7 6
72
Figure 55"Appmimate Axial Compressive Loads atwhich Sinusoidal Budding isExpected to Occur
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
STD-APIIPETRO RP 7G-ENGL
L998
m
0 7 3 2 2 9 0 Ob09743 3 T T
RECOMMENDED PRACTICE FOR DRILL %EM DESIGN AND OPERATING LIMITS
Figure 56-Approximate Axial Compressive Loads at which Sinusoidal Budding isExpected to Occur
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
73
Ï'G-ENGL
S T D - A P I / P E T R OR P
L998
,
I
I
0732290 Ob09744 23b
m
API RECOMMENDED P M C E7 6
74
Figure 58-Approximate
A x i a l Compressive Loads at which Sinusoidal Budding is Expected to Occur
Figure 59-Appmimate Axial Compressive Loads at which Sinusoidal Budding isExpected to Occur
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
RECWMENDEDPRACTICE FOR DRU
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
STEM DESIGNAND OPERATING LIMITS
75
S T D = A P I / P E T R O R P 7G-ENGL 1998
I
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
m
0732290 b0974b
API REC~MMENDED PRACTICE 7 6
O09
STD.API/PETRO RP
7G-ENGL
m 0732290
L998
I
I
77 I
l ... ......................... ~ ' " ........ ...,-. ........... 1 1 ..... .....I...... ..... ...................................... ,.,,,: ..... ......I .....1.....i.....i.....i..... ............ 1i..... .....i............ I ...... L . .. .! .l . ....... . .!.................. .. .. 1-1 .....!I ___...... . . ; _.___i ...... r--..... .....i..... ......i.....i .....i.....j.....4.c .....i_.._.i .........i......;..-..i .....i.....i..... i.....i..... i......i.....i.....i.....i.....j..... ....5'/,inch, 24.70 ppf ..... i........i..... 1. ......i......I ......i......i.....i......i .....i..... f .....i..... i..... ..... L ..... ...... ..... ..... ...... ..... ..... .....j ......i.....i.....1.....i .....?)..... ppg 12 mud ...... ..... i..... ........... ..... ........... ..... .....i...... i..... i.....i.....i.....i..... ....i i..... i_.__.i .....i......i. . . . . . . . . .... ..... ..... ..... i ....i.....t .....i i..... ...i .......i i...... i i.....i..... i ............ i.__.__i ......i.....i..... .... ..... ..... ................. ......i....... i......i......i......i......1._..__i i.....i.....i ...... i........i...... ......L......i...... . .iI...... . .i._____i . ..... .......... E . ............................. i......j...........i......i..... ...... ......i......i.....i......+.....i .....4......i ...... i ...... ..___G.....i ............ +.....i ...... .... i.....i......i.._..i .....i.....i...... i ....._..... :._..:..... _._._i .....i.....i .....i_____: ............i .....i........... j.....1_____i ......i......i.....i ..... .... c .... .i. L .....i...... i......i...... i......i......: ...... 4.._....: . ..... .... .......i......i ..-"..:.(. i......i....... .i....."i__._i ......i I-.............i'.. . ....1..-..I......L. ....i......:.....J ......i......i ..... ..... i .. C." .i .i"... J..".*..... .....c....4..... i.....i ...... i.....i.....i .....j ..... i..... .....j ......i .....L .....:...... .... ' .....:.....L ..____: ...... :...... * ..... * .....:.......:..... i _._._i .....1_____i ......i..... 1____.i ...... i .....2 ...._i..... 1......i .....4 .....i..... ............ I .....I ....2:::::: ......i..... ..... i...... ..... :>.....i ...... ...... i.....j.....i..... i............i..... 1......i ......i...... i.......I...... i ......j......i......j......i . .....i........i.....1 . ...-i
i
"_
I
1
m
DESIGN AND OPERATlNG LIMITS
RECOMMENDED PRACTICE FOR DRILL*M
I
Ob09747 T 4 5
f
J
A
7oooo
.
?
L
-
".
14
12 8
!
?
I
10
Figure 64-Approximate Axial Compressive
.
.
.
.
16 Hole size (inches)
18
20
22
24
Loads at which Sinusoidal Buckling is Expected to Occur
Figure 65-Approximate Axial Compressive Loads at which Sinusoidal Bucklingis Expected to Occur
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
04 03 02 01
~~~
~~
~~
STD.API/PETRO RP 7G-ENGL
II998
m
~~
0732290Ob09748
981
m
API REC~MMENDED PRACTICE 76
78
10
14
12
16
20
18
22
24
Hde size (inches)
Figure 66-Approximate Axial Compressive Loads at whc i h Sinusoidal Budding is Expected to Occur
the Drill Pipe Buckling Curves
used on a particular pipe,the mostcommon one wasselected.
11.2.3 Using
Tool joint diameter is the minimum for Premium Class. Radial clearance is the distance between the tool joint OD and the hole. b. Pipe wall thickness is new nominal. c. The well bore is straight. d The effects of torqueare neglected. e. Mud weight is 12.0 1Wgal.
Enter the curvefor the correct pipe size and weight at the hole diameter. Read verticallyto intersect the hole angle, then horizontally to read critical buckling load. Compensate the value obtained for mud weight being used.
11.2.2 Compensating for Different Mud Weight If the actual mud weightis not 12.0 lWgal,criticalbuckling load maybe adjustedby the following formukx
(Fd-œ#) = (FA(f,) W
= adjusted criticalbuckling load(lbs), F& = criticalbuckling loadfrom curve (lbs), f, = (buoyan~yfactor/o.817)05 (~ee below), Mud Weight
W@) 8.0 9.0 10.0 11.0 12.0 13.0
1.00
0.99
11.2.3.2 Solution: Reading from the figure for the drill pipe in question (Figm), the critical buckling load is about 28,200 pounds. Adjusting to 9.0 Wgal mud:
W@)
f-
14.0 15.0 16.0 17.0 18.0 19.0
0.98
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
F-
= 28,200 lbs (1.03) = 29,000 lbs
11.3 CRITICAL BUCKLING FORCE BOREHOLESnSSflS
Mudweight
,f
How much compressive load may be applied to 5-inch, the 19.50 Wft drill pipe in a 12'/,-inch horizontal hole before drill pipe buckles? Mud weight is 9.0 lb/gal.
ure
h
F-
11.2.3.1 Example
0.97 O.% 0.95
0.94 0.93
FOR CURVED
The critical buckling force of compressively loaded drill pipe is also signifìcautly i n f l u e n d by the c m of the borehole. In angle building intervals the upwardcurvature of the borehole inthe critical buckling force. In turning iutervals the hole curvature also increases the buckling force of the drill pipe. Table 20 showsthe hole curvature rates that p e n t buckling fora range ofpipe and holesizes.
RP 7G-ENGL
STD.API/PETRO
L998
m
0732290Ob09749
818
m
RECOMMENDEDPRACTICE FOR DRILL STEM DESIGNAND OPERATING LIMITS
79
Table 2 W o l e Curvatures that Prevent Buckling Hole Size
in. 2.375
DrillPipe Drill pipe Nominal Tool Joint OD ID Weight OD
ia
4.000
in
lWft
1.815
6.7
AxialLoad UlMlbS 25Mlbs 40Mlbs 30Mlbs
5Mlbs
1OMlbs
lsMlbs
in.
allm
"/looft
" / l mO/lOoEt "/looft.
50Mlh
""/ /l lmm
"/looft
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 6.000
2.875 3.500
2.151 2.764
10.4 13.3
4.125 2.4 5.000 0.6
1.2 0.3
4.7 1.3
3.5 1.0
5.9 1.6
7.1 1.9
9.5 2.6
11.8 3.2
6.750 6.750
3.500 4.000
2.764 3.340
13.3 14.0
5.000 1.1 0.7 5.250
0.6 0.3
2.3
1.7 1.o
1.3
2.8 1.7
3.4 2.0
4.5 2.7
5.6 3.4
7.875 7.875
4.000 4.500
3.340 3.826
14.0 16.6
5.250 1.2 6.250
0.6 0.2
2.4 0.5
1.8 0.7
.o
3.0 1.2
3.5 1.5
4.7 2.0
5.9 2.5
8.750 8.750 8.750 8.750
4.500 5.000 5.500 5.500
3.826 4.276 4.778 4.670
16.6 19.5 21.9 24.7
6.250 0.8 6.375 7.500 7.250
0.4 O2 o.1 0.2 o.1
1.5
1.1 1 0.7 0.3 0.3
2.3 1.4.o
1.9 1.2 0.5 0.5
3.O 1.9 0.8 0.8
3.8
2.4 0.6 0.9 0.6
9.875 9.875 9.875 9.875
5.000 5.500 5.500
19.5 21.9 24.7 25.2
6.375 7.500 0.4 7.250 8.000
0.4 0.2 0.2 0.2 o.1
1.4 0.7 0.7 0.3
1.1 0.5 0.5 0.3
3.6 1.8 1.80.7
6.625
4.276 4.778 4.670 5.%5
1.8 2.8 0.9 1.4 0.9 1.4 0.4
2.1 1.1 1.1 0.8 0.5
0.7
12.250 12.250 12.250 12.250
5.000 5.500 5.500 6.625
4276 4.778 4.670 5.%5
19.5 21.9 24.7 25.2
6.375 1.2 7.500 7.250 8.ax
0.6 0.4 0.3 0.2
2.4 1.4 0.7 0.7 0.8 0.4
1.8 1.1 1.o 0.6
3.6 2.1 2.0 1.3
3.0 1.8 1.7 1.o
6.0 3.6 3.4 1.1 1.9
4.8 2.9 2.7 1.5
11.3.1
0.5
0.4 O2 0.4
0.4
1
1
.o
Example
ing of the tool joints, as well as the axial compressive loadon 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 size is 8.75 inches build curve of a horizontal well? The hole pipe in curved boreholes progresses through three stages. and the maximum required bit loadis 30,000 pounds. Under light loads, the maximum bending stress occurs in the center of the pipe span but only the tool joints are in contact 11.3.2 Solution with the wall of the borehole. As loading is inmased, the center of the pipe comes into contact with the wall of the Table 20 shows that 5-inch, 19.5 lb/ftdrill pipe in an 8.75inch hole will not buckle in hole curvatures greater than 1.4 hole.Under this loadingconditionthemaximumbending stress occurs at two positions thatare located on either side of degrees per 100 feet with a30,000 pound load. thepointofpipe body contact. As theload is further increased, the length of pipe body contact increases from 11.4 BENDING STRESSES ON COMPRESSIVELY of pipe locatedin point contactto wrap contact along a length LOADED DRILL PIPEIN CURVED the center of the joint. BOREHOLES33p34 Figures 67 through 74 p v i d e solutions to the bending stress, pipe body contact, and lateral contact loads for the Rotating compressively loaded drill pipe in curved portions most common sizes of 6V8-inch to 23/,-inch drill pipe. There of the borehole generates cyclic bending stresses that, if large are four plots for each size of drill pipe. The plot in figures enough,maycausefatiguedamage.Compressive'loading 67-74 (figures a) show the maximum bending stress as a may also cause aportion of the pipe bodyto contact the wall function of axial compressive load for a range of hole curvaof the hole. In abrasive formations, pipe body contact can tures. The type of loadingis shown by the style of the plotted erode the body of the pipe and furthermagnify the bending lines. For no pipe body contact, the bending stress curve is stresses. The maximum bending stress caused by compresshown as a solid line. For point contact the bending stress sively loadingdrill pipe in curved boreholes is affected by the relation is shown as a dashed line and forwrap contact the size of the pipebody, and thespacsize of the tool joints, the (Text continued onpage 96.) COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
~
STD-API/PETRO RP
7G-ENGL 1998
m
0732290Ob09750
53T
API RECOMMENDED PRACTICE 7 6
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
Axial compressive load-lo00 lb.
Figure 67a-Eending Stress and Fatigue Limits
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
60
70
S T D m A P I I P E T R O R P 7G-ENGL L998
REC~MMENDED PRACTICE FOR DRU -M
m 0732290 0609751 476 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
Axial compressive load-1 o00 lb.
Figure 6 7 H a t e r a l Contact Forces and Length
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
60
70
API RECOMMENDED P ~ C7 6E
82
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 Axial compressive Ioad-lOOO lb.
50
Figure 68a-Bending Stress and Fatigue Limits
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
60
70
~
STD-APIIPETRO RP 7G-ENGL
L998
m
0732290Ob09753
249
m
RECOMMENDED PRACTICE FOR DRU STEM DESIGNAND OPERATING LIMITS
83
5.5-in. 21.9IbRt Drill Pipe, 7.5-in.Tool Joint 10 ppg mud, 90-degree 9.875-in. hole
10
5
20 d/h
O
Figure 68b”ateral Contact Forces and Length
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
API REC~MMENDED pRAcTlc~7 6
a4
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 d ü C
15
10
5
O O
20
10
30
40
Axial compressive o la d O lO Olb.
Figure 69a"Bending Stress and Fatigue Limits
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
60
STD.API/PETRO
RP 7G-ENGL
L998
m 0732290 0609755 O L L m
RECOMMENDEDPRACTICE FOR DRU STEM DESIGN AND OPERATING LIMITS
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
1
30 40 Axial compressive load-1 O00 lb.
Figure 69b"Lateral Contact Forces and Length
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
50
60
API REW"ENDED
86
PRACTICE 76
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 Limits
COPYRIGHT American Petroleum Institute Licensed 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
DRIU STEM DESIGNAND OPERATING LIMITS
RECOMMENDEDPRACTICE FOR
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
20 d/h
O
O
10
20
30 Axial compressive load-1 O00 lb.
Figure 7Ob"Lateral Contact Forces and Length
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
~~
STD-API/PETRO RP 7G-ENGL L998
80
~
m 0732290 Ob09758 820 m
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 Limits
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
STD.API/PETRO RP
7G-ENGL L998
m
0732290Ob09759767
m
RECOMMENDED PRACTICE FOR DRU %EM DESIGNAND OPERATING LIMITS
89
4.0-in. 14.0Ib/ft Drill Pipe, 5.25-in.Tool Joint with 10 IWgal mud in a 6.75-in. hole
15
10
30dnl 2odnl
5
10 dnl O O
10
20
Axial compressive load-1
30
40
O00 lb.
Figure 71 M a t e r a l Contact Forces and Length
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
50
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 Axial compmsive load-loo0 lb.
30
Figure 72a"Bending Stress and Fatigue Limits
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
40
m
S T D a A P I / P E T R O RP 7G-ENGL 1 9 9 8
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
2
30dh
I I3
a c C
20 dh
O
SI10 dh
15
I
1
I
I
I
I
10
I
4odh
30dh
2om 5 10 dh
O
Figure 72b-Lateral Contact Forces and Length
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
~~
S T D = A P I / P E T R O RP 7G-ENGL L998
m
0732290Ob097b2
API RECOMMENDED PRAC~CE 76
92
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 Limits
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
251 W
S T D = A P I / P E T R O R P 7G-ENGL 1998
W 0732290 0609763 198 W
RECOMMENDEDPRACTICE FOR DRILLSTEM DESIGNAND 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
O O
10
20
30
40
50
Axial compressive load-i O00 lb.
Figure 73b-Lateral Contact Forces and Length
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
70
1om
94
PRACTICE API RECOMMENDED
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 Axial mpressive load-lo00 lb.
Figure 74a43ending Stress and Fatigue Limits
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
20
25
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
3om 20 dh 10 d/h
2odh 10 dh
O
5
10 Axial compressive load-1
15
20
O00 lb.
Figure 74Materal Contact Forces and Length
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
25
API RECOMMENDED PRACTICE 7 6
96
plotted stress is shown as a dotted line. The plotsalso include the fatigueendurance bending stress limits h m Section 11.5. The plots assumea 10 %/gal mud, 9Odegree hole angle, and The mud density, hole angle, and hole a deíìned hole size do notaffect the bendingstresses unless the pipe buckles. On most of theplotsthe critical bucklingforce is only e x &for cases withzero or negative buildrate. The bending stresses for buckled pipeare independent ofthe hole curvatureandgenerallyfollowcurves in whichthebending stress inarmes more rapidly with increased axial load than for the constant hole curvature cases.
szi e.
11.4.3 Example Determine the maximum bending stresses for d i c h , 14 %/ft drill pipe with 5V8-inch tool joints in 24Megrees-per100-foot holecurvature, and a 20,000 poundaxial compressive load. 11A.4Solution
Figure 71a shows the bendingstresses for 4-inch, 14 lb/ft drill pipe, with W4-inch tool joints. The actual tool joint outside diameter is 53/8-inchor ‘/,-inch larger. Figure 75 shows factorsfor varioussizes of drill The plotsin Figures 67-74 (figuresb) show the pipe body the hole curvatwe adjustment pipe as a function of the difference in the tool joint outside contact length and the lateral contact forces between the pipe diameters. Foran actual tool joint, ’/,-inch larger thannomibody and the tool joints with the wall of the hole. nal, Figure 75 showsthat with 4inch d d I pipe the curvature adjustment factoris l.l. To determine themaximumbending 11A.1 Example stress for the inch larger tool jointa 2Odegrees-per-100in foot holeamature at 20,000 pound load, multiply theactual An 8V2-inch horizontal well will be drilled with 5-inch hole curvature by the adjustment factor, 2Odegrees-per-10019.50 lb/ft drill pipe with 6V,-inch tool joints in an W2-inch feet times 1.1 = 22-degrees-per-lOO-feet Using 22degreeshole with 10 lb/gal mud The maximum hole curvatm will per-100-feet at 20,000 pounds on Figure 71% the bending be 16 degrees per 100 feet. The horizontal interval will be stress for 53/,-inch tool joints is 24,500 psi. drilled with surface rotation with loads upto 35,000 pounds. What grade of drill pipe is requiredfor this example? 11.5 FATIGUE LIMITS FOR API DRILL PIPE
V,
11.A2 solutlon 11.4.2.1
Figure 69a shows the bending stresses and fatigue
limits for 5-inch, 19.5 1b/ft drill pipe, with @/,-inch tool joints in a 9 o d .e g r e e ,8V2-inch hole with10 lWgal mud For a hole cumahre of 16deps-per-100-feet and an axial compressive load of 35,000 pounds, the maximum bending stress is %,O00 psi. A slightly bending stress of 25,OOO psi is
high=
p o rd u dby a 24,000 pound axial load. Themaximumbending stresses exceeds the fatigue endurance limits for Am Grade. E75, X95, and D55 pipe, but is less than the fatigue endurance limitsfor grades G105 and S135 pipe.Figure 69b shows that at 35,000 pound axial load, the tooljoint contact forces would be about 2,600 pounds with a 16 degrees per
1OOfootcurvaauerate.Thepipebodycontactforcewillbe about 600 pounds under a 35,000 pound axial load For this curvatureratethecontactwillbeatthecenterofthespan. 123
100
11.4.22 The maximum bending stresses for pointand wrap contact are directly proportional to the holecurvatures andradialclearancesbetweenthepipebodyandthetool 167 bending 145 stress 165 plots135 joints. This allows us to use the existing to estimate the bending stresses for tool joint dimensions other than used in preparing the plots.No adjustment is necessary unless the loading condition produces point or wrap contact- If this is the case, we can compute an adjustment factafromtheactualsizeofthetooljointandusethattocompute an equivalent hole curvature to determine the coT28cf bendingstress.
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
R P. Morgan and M. J. R ~ b l i ndeveloped ~~ a method of measuring fatiguelimits from smaU drill pipe samples. Their technique preserves the effect of the“as produced” drill pipe hotfinish They reported on thetestingof API Grades E75, X95, G105, and S135 as well as an experimental high strength tubular identified as V180. Their test program showed that the fatigue endurancelimits for drillpipe correlate well with the tensile strength of the pipe. Table 21 shows some of the results of their test program.
surfaces.
Table 21-Youngstown Steel Test Resutts* Avenge
.m . Idnumum
API Yild
API Tensile
Ya
strength
strength
Strength
Ofm
clrade strength Maximum Minimum samples ksi E75 105
75
x95
95
G105144 S135
*Yo-
105 115
ksi
ksi
ksi
125 132
105
35
135
EndunmceIimit
Tensile
M’
Median
mt
Test
val=
value
ksi
ksi
30
32
32 34
38
36
40
Sheet and lbbe Compauy, 1969MME conference,Tulsa,
Oklahoma
Casne+hasutilizedtheirtestresultstodetenninetheminb u mfatigue endurauce limits for API drillpipe that meets
the API minimum strength requirements, See “%le
22.
L778
S T D O A P I I P E T R O RP 7G-ENGL
m
0732290 0607767 8 3 3
m
RECOMMENDEDPRACTICE FOR DRU STEM DESIGN 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 nominalT M n .
Figure 75"iole Curvature Adjustment FactorTo Allow for Differences in Tooljoint ODs
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
5
Table 23-Values
Table 22-lätigue Endurance Limits Compressively Loaded Drill Pipe
m Grade
Minimum Yield Strength ksi
API .. IvhmumTensile
Grade
ksi
MinimumFatigue EhdmœLimit ksi 22.0
E75
strength
'Islpical YieldStzmgth
Used in Preparing Figure77 Expactedultimate MinimumFatigue Strength and Fatigue Stress Limit far stress Limit forme l,ooO,ooO Revdutions Revolutim
ksi
ksi
87.5
121.5
26.7
ksi
E75
75
100
x95
23.1 95
105
x95
281.093.0
131.5
G105
25.3
115
G105
321.294.0
149.5
S135
31.9
145
S135
35.0
159.0
150.0
11.6 ESTIMATINGCUMULATIVEFATIGUE DAMAGE
fatigued endurance limits for these tensilestrengths. The SN curve was computed by using the exponential relationship described above with the tensilestrength equal to the fatigue endurance limit for one revolution and the fatigue endurance limit values to represent thestress limit for onemillion revo&il lutions.Thevaluesused to prepare Figure 77 are S in Table 23.
An interesting altemative to operating below the fatigue endurance limits for drill pipe is to monitor the cumulative fatigue damagecaused by rotating in highcurvature intervals of the borehole and retire the pipe before failures occur. The concepts for tracking the cumulative fatigue damage have The cumulative fatigue damage is determined by counting been well developed by Hansford andLubir~slci.~~J~ The key the revolutions of pipe in highly curved portions of the boretowards successful use of this technique is establishing the stresses exceed the fatigue endurancelimits. hole where the appropriate stress versus revolutionsto failure curves for the If, for example, the revolutions in a particular section of hole various grades of A P I drill pipe. Figures 76 and 77 provide represent 20 percent of the predicted revolutions to failure for estimates of the median expectedfailm limits found by Mort h a t dogleg severity it is judged that 20 percent of the fatigue gan and Roblin and an estimate of the minimum failwe limits been consumed. Figures 76 and 77 can be used to life has of API drill pipe that has been manufactured to average A P I judge inspection levels and ultimate retirement levels. The properties. We would expect that half of the drill pipe exposed ultimate life can be judged from the plot of the median to the limits shown in Figure 76 would fail. The minimum fatigue limits of Figure76. The appropriate minimuminspecfailure limits in Figure 77 should avoid fatigue failures on tion levels canbe judged from the minimum fatigue limitsof typical API drill pipe. The mediaa failure limits are based on Figure 77. After exposure to this level of fatigue, inspection an exponential relationshipthat connects the average tensile 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 lifeto or beyond the expected median life levels. ing onemillion cycles to failm. The average tensilestrength Figures 78 through 80 are plots of the bendingstresses for values and the median fatigues endurance limits h m Table 3vZ-inch, 27l8-inch,and 23i8-inch drill pipe in highly curved 21 were used to develop thestress versus revolutionsto failboreholes. The bending stresses determined h m these plots we curves shown in Figure76. are used to determine thetotal number of revolutionsthat the pipe can withstand from Figures 76 and 77. These are then TS comparedto the observed number of revolutionsto determine Theequationisoftheform: S = N" the level of fatigue damage. The ratio of the revolutionsto the predictedmedian revolutionsto failure defìnes the fraction of where the drillpipefatigue life consumed drilling in through the high S = bending stress limit,psi, curvature hole. Ts = tensile stmgtb of pipe, psi, N = molutionst~failm, x = a frzlctionalexponent of aboutD. l. Thecurvesofminimumfailmljmitsarealsobasedonthe Morgan and R o b b data Their report includes a table that de6nes the typical yield and ultimate tensile strengths for normalized Grade E75, normalized and t e orades X95 and G105, and quenched tempered Grade S135 API drill pipe. Using Casnefs d e h e d 0.22 ratio we computed the
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
11.6.1
Example
An example ofthe cumulative fatigue damage calculations is given by the following. Consider drilling a 5OO-foot horizontal hole below a 1OO-fod radius build curve with 3VZ-inch S135 chill pipe. Drill pipe will be rotated at 30 RPM with l0,OOO WOB, andis expected to drill at 15 feet per hour. The equivalent buildrate is given by:
STD-API/PETRO
RP 7G-ENGL 1998
D 073227006077b9bob
RECOMMENDEDPRACTICE FOR DRU STEM DESIGN OPERATING AND
LIMITS
85
80
75
70
65
W
55
50
45
40
30 10,Ooo
lo00
Revolutionsto failure
Figure 76"edian
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
Failure Limits for API Drillpipe Noncorrosive Service
D
99
~
STD.API/PETRO
RP 7G-ENGL
L99B
~~~~~
D 0732290Ob09770
328 D
API RECOMMENDEDP W C E 7 6
100
5
lo00
Figure 774inimum Failure Limitsfor API Drillpipe Noncorrosive Service
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
STD.API/PETRO RP 7G-ENGL
1,998
m
073229.0 0609771, 264
m
REC~MMENDED PRACTICE FOR DRU &EM DESIGN AND OPERATING L I M ~
B = -5730
R
where B = build rate,d e ~ 1 0 R, 0 R = build radius,R For this case: B =
11.7 BENDING STRESSES ON BUCKLED DRILL PIPE
The bending stresses on buckled drill pipe must account for both the mechanicsof buckling and the additional bending caused by the axial load and the tool joints. The curvature producedby bucklingis given by:
5730 = 57.3 degreedlooft. 100
-
Bbuc
=
Fxh,x57.3x12x100 2xExZ
11.6.2 Solution
Figure 78a shows that at 10,000 pound axial compressive load and a 57-degrees-per-100-footbuild rate the maximum bending stress is 50,000 psi. Figure76 predicts that half of the S135 pipe will fail under a 50,000 psi bending stress after 110,000revolutions. Theminimumfailure limitsof Figure 77 predict that S135 pipe canbe rotated 39,000 re~olution~ without failure. The number of revolutions of exposure is givenby: N =
60xLxRPM ROP
where N = revolutions of exposure, L = length of high curvature hole,R, RPM = romy speed rev/min, ROP = penetration rate,ft/hr. The length ofL of our 90 degree build curveis equal to: R
IC
L = - X R = - X 1 0 0 = 157ft. 2 2 Therefore, the number of revolutions of exposure for the pipe that is rotated through the build iscurve equal to: N = 6o x 157 x 30 = 18,850 revolutions 15
The cumulative damage can be computed by comparing to the ll0,OOO revolutions therevolutionsofexposure required to cause half of the pipe to fail. This suggeststhat 17 percent of the fatigue life of the affected pipe has been consumedindrillingonewell.Comparingtherevolutionsof exposure to theminimum fatigue limitof 39,000 revolutions a failure. For this case, the18,850revoluevaluates the risk of tions ofexposurerepresents 48 percentofthe minimum fatigue life expected for Sthe 135 pipe. This suggests that two wells could be drilled withthis string before inspecting and downgrading or removing fatigue damaged joints from service. Continued use of the string will requireremoving significant portions of the affected pipe in order to prevent failures.
1o1
Bbvc
=
17190 X F(Dh - Dtj) ExZ
where Bk = curvatme of buckled pipe, "/lo0 ft., F = axial load, lb., Dh = hole diameter, in., Dti = tooljoint OD,in., h, = radial clearance
-
h., 2 Z = acea moment of inertial of pipe, in?, B = Young's modulus, psi = 30 x 106 psi for steel. "
This curvature can be used in place ofthe hole curvature in the equations covered inSection 1 1.4.
12 Special Service Problems 12.1 SEVEREDOWNHOLEVIBRATION
Downhole vibrationis inevitable.In many cases, low levels of vibration go undetected and are harmless. However, severe downholevibralioncancausedrillstringfatiguefailure m k e d drillstrings, premature bit fail(washou~twist~ff), ure, and r e d u d penetration rates. The mainsources of excitation are providedbythe interaction of the bit with the formation and the drillstring with the wellbore. The drillstring response to these excitationsources is very complex. Vibration can induce three components of motion in the drillstring and thebit, namely: axial (motion along drillstring axis), torsional (motion causing twistftorque) and lateral (side to side motion).All three dynamic motions may coexist and one motion may cause another. While theories exist, therenoisgeneral agreementon how to predict (calculate) when damaging vibrations will occur. However, by observing the symptoms of severe downhole vibrations,probablemechanismsmay bedeterminedand appropriate corrediveactions taken. Severe downhole vibration is often accompanied bysymp toms belonging to more than one mechanism. This fact makes the detection of the primary mechanism more dZEcult For (Text continuedc m page 108.)
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
API
102
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
ïo
ö
30 b a lcompressive load-1 O00 lb.
Figure 78a-Bending Stress for High Cuwatures
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
STD.API/PETRO RP 76-ENGL
L998
m 0732290 0609773 037 m
RECOMMENDED PRACTICE FOR DRU STEM DESIGN AND OPERATING LIMITS
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 Length
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
103
~
STD.API/PETRO
RP 7G-ENGL
~~~~~
L998
~~
m
0732290Ob09774T73
API REC~MMENDED PFtt~mcE76
104
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 Stress for High Curvatures
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
m
m
S T D = A P I / P E T R O R P 7G-ENGL L998
0 7 3 2 2 9 0 Ob09775 90T
m
RECOMMENDEDPRACTlCE FOR DRU STEM DESIGN AND OPERATING L"
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 Axial compressive load-1 O00 lb.
Figure 79b"Lateral Contact Forces and Length
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
20
25
API REW"ENDED
106
PMCE
76
2.375 in. 6.65 IbAt Drill Pipe, 3.250 in. Tool Joint with 10 Wgal mud in a 4.00 in. hole
O
5
10 Aial compressive load-loo0 lb.
15
Figure 80a-Bending Stress for High Curvatures
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
RECOMMENDEDPRACTICE FOR DRU STEM DESIGNAND 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
5
O
10
15
Axial compressive load-lo00 lb.
Figure 8Ob”ateral Contact Forces and Length
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
20
example, an increase " inDshock counts, which is indicative of BHA lateral vibration, can be caused by BHA Whirl, Bit Bounce, or other mechanism. Additional clues, suchas bit toothbreakage, forthis example, are required for the identifìcation of theprimary vibration mechanism. There are a number of mechanisms which can cause severe downhole vibration. For mechanisms, their symptoms, and methods of control are described below:
a. Slapstick l. Mechanism-Non-uniform bit rotation in which the bit slows or even stops rotatingmomentarily, causing the drillstring to periodically torque up and then spin free. This mechanism sets up the primary torsional vibrations in the string. 2. Sympto=surface torque fluctuations>15 percent of average (below 1 Hz or stalling), increased MWD shock counts, cutter impact damage, drillstring washouts/twistoffs, comedion over-torque or back-off. Note: 1 Hzisonecyclepersecond.
3. A c t i o d u c e WOB and increase RF", m i d e r a less aggressive bit, modify mud lubricity, reduce stabilizer rotational drag (change blade design number or of blades, use non-rotating stabilizer or roller reamer), adjust stabilizer placement, smooth well profile, add rotary feedback
ping rotation,use stabilizedBHA withfull gauge near-bit stabikmmreamer.
d Bit bounce: 1. Mechanism--large weight-on-bit fluctuaiions causing the bitto repeatedly lift off andimpact the formation.This mechanism often occurs when drilling with roller cone bits inhard formations. 2. Symptoms-large axial 1 to 10 Hz vibrations (shaking and/ of hoisting equipment), large WOB fluctuations, cutter or bearing impact damage, fatigue cracks, reduced ROP. 3. Actions-run shock sub or hydraulic thruster, adjust WOB/RPM, consider changing bit style, change length of BHA. e. Other mechanis-some field data and theoreticalstudies indicate that certain "critical speeds" exist which excite Pracresonant vibrations.previous editions of Recommended tice 7G gave formulas and graphs for predicting these critical speeds. However, severe vibrations havebeen routinely measured at RPM other than thosegivebythesesimple calCUlElti0~. 12.2 TRANSITION FROM DRILL PIPE TO DRILL
COLLARS
Frequent failure in the joints of drill pipe just above the drill collars suggestsabnormallyhighbending stresses in This condition is particularly evident when the these joints. s y hole angle is increasing with depth and the bit is rotated off b. Drillstringwhirk 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 firstjoint of borehole. The violent whirling motion slams the drilldrill pipe above thecollars.When joints are moved h m this string against the borehole. The mechanism can cause location and rotated to other sections, the effect is to lose ~odandlateralvibmtim. identity of these damaged joints. When these joints laterfail . . washouts/twist-offs,localized 2" S through accumulaton of additional fatigue d a m a g e , every 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. to improve control over the f a i l m at the transition zone and 3. Actions-Ht bitoff bottom and stop rotation, then damag~jointsistousenineortenjoin~ofheavywallpipe, reduce RPM, avoid drill collar weight in excess of 1.15 to or smaller chill c o b , just above thecollars.Thesejoints are 1.25 timesWOB, use packed hole assembly,reduce stabimarked for identiíìcation, and used in the transition zone. lizer rotational drag, adjust stabilizer placement, modify TheyareinspectedmmGrequentlythanregulardrillpipeto mud properties,consider drilling with a downhole 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 caused by b i t h e m gearing (analogous to a planetary gear). This mechauism 12.3 PULLING ON STUCK PIPE induces high frequency lateral and t o r s d i vibmtion of It is normally notconsidered good practice to pull on stuck the bit and drihhiug. drill pipe beyond the minimum tensile yield strength for the 2 Symptoms-atter impact damage, uneven bit gauge size,grade, weight, and classif~cationof the pipe in use (see W=, 0 v e r - p hole, ~ reduce ROP, 10 to 50 Hz lateraV mies 4,6, and 21). For example, assuming a stringof 5-in., torsional vibrations. 19.5 lb/ft Grade E drill pipe is stuck, the following approxi3. Actions-lift bit off bottomand stop rotation, then mate values formaximum hook load would apply: Feduce RF" and increase WOB, comider changing bit PremiumClass: 3 1 1,535 lbs (flattex profile, anti-whirl), use slow RF" when tagging Class 2: 270,432lbs bottom and when reaming, pickoff bottom before s t o p
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
~
STD.API/PETRO RP
7G-ENGL
L998
m 0732290
Ob09777 555
m
REC~MMENDED PRACTICE FOR DRILLSTEM DESIGNAND OPERATING LIMITS
The stretch in the drill pipe due to its own weight suspended in a fluid should be considered when working with drill pipe andthe propex formulas to use for stretch when free or stuck should be used. 12.3.1 Example I (see A.6 for derivation): Determine the stretchin a 10,OOO foot string of drill pipe freely suspendedin 10 lWgal drilling fluid. e =
-
L’
[65.44 - 1.44 W B ]
10’W2
[65.44- 1.44 X 101
9.625 x lo7
(22)
109
12.5 TORQUE IN WASHOVER OPERATIONS Although little data are available on torque loads during washover operations, they are significant. Friction and drag on the wash pipe cause considerable increases in torque on the tooljoints and drill pipe, and should be considered when pipe is to be usedin this type service. This is particularly true in directionally drilled wells and deep straight holes with small tolerances.(See 12.6.) 12.6 ALLOWABLE HOOKLOAD AND TORQUE COMBINATIONS Allowable hookloadsand torque combinationsfor stuck drill strings maybe determined by use of the followingformulx
9.62s X lo7
= 53.03 in.,
where
I
= length offree drill pipe, feet, W, = weight of drilling fluid, lb/gal, e = stretch, inches.
where QT = minimum torsional yieldstrength under tension, lb-ft., J = polar moment of inertia:
12.3.2 Example II (see A.4 for derivation): Determine thefree length in a 10,OOO foot stringof 4V2-in. OD 16.60 1Wft drill pipe which is stuck, and which stretches 49 in.due toa differential pull of80,OOO lbs.
L, =
735,294 X e X W,, P
(23)
735.294 x 49 x 16.60 80,OOO = 7476 ft.,
where
4
= length of free drill pipe, feet, e = differential stretch, inches, Wb,= weight of drill pipe, pounds per foot, P = differential pull, pounds.
12.4 JARRING It is common practice during fishing, testing, coring and other operations to run rotary jars to aid in k i n g stuck assemblies. Normally, thejars are run below severaldrill collars which actto concentrate the blowat the fish. It is necessary to take the proper stretch to produce the r e q u i d blow. mass of drill collars and Themomentumofthemoving stretched drill pipe returning tonormal causes theblow after the jar hammer is tripped.A hammer force of three to four times the excess of pull over pipe weight is possible depending on type and size of pipe, number (weight) of drill collars, drag, jar travel, etc.This force may be large enough todamage the stuck drill pipe and should be considered whenjarring operations are planned.
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
=
IC (D4-d4) fortubes, 32
D = outside diameter, inches, d = inside diameter, inches, Y, = minimum unit yield strength, psi, S, = minimumunit sh=strength,psi: (S, = 0.577 Y,,,), P = total loadin tension, pounds, A = cross section area
An example ofthe torque which may be appliedto the pipe as follows: which is stuck while imposing a tensile load is Assume: a. 3V2-in.OD 13.30lb Grade E drill pipe. b. 3V2-in,IF tool joints. c. Stuck point: 4OOO feet. d Tensile pull: 100,OOOpounds. e. New drill pipe.
Lkn:
QT
=
0.096167 x 9.00 3.5
C&= 17,216 lb-ft.
For further information on allowablehookloads,torque application, and pump pressure use, see Stall and Blenkam: Allowable Hook Load and Toque Combinations For Stuck Drill Sm*ngs.12
m 0732290 Ob09760
STD.API/PETRO RP 7G-ENGL L998
277 H
API RECOMMENDEDPRACTICE 7 6
110
12.7 BIAXIAL LOADING OF DRILL PIPE The collapseresistance of drill pipe corrected for the effect of tension loading maybe calculated by reference to Figure 81 and the use of formulas and physical constants contained in 12.8, 12.9,12.10,and 12.11. 12.8 FORMULAS AND PHYSICAL CONSTANTS
The ellipse ofbiaxial yield stress shown in Figure46 is for use in the rauge of plastic collapse only, andthegives relation between axial stress @si)in terms of average yieldstress (psi) and effective collapse resistance interms of nominal plastic collapse resistance. This relationship is depicted in the following form&
12 + rz + z2= 1, having solutionsas follows: z = - r+J= 2
r=
Z
+
J
,and
X
2
(1)
(2)
*
where
r=
Effective collapse resistance under tension (psi) (3) Nominal plastic collapse resistance (psi)
Z =
Total tensile loading (pounds) Cross section area x Average yieldstrength *
Y
(4)
Average yieldstrengths in psiare as follows: GradeE75 . ... . .. . . 85,000 Gradem5 ... . . 110,000 GradeG105 .... ... 120,000 Grades135 ... . .. . . 145,000
. . ... .
12.9 TRANSITION FROM COLLAPSE
ELASTIC PLASTIC TO
M;rterial in the elastic range whenunder no tensile load, transfers to the plastic mge when subjected to sufiicient axial load. Axial loading, below the transition load, has no effect on elastic collapse. At transition point, the collapse resistance under tension equals the nominal elastic collapse,
and also equals a tension factor (r)times collapse resistance as calculated h m the nominal plastic formula. M e t h d Determine values for both elastic and plastic collapse from applicable formulas in AppendixA, substitute in formula (3). 12.8 and solve for r. Then, solve formula (l), 12.8, for z. For the total tension (transition) load, substitute value of z in fonnula(4). 12.8.
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
12.10 EFFECT OFTENSILE LOAD ON COLLAPSE RESISTANCE The effect of tensile load applies only to greater than transition loadon normally elasticitems, and to any loadon plastic collapseitems. In either case, the value determined from the plasticcollapse formula (Appendix A)is to be modifìed. M e t h d Substitute the tensile load value in formula (4), z. Substitute this value in formula (2), 12.8, to find a value for 12.8, to permit solution fur r. Next, substitute the value rof in formula (3), 128, to obtain the effective collapse resistance under tension. 12.1 1 EXAMPLE CALCULATION OF BIAXIAL LOADING
An example of the calculation ofdrill pipe! collapse resistance, corrected for theeffect of tensile loadis as follows: Given: String of 5-inch OD, 19.50 lb per ft, Grade E P m m m i Class drill pipe. Required: Determine the collapse resistance c o efor tension loading during drill stem test, with drill pipe empty and 15 lb per gal.mudbehindthe drill pipe. Tensionof 50,000 lb on the joint above the packer. Solution:Findreduced cross section area of Premium Class drill pipe as follows: a Nominal OD = 5 inches, nominal wall thickness = 0.362 inches. b. Nominal ID = 4.276 inches. c. Reduced wall thickness forpxemium. d Class = (0.8)(0.362) = 0.28% inches. e. Reduced OD for premium class = 4.8552 inches. f. crOss-sectional area for premium. g. Class=reducedODarea-nominalIDarea = 18.5141 - 14.3603 = 4.1538 sq.inches. h. Tension load on bottom joint = 50,000 z 4.1538 = 12037 psi. i. Average yieldsh-ength for Grade E drill pipe = 85,000 psi. j. Percent tensilestress to average yieldsh-ength 12'037 x 100 = 14.16percent =-85,000
IL Enter F i-
81 at 14.16 percent on upper right horizontal scale anddrop vertically to intersect right-hand portion of the ellipse. proceed horizontally to the left and intersectNominal collapse Resistance (cente~ vertical scale)at 92 percent L Minimum collapse resistance for premium class ("de 5) = 7041 psi. m.correctedco~seresistancefor~ectoftension = (7041)(.92) = 6478 psi. CAUZ'ZON: No safety factors are included in this example calculation Nok:Use~val~forcrosssectionalarea.tensirmaudc~llapaerating fortheappropriateclass~~~2)0fuseddrillpi~beingconsid-
d
~~
STD.API/PETRO
RP 7G-ENGL
RECOMMENDEDPRACTICE DRILL FOR
Collapse
h
O
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
0732290 Ob09783 303
L998
SIEM
DESIGN OPERATING AND
LIMITS
111
S T D - A P I I P E T R OR P
7G-ENGL
112
1998
m
0732290 Ob09782 0 4 T
m
A P I RECOMMENDEDP M C E 7 6
13 Identification, Inspection and Classification of Drill Stem Components 13.1DRILLSTRINGMARKINGAND IDENTIFICATION
body in-service failuresOCCUT near the upset runoutor within the slip area Special attention to these critical fail- aseas should be perfomed during inspection to facilitate crack detection in drill strings which havebeen subjected to abnormally high bending stresses. Drill pipe which has just been inspected and found fret of cracks may develop cracks after very short additionalservice through the additionof damage to previously accumulated fatigue damage.
Sections of drill string manufadwed in accordance with Am Speciscation7 are ideded with the markings shown in Figure 82. It is recommended that drill string members not Cracks 13.2.2 Drill covered by Specification 7 also be stencilled at the baseof the String pin as shown in Figure 82. It is also recommended that drill A crack is a single line rupture of the pipe surface. Therup string members be marked using the mill slot and groove ture shall (a) be of sufficient length tobe shown by magnetic method as shown in Figure83. 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, and drill collars found to contain cracks should be considered unfitfor further Through efforts of joint committees of API and M I X , drilling service. Shop repair of some tool joints and drill colinspection standards for the classifìcation of used drill pipe lars, containing cracks, may be possible if the unaffected area have been established. Theprocedure outlinedin Table24 was of the tool joint body or drill collarpermits. adopted as tentative at the 1964 Standardization Conference and was revised and approved as standard at the 1%8 Standardizationconference.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 Table24. The only acceptable Spezification 7 and placed in API Recommended practice 7G. wall thickness measurements are those made with pipe-wall At the 1979 Stan-on Conference, Table25 was revised micrometers,ultrasonicinstruments, or gamma-ray devices to also cover classification of used tubing workstrings. that the operator can demonstrateto be within 2 percent accuThe guidelines established in this recommended practice r a ~ yby u ~ Of e test blockssized to approximate pipe wall thickhavebeeninuseforseveralyears.Useofthepracticeand ness. When usinga highly sensitive ultrasonicinstmment, care classification guide have apparently been successful when must be taken to ensure that detection of an inclusion or lamiapplied in generalapplication. There may be situations w h m nation is not interpretedas a wall thickness measurement additional inspectionsare nquiml. 13.2.1 Limitations of Inspection Capability
Most failures of drill pipe result from some form of metal
fatigue.A fatigue failure is one which originates as a d
t of repeated M fluctuating stresses having maximm values less than the tensile strength of thematerial. Fatigue fractms are progressive, beginning as minute cracks that grow under the action of the fluctuahg stress. The rate of propagation is related to the applied cyclic loads and under certain conditions may be extremely rapid. The failure does not normally exhilit extensive plastic deformation and is therefore difficult to detect until suchtime as consided.dedamage has occuncedThereisnoacceptedmeansofinspectingtodeterminethe amount of accumulated fatigue damage or the remaining life in the pipe at a givenstress level presently accepted means of inspection are limited to location of cracks,pits, and other surface marks; measurement of r e m g wall thickness; measwementof outside diameter, and calculation ofremaining cross sectional area Recent that aof tube industry statistics confirmmajor
13.2.4 Determination (Optional)
of Cross Sectional Area
Detemine cross sectionalarea by LW of a direct indicating instnunent that the operator can demonstrate to be within 2 percent accuracy by use of apipe section approximately the Sameasthepipebeingins~IntheabSenceofsuchan instrument, integrate wall thickness measurements taken at 1inch intervals around the tube. 13.2.5 Procedure
Used drill pipe should be classified according to the pmce d m of "le 24 and as illustratedin Figure 84, d i m e n s i o n A. Hook loads at minimumyield strength for New,premium and Class 2 d d l pipe are listed in Table 26. Values recommended for minimum OD and make-up tuque of weld-on tooljoints usedwiththeNew,premiumandclass2~pipearelisted in Table 10. Maximum allowable hook loads for New, Premium and Class 2 tubing work strings (also classified in 24) are listed in Table 27. accordance with Table (Text c o n n i t n e d m page 122.)
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
-
L
I
STD.API/PETRO
RP 7G-ENGL
m
L998
0 7 3 2 2 9 0 Ob09783 T8b
Sample markings at baseof pin 1
2
4
3
5
1
Tool JointManufacturer's Symbol: ZZ Company (fictional for example only)
2
Month Welded: Wune
3
Year Welded: 70-1 970
4
Pipe Manufacturer'sSymbol: N-United States Steel Company
5
Drill Pipe Grade: E-Grade E75 drill pipe
Notes: manufacturer,and drill pipe grade symbol shall be stenciledat the base of the pin as Tool jointmanufacturer's symbol, month welded, year welded, pipe 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 i certificationpapers or purchase orders. TOOL JOINT MANUFACXJRER'S SYMBOL Refer to the eleventh edition 1993 of the IADCDrilling Manual* (Section B-1-9)for a list of Tool Joint Manufacturer's symbols. P.O. Box 4287,Houston, TX 77210. *Available hhtemational Association of Drilling Contractors
Pipe Manufacturers
Month and Year Welded
(Pipe Mills or Processors)
year 1 througb 12
Last two digits of year
AdW.
Drill Pipe Grade Grade
svmbol
E75 ................. E x95 ................. x G105 ................ G S135................. S
Heavy Weight Drill Pipe (Double stencil pipe grade symbol.) The "manufactu&' may be either a pipemill or processor. See API Specification 5D,Specificatton for Drill Pipe. These symbols are provided for pipe manufacturer identificationandhave been assigned at pipe manufacturers' requests. Manufactmrs included in this list may not be current M I Specification 5D licensedpipe manufacturers. A list of current licensed pipemanufacturen is availablein the Composite List of Manujàcturers, (Licensedfor Use of the API Monogram). Pipe mills may upset andheat íreat their own drill pipe, or they m a y have this done according to theirown specificatiom.In either case, the mill's assigned symbol should be used on each drillstring assembly sinœ they are the pipe mauufacturcr. Pipe processors maybuy "green" tubes and upset andheat treat these according to theirown specifications. In this case, the processor's assigned symbol should be used on each d d string assemhly sinœ they are the pipe manufacturer.
Mill
Algoma British Steel seamless n b e s L m Dalmine Kawasaki Nippon
Mill
Symbol
X
Amco
American seamless B D H I
NKK
K
Mannesmann Reynolds Aluminum
M
RA
sumitomo
S
S i b TamSa us Steel Vallourw: U d
SD T N V
B&W
CFm J&L Lone Star Ohio Republic TI Thbenluse vœst wheeling Piusburgh Youngstown
U Symbol TFW OMS PI
-
Figure 82-Mark1ngon Tool Joints for Identification of Drill String Components
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
Symbol A AI W C J L O R Z
Tu VA P
Y
API REC~MMENDED PRACTICE 7 6
114
No maddngs
Standard weight grade G105 drill pipe
Standard weight gradeE75 drill pipe
rW7
Standard weight grade S135 drill pipe
Standard weight gradeX95 drill pipe kld
Heavy weight grade G105 drill pipe
Heavy weight gradeE75 drill pipe
-" Heavy weight grade X% drill pipe
Heavy weight grade S135 drill pipe Drill pipe Weight cade
(1) SizeOD inchCs
(2) NominalWei& bFfi
231,
4.85 6.65.
2%
6.85
.362
(3) WallinchCs .190
(1) SizeOD
(4)
Weightcode N& 1
inchCs
A30
3
.m S50
.217
1
24.66 25.50
4 5
575
6
16.25 19.50 25.60
.2%
1 2
.m
3
19.M) 21.w
.304
1 2
2
.362
9.50 13.3W 15.50
.254
.'I49
1 2 3
11.85 14.00.
.262
1
.330 .380
2 3
24.70
.361 .415
2520.
.330
1 2
27.70
362
.368
511,
15.70 271 4% .357 *a'
inches
22.82
5
4
(4)
Weightcode N&
2
4VZ
20.00
(3) Wall'Ihicloless
.280
10.402
3'11
(2) Nomindweight bperft
13.75 16.60.
~Sstandardweightfndrillpipesizt.
Figure 83"Recommended Practice for Mill Slot and Groove Method of Drill String Identification COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
3 2 3
STD.API/PETRO
RP 7G-ENGL
L998
m
m
0732290 Ob09785 859
RECOMMENDEDPRACTICE FOR DRU SIEM DESIGNAND OPERATING LIMITS
115
Table 24"Classification of Used Drill Pipe (Ausizes, weights and grades.Nominal dimension is basis for all calculations.)
class 2 Yellow Bands Two center h c h Marks
Pipe condition
class 3
Orange Bands ThreeCenterPlmchMarks
L EXTERIOR CONDITIONS"
k ODWall
B. Dents and mashes crushing, necking
2. string shot
..
Remamug wall notless than 80%
than 70%
Remaining wall not less
Diame&r IIxiuction not oyer 3% of OD Dialmmduction not over 3% of OD
Diameterreductionnot over 4% of OD Diameterreduction not over 4% of OD
Depth not to exceed 10% of the average adjacent wall5
Depth not to exceed 20% of the average adjacent wall5
Diameterreductionnot over 3% of OD
Diameter d u c h l not over 4% of OD
Diameterincreasenot over 3% of OD
DiametainCTlXSnot over 4%of OD
Remaining wall not less
Remaining wall not less
than8096
than 70%
Remainingwall not less
than8096
Remabhg wall not less than 70%
Remaining wall not less than 80%
than805
None
None
Remaining wall not less than 80% measured from base of deepest pit
Remaining wallnot less
E. Corrosion,cuts, and gouges 1. Corrosion 2. Cuts and gouges Iangitudiual
F. Cracks3
Remaining wall notless
None
II.INTERIOR CONDITIONS A. Conosive pitting
Wall
than 70% measured from base of deepest pit
B. Emsion and weat
Wall
c. cmw
Remaining wall not less
Remaining wall notless
than8096
than 70%
None
None
NOne
T ' hepremium classificationis recommendedfor serviœ where it is anticipateclthat torsionalor tensile limits for Class 2 drill pipe and tubing wo& strings w l l ibe exceeded. These limits for F'remium Class and Class 2 drill pipe are specified ia Tables 4 and 6, respectively.PremiumClass shall be identified with two white em shoulder ofthe pin end tool joint bands, plusone center punch mark on the 35 degree a 18 d qemaining wall shall not be less thanthevalue in LE.2,defects may be ground out providing the remaining wall is not reducedbelowthe value shawn inLE.l of this table andsuch grinding to be approximatelyfaired into outer contour ofthe pipe. any classificationw k nacks or washouts appear, the pipe w l ibe identified with the red band and considered unfit f a fuaherdrilling service. 4 A n API Recommendedpractice 7G inspectioncannot be made with drill pipe rubbers on the pipe. adjacent wall is determined by measuring the wall thickness on each side of the cut or gouge adjacent to the deepest p e n d o n .
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
7G-ENGL 1998
S T D . A P I / P E T RROP
0732290 Ob0978b 795 W
API RECOMMENDED PRACTlCE 76
116
I I
I o
I I I
I I I I I
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
I I I I I
I I I
I I I
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' One White Band
pipe Body Condition
premiumclass2 T h White Bands
class 2 Blue Bands
L EXTERIOR CONDlTXONS A. OD wear Wall B. Deuts and mashes Crushing, necking
Remaining wall not less than 80%
Remamlngwall not less
Diameterductionnot over 2% of OD Diameterductionnot over 2% of OD
Diameter d u c t i o n not over 3%of OD over 3% of OD
Diameterreduction not over 4% of OD Diameterreduction not over 4% of OD
Depth not to exceed 10% ofthe average adjacent
Depth not to exceed 10% oftheaverageadjacent Wall5
Depth notto exceed 20% of the average adjacent wall5
Diameter reduction not over 3% of OD Diameterincreasenot
Diameter duction not over 4% of OD Diameterincreasenot over 4% of OD
wall5
Diameter reduction not over 2%of OD
2. string shot E. Conosion,cuts, and gouges 1. Corrosion 2.
..
Remaining wall not less than 87V,%
Diameter increasenot over 2%of OD
Diameter reduction not
over 3% of OD
than 70%
Remaining wall not less than 87V2%
Remainingwall not less
Remaining wall not less
than 80%
than 70%
Remaining wall not less than 87V2% Remaining wallnot less than 87V2% None
Remainingwall not less than 80% Remainingwall not less than 80%
Remauung wall not less than 70% .. Remauung wall not less
None
N m
Remainingwall not less
than 871/2%measured h m base of deepest pit
Remaining wall not less than 80% measured h m base of deepest pit
Remaining wall not less than70%measuredhm base of deepest pit
Remaining wall not less than 87V2%
Remaining wall notless
than8096
Remaining wall not less than 70%
Cuts and gouges LLmgitudiUal
TranSverSe F. Cracks'
..
than 80%
~
IL INTERIOR CONDITIONS (Tube and Upset) A. Corrosivepitting Wall
B. Erosion and wear Wall
ID
Am dimensions Y,,inch less than bored ID
None
None
API dimensions I l l a inch less than specified bored
D.cracks4
API dimensions V I 6 inch lesthans@edbored ID None
'Thecriticalservice classilìcation is recommendedfor service wherr:new or like new specifications apply. Criticalservice classification tubing work strings shall be identifìed with one white band The p m u i m classification is recommended for service where it is anticipated that torsionor tensile limits for class 2 tubing work strings will be exceeded Remim classification tubing work strings shall be identilied with two white bands. %emaining wall shall not be less than the value in I.E.2. Defe& may be ground out providing themmaining 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 libe ideutiíied withthe red band andconsideredunfit for fuaher service. sAverage adjacentwall is determinedby measuring the wall thickness on each sideof the cut or gouge adjacentto the deepest penetration. 6Applidleto Intemal Upsets which have been bored
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
S T D - A P I / P E T R O RP 7G-ENGL L998
m
0732290Ob09788
5b8
m
API RECOMMENDEDP R A m C E 7 6
118
-
Table 26"Hook-Load at MinimumYield Strength for New, Premium Class (Used), and Class 2 (Used)Drill Pipe
class2
NCW
lb
l b l A i n . i l L i n . S q . i n . p s i
4.85
2375
0.190
6.85 172143. 190263.
274
10.40
in.
S q . h
2375
2875
2875
3.500 9.50
0.280 1.815
0.217
0362
0.254
1.8429
2441
2.151
2992
25902
75000. 138214. 22630 95000. 1oMoo. 193500. 167167. 135000. 248786.
0.224 1.4349 77.86 107616.
2.7302
194264.
3.3984
1550 3500
n1m. 95000. 343988. 1oMoo. 380197. 135000. 488825.
0.449
2602
43037
75000. 322775.
m. 408848.
0.262 3.476 3.0767 75M)o. 230755.
m. 292290.
0.290
22205 77.70 166535. 210945. 233149.
14.00 4.000 0.330 3.340 3.8048 75000. 285359.
0.243
3.3528
33204
324118.
0.294
0.39 3.316
3.8952 0.210
3.8480
m. 410550.
nom.
26578
1.9141 0.253 143557. 66.97
1
181839.
m80. 258403. 3.3476 0.178 1.7706
28281 78.12 212150. 268723. 297010. 381870.
3.2792
77.65
mm.
24269 78.88 182016.
68.36
0.264
29891 78.56
0.304
4.3916 0.217
132793. 168204. 185910.
239027.
o m
24453
183398. 67.53 232304. 256757. 330116.
3.2306 0.314
287%
66.91 215967. rims.
302354. 388741. 3.8428 0.183
21084
68.53
158132
230554.
200301.
254823. 3n630.
221385. 284638.
224182 283%3. 313854. 4433527.
3 . m
0.231
25915
68.11 194363. 246193. 272108. 349853.
3.3847 78.32 253851. 3.7720
0.266
28434 78.97 213258.
m. 342043.
nom.
105000. 378047. 135000. 486061.
298562 383865.
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
0.152 1.2374 68.29 92801.
29298
67.80 219738.
321544. 355391. 456931.
105000. 453765. 135000. 583413. 13.75 4.500 0.271 3.958 3.6005 75000.
27448
317452 350868. 451115.
3.8680
15.70 4.000 0.380 3.240 4.3216 75000.
1.2383 67.19 92871. 130019.
20397 78.75 152979. 193774. 214171. 275363.
95000. 361454. 105000. 399502 135000. 513646. 4
0.1%
299764.
105000. 323057. 13"). 415360. 4
lb
84469.
2.2070
1oMoo. 451885. 135000. 580995.
11.85 A000
%
150662 193709.
m. 246068.
13.30 3.500 0.368 2.764 3.6209 75000.
Sq.in.
192503.
75000. 214344. 95000. 271503. 105000. 300082 135000. 385820. 75000.
in. 0.133 0.8891 68.17 66686.
97398. 107650.
1.8120 75000. 135902. 2.7882 0.174 1.4260 78.69 106946. 95000. 105000. 135000. 244624. 167043. 28579
in. 22610
105000. rimo. 135000. 349676.
4
lb
%
95000. 123902 105000. 136944. 93360. 135000.
176071. 6.65 175072.
ia
1.995 1.3042 75000. 97817. 2.2990 0.152 1.0252 78.61 76893.
278335. 307633. 395526. 43374
0.190
24719
68.65 185390.
234827. 259546. 333702
1
RP 7G-ENGL 1998
STD.API/PETRO
m
0732290Ob09789
RECQMMENDEDPRACTICE FOR DRILLSTEM DESIGN OPERATING AND
4T4
m 119
L”
Table 2Wook-Load at MinimumYield Strength for New, Premium Class (Used), and Class 2 (Used) Drill Pipe (Continued)
in. 4V2 364231.
Ib/Ain. in.
4’1,
20.00 4.500 0.430 522320. 452082 742244.
4V2
5
5
sq:in.
16.60 4.500 0.337 3.826 4.4074 75000. 330558. 4.3652 0.270 3.4689 78.70 260165. 4.2978 0.236 3.0103 68.30 225771. 418707. 462781. 595004.
J
5
in.
psi
lb in.
sq. in.
in.
I
lb
in
in.
sq.in.
%
lb
95000. 105000. 135000.
3.640 5.4981 75000. 412358. 4.3280 0.344 4.3055 78.31 322916. 4.2420 0.301 3.7267 67.78 279502 95000. lo”). 577301. 135000.
22.82 4.500 0.500 3.500 6.2832 75000. 471239. 4.3000 596903. 659735. 848230.
95000. 105000. 135000.
16.25 5.000 0.296 4.408 4.3743 75000. 328073. 4.8816 0.237 3.4554 78.99 259155. 4.8224 0.207 3.0042 68.68 225316. 415559. 459302 590531.
95000. 1Mooo. 135000.
19.50 5.000 0.362 4.276 5.2746 75000. 395595. 4.8552 0.290 4.1538 78.75 311535. 4.7828 0.253 3.6058 68.36 270432 501087. 553833. 712070.
95000. 105000. 135000.
25.60 5.000 0.500 4.000 7.0686 75000. 530144. 4.8000 525274. 580566. 954259.
9500. 671515. lo”). 742201. 135000.
19.20 5.500 0.304 4.892 4.9624 75000. 372181. 5.3784 0.243 3.9235 79.06 294260. 5.3176 0.213 3.4127 471429. 521053. 669925.
95000. 105000. 135000.
21.90 5.500 0.361 4.778 5.8282 75000. 437116. 5.3556 0.289 4.5971 78.88 344780. 5.2834 0.253 3.9938 68.52 299533. 553681. 611963. 786809.
95000. 105000. 135000.
24.70 5.500 0.415 4.670 6.62% 75000. 497222. 5.3340 0.332 5.2171 78.69 391285. 5.2510 0.290 4.5271 68.29 339533. 629814. 696111. 894999.
95000. 105000. 135000.
25.20 6.625 0.330 5.965 6.5262 75000. 489464. 6.4930 619988. 685250. 881035.
95000. 105000. 135000.
27.70 6.625 0.362 5.901 7.1227 75000. 534199. 6.4802 0.290 5.6323 79.08 422419. 6.4078 0.253 4.8994 68.79 367455. 676652. 747879. %1558.
95000. 105000. 135000.
354035.
409026.
0.400
4.9009 78.00 367566. 4.2000 0.350 4.2333 67.37 317497.
0.400
5.5292 78.22 414690. 4.7000 0.350 4.7831 67.67 358731.
68.77
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
0.264
255954.
5.1662 79.16 387466. 6.4270 0.231 4.4965 68.90 337236.
607026.
S T D - A P I I P E T R O RP 7G-ENGL L998
m
inmin
in
in.sq.in
psi
Ib in
in
0.3326 0.824 0.113 1.050 55000. 18295. 1.20 1.0048
0.090
75000.
1.50 1.050 0.154 0.742 0.4335
1.049 0.4939
55000. 75000.
23842. 32512 34679. 45516.
0.9884
27163. 37041. 39510. 51857.
1.2618
35135. 47912 51106. 67077.
1.2434
0.143
0.4950 77.48
36769. 50140. 53482 701%.
1.6040
0.1 12 0.5250 78.53
1.5836
0.153
0.6868 77.92
105000.
48481. 66110. 70517. 92554.
55000.
50018.
1.5808
0.158
0.7078 77.83
75000.
68206.
53087.
105000.
72753. 95489.
56626. 74322
80000.
105000. 1.315 0.179 0.957 0.6388
55000.
75000.
80000.
105000. 240
1.660 0.140
1.380 0.6685
55000. 75000.
80000.
105000. 3.02
1.660 0.191
1.278 0.8815
55000.
75000.
80000.
3.20
1.660 0.198
1.264 0.9094
80000.
2.90
1.900 0.145
1.610 0.7995
4.19
1.900 0.219
1.462 1.1565
1.8124
55Ooo.
0.123
0.106
0.3349 77.25
0.3862 78.20
0.116
0.6290 78.68
0.175
0.9011 77.92
2063 0.156 1.751
0.9346
55000. 75000.
80000.
105000. 4.70 2375
0.190 1.995
13042
55000.
75000.
80000. lQso00. W a
2.375 5.30 0.218 1.939 1.4773
20006
71733. 97817. 104339. 136944.
22990
55ooo. 81249. 75000. 110794. 80000. 118181. 105000. 155112
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
0.9576
0.108
21242
1.2352
0.093
0.3340
67.64
18372 25053. 26724. 35075.
27222 37122 395%. 51970.
1.2076
0.125
0.4260 66.69
23432 31953. 34083. 44734.
28873. 39373. 41998. 55122
1.5760
0.098
0.4550 68.07
25027.
37776. 51513. 54947. 72118.
1.5454
0.134
0.5930 67.27
32613. 44472 47437. 62261.
38930.
15412
0.139
0.6107
33590. 45805.
0.2878
66.39
34595. 47175. 50320. 49562 67584. 72090.
0.125 0.7354 78.69
30219.
34128. 36403. 47779.
67.16
48858.
64126. 1.8130
0.101
1.7686 0.153
0.5457 68.26
0.m9
67.26
30016. 40931. 43660. 57304. 42787. 58345.
62235. 81684.
0.109 0.6382 68.28 35099. 40450. 1.9694 47862 51053.
55158. 58836. 71222 0.152 1.0252 78.61 56388.
6m07.
22610 76893. 82019. 107650.
2.2878 0.174 1.1579 78.38
15829. 21585.
23024.
w1a
51403. 70095. 74768. 98133.
\
18418. 25115. 26790. 35161.
66045.
75000.
lb 16832 17954. 23564.
30897.
63610. 86741. 80000. 92523. 1owW)o. 121437.
105000.
%
12343. 67.47
40552
1.w.o
80000.
sq.h
28%6.
43970. 59959. 63957. 83943.
55000. 75000.
in
19477. 20775. 27267.
24948.
34927.
55000.
in
0.2244 0.079
2661 1.
75000.
225
lb
80000.
80000.
1.80 1.315 0.133
q.in % 0.2597 14283. 78.07 0.9822
105000.
105000.
Z3/a
m
API RECO~~MENDED PRAcnc€76
120
3.25 2Vs
0732290 Ob09790 L L b
63686. 2.2442 0.153 1.0027 67.88 86844. 92634. 121581.
0.133 0.8891 68.17
48903.
66686. 71132 93360. 55150.
75205. 80218. 105286.
1
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RECOMMENDEDPRACTICE FOR DRIUSTEM DESIGNAND OPERATING LIMITS
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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)
0)(9)
(2)
(18) (8)
(17)
(16)
NCW
(15) (10) (14) (11) (13
(12) class2
Remiurnclass
8
W
in.
Ib"A in.
5.95 126936.
in. 2375
ia qin. 0.254 1.867 1.6925 55000. 93087. 2.2734 0.203 1.3216 78.08 72686.
in.
sq.in.
2875
0.217 2.441 1.8120
55000.
80000. 190263.
99661. 2.7882 0.174 1.4260 78.69 76427. 135902 92801. 144962 98988.
9.50 203080.
2875
0.308 2.259 2.4839 55000.
27448
0.152 1.2374 68.29 88054.
q.in
lb
%
129922 136612
2.7518
0.246
1.9394 78.08 106667.
26902
0.216 1.6761 67.48 92186.
75000.
2875
155152 203637.
134089. 175992
0.340 2.195 2.7077 55000. 148926. 2.7390 0.272 2.1081 77.85 115945. 2.6710 0.238 1.8192 67.18 100053. 75000.
80000. 216619.
284313. 271a 10.70 2875 229337.
145532
1050M). 0.392 2.091 3.0578 55000. 168180.
27182
0.314
23690 77.47 1302%.
75000.
80000.
2.065 3.1427 55000. 172848. 2.7130 0.324 2.4317 77.38 133744. 2.6320 0.283 271a 11.00 2875 0.405 235702. 194536. 329983. 12.80 3.500 0.368 2.764 3.6209 55000. 199151. 3.3528 0.294 271569. 226293. 380197.
152933. 163128. 20917
66.56
115042
80000.
24453
67.53 134492.
251415.
105000. 28287
78.12 155577. 3.2792 0.258
80000.
28746
78.08 158101. 3.2750 0.263 2.4843 67.48 136637.
289674.
75000.
80000. 294524. 105000. 386563.
229965. 301828.
75000.
80000. 361767.
19.20 4.500 0.430 3.640 5.4981 55000. 412358. 344443. 577301.
66.68 112151.
75000.
3V2 15.80 3.500 0.476 2.548 4.5221 55000. 248715. 3.3096 0.381 3.5038 77.48 192708. 3.2144 0.333 3.0160 66.69 165879. 339156.
15.50 4.500 0.337 3.826 4.4074 55000. 330558. 277509. 364231.
20391
105000.
260853.
3.500 0.510 2.480 4.7906 55000. 263484. 3.2960 3V2 16.70 3592%. 296140. 503015.
0.274
75000.
3.500 0.375 2.750 3.6816 55000. 202485. 3.3500 0.300 3V2 12.95 276117.
474819.
26398 177~~76. 189522 248747.
244626. 105000. 321072 214106.
4V2
in. 0.178 1.1422 67.49 62820.
105000.
168647.
260165.
in. 22226
106946. 114076.
80M10. 198708. 105000. 260805. 21 '8
lb
%
105000. 75000.
8.70 186289.
in.
80000. 135399.
177711.
271,
lb
75000. 105725.
6.50
psi
280302.
241278.
105000.
0.408
3.7018 77.27 2035%. 3.1940 0.357 3.1818 66.42
17Mo1.
75000.
80000. 383249. 105000.
242409.
4.3652 0.270 3.4689 78.70 190788. 4.2978 0.236 3.0103 68.30 165565.
75000.
l.
80000.
352595. 105000. 462781. 3023%.
75000.
80000.
105000.
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
439848.
4.3280 0.344 4.3055 78.31 236805. 4.2420 0.301 3.7267 67.78 204968.
STD.API/PETRORP7G-ENGL
API REC~MMENDED PRACTlCE 76
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13.3.2.1RequiredInspections
InspectionClassificationMarking
A permanent mark or marks signifying the classification of the pipe (for example, refer to Table 24, Note 1) should be stamped as follows:
Following are required inspections:
c. Cold steel stenciling shouldbe avoided on outer surface of tube body.
a Outside diameter measurement-measure tool joint outside diameter at a distance of 1 inch from the shoulder and determineclassificationfrom data in Table 10. Minimum shoulder width should be used when tool joints are worn eccentrically. b. Shoulder conditiowheck shouldersforgalls,nicks, washes, fìns, or any other matter which would affect the pressure holding capacity of the joint and conditions which may affect joint stability. Make certain joint has a minimum 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
a. On the 3 5 d e p or 18degree sloping shoulder of thepin end tool joinL b. Or in some other low-stressed section of the tool joint where the marking will normally carry through operations.
OptionalInspections
Following are optional inspections: 13.3 TOOLJOINTS
a Shoulder width-using data in Table 10, determine minimumshoulderwidthacceptablefortool joint in class as 13.3.1 Color Coding governed by the outside diameter. b. visual thread inspectioMe thread profile is checked to 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 andor pin stretch-these are indications of 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 jointsforand performance of the tooljoint The lead gauge is the onlystandrill pipe is shown in figure 85. dard method for measuringpin stretch. On used tool joints,it 0.006 is recommended that pins having stretch which exceeds inch in 2 inches should be recut All pins which have been 13.3.2 Inspection Standard stretched shouldbe inspectedfor cracks. The followingrecommended inspection standard for used It is recommended that box counterbores (Qc),API Specitool jointswas initially includedas an appendix to Am Specification 7, Table 25, be checked. If the Qc diameter is more fication 7. It was moved to Am Recommended Practice 7G than 0.031 inch inch) outside the allowed tolerance, 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 of drill pipebody l’&lJointandDrill
PipeClassiscation
NIUlltUdcolca
dB&
...............m white one Yellow class 3 . .................... oneorange Remilrm class
class 2. ....................
’bolJoint
C o a l
condition
of Bauds
ScrapaShopRepairable ............ Red
Field Repairable. ..................Green
scrap ........................ .oneRed Figure 85-Drill Pipe and Tool Joint Color Code Identification
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
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for the The use of othertypes of tongs,or devices designed d Magnetic particle inspection"if evidence of pin stretchpurpose of making and breaking c o ~ e c t i o lmay l ~ require a ing is found, magnetic particle inspection should made be of area, especially the last engaged thread Werent minimum tong space than what would be deterthe entire pin threaded mined for manual tongs. In this case, the user should apply area,todetermineiftransversecracksarepresent. the criteria necessary to ensure that the intent of this recomIn highly stressed drilling environments orif evidence of mendation is satisfied. damage, such as cracking is noted, magnetic particle inspecSuch minimum tong space should not be construed as a tion should be made of the entire box threaded area, espemeans by which tool jointsare acceptable or not with regard cially the last engaged thread area, to determineif transverse to the strength or integrity of the connection as otherwise cracks are present. specified inthis recommended practice. Longitudinal or irregular orientation of cracking occur may as a result of friction heat checking (see 8.6). In that case 13.3.3 General magnetic particle inspection of both box and pin tool joint a Gauging-wear, plasticdeformation,mechanical surfaces, excluding any hardband area, should be performed, damage and lack of cleanliness may all contribute to erronewith an emphasison detection of longitudinal cracks. 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 be not method is preferred for tool joint inspections. Tool joints used to determine rejectionor continued use ofrotary shoulfound to contain cracks in the threaded areas or within the deml connections. tool joint body, excluding any hardband area, should be conb. Repair of damaged shoulders-when refacing a darnsidered unfitfor further drilling service. Shoprepair of some aged tool joint shoulder, a minimum of material should cracked tool jointsmay be possibleif the unaffected area of be removed. It is a goodpractice to remove not more than the tool joint body permits. '/,,-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 that a benchmarkbe provided for the deterdrill pipe shouldbe basedon safe and efficient tonging opera- mination of the amount of material which may be removed tions on the rig floor, primarily when manual tongs are in use. This benchmark should from the tool joint makeup shoulder. In this regard, there should be sufEcient tong spaceto allow be applied to new or recut tool joints after facing to gauge. The form of the benchmark may be a 3/,sinch diameter circle full engagement ofthe tong dies, plusan adequate amount of to the circle parallelto the makeup shoulwith a bar tangent tong space remaining to allow the driller andor floorhand to as shown in Figure 86. The distance from the shoulder to der, visually verify that the mating shoulders connection of the are the bar should be V,, inch. Variations of this benchmark or unencumbered to allow pmper make-up or break-out of the other type benchmarks maybe available from tool jointmanconnection without damage. ufacturers or machine shops. It is also recommended that any hard banded surfaces of the pin or box tool joint tongspace be excludedfrom the area 13.3.4 Coverage of tong die engagementas stated above whenminimum tong space is detemined. This practice w l l iensure that optimum Figure 84, dimension A, indicatesthelengthcovered gripping ofthe tongsis achieved and that damage to tong diesunder 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 notcoveredbyinspectionstandards been substantially removed, theuser may include this area in is indicated under a CAUZ'ON heading by dimension C,Figure 84. determining the minimum tong space.
c
Figure 86-Tong Space and Bench
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
Mark Position
I
124
API RECOWENDED PRACTICE 76
The followinginspection produre for useddrill collars is recommended:
bore of the elevator shouldalso be checked and corrected at this time as excessive slack between collar gmove diameta and elevator bore decreases shoulder suppoa area and can also let too much load shift to the elevator door.
a. VhaUy inspect full length to determine obvious damage and overallcondition.
13.5.4 The following inspection procedure for drill collar handling systemsis recommended:
13.4 DRILL COLLAR INSPECTION PROCEDURE
b. Measure OD and ID of both ends. C. T h ~ ~ ~ ~clean g h l box y and pin threads.Follow immediinspection for ately with wet fluorescent magnetic particle detection of cracks. A magnifying minor may be used in crack detection of the box threads.Drill collars found to contain cracks should be considexedunfìt for further drilling service. Shoprepair of cracked drill collars is typically possible if the unaffected area of the drill collar permits. d. Use a p 6 l e gauge to check thread form andto check for stretched pins. e. Check box counterbolediameter for swelling.In addition, useastrai~tedgeonthecrestsofthethreadsinthebox checkingforrockingdue to swellingofthe box. Some machine shops may cut box counterbores larger than API sa tndards,therefm, a check of the diameter of the counterbore may givea misleading result. f. Check box andpin shoulders for damage.All field repairable damage shallbe repaired byrefacingandbeveling. Ehcessive to shoulders should be repaired in reputable machine shops withAPI standard gauges. 13.5 DRILL COLLAR HANDLING SYSTEMS 13.5.1 While the recent increased usageofgrooved drill collars has helped save time in tripping, it has i n & some potential dangen to rig floor operations. These pb-
lemscanbeminimizedbystdctadherencetoregthlyscheduledinspections. 136.2 When the elevatorshoulda on a drill collar is new it is square and has sufficient area in contact with the elevator. (See Figures 87 and 88, and ‘Wle 28 fa suggested dimensions 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, 1/32inch radius worn on the comer, and a Sdegree angle on the can be reduced byas much as 40 to shoulder, elevator capacity 60percent., depending on collar size and elevatordesign. 13.5.3 Before this danger point is reached, the collar and to elevator shouldbe shopped and the shoulders brought back a square amdition. Be very sure the elevator shoulderradius on the driU collar is cold worked when shoulderis morked. (See section 14 for welding procedure limitations.) The top
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
a Thoroughly clean and examine elevator adapter for cracks. b. Check links (commonly called bails) for cracks and measure them eye to eye to be certain they are within l inch of being the same length. c. Thoroughlycleanandexamine drill collarelevator for cracks with magnetic particle inspection. Make certain that elevatorsafetylatchworkseasilyandworkseverytime. Check top seat of elevator to be certain it is square. Check elevator top bore as follows: 1. Center-latch elevator-latch elevator, then wedge front and back of elevator open and measure at largest part of top bore straight across between link arms. This method will measure total wear in bore (of which there will be very little), and wear on hinge pin and latchsurfaces.Wear should not be allowed to go above ‘/,,-inch on elevators for 5V8-inches and smaller drill collars, and VI6inch for drill collm larger than 5’/8-inche~. 2. S i d e d m elevators-latch elevator, then wedge latch open. Measure top bore h m h ntot back. Use same center-latch as for elevators. allowance wear d. Check elevator shoulder on drill collar to be certain it is square. (See 13.4for inspection procedure for the drill collar.) e. Examine drill collar slips for general condition and for correct size range for thecollars being run. Look for cracks, missing cotter keys, loose liners, dull liner teeth,bent back tapers ( h m catching on drill collar shoulder),and bent handles. f.Examine safety clampforgeneral condition. Look for cracks, missing cotter keys,galled or stlipped threads, munded-off nuts or wrenches, dullteeth,bmken slipsprings, and slips that do not move up and down easily.
Figure 874rill Collar Elevator
I
RECOMMENDEDPRACTICE FOR
DRU STEM DESIGN OPERATlNG AND
L"
125
-
OD +1116' maximum
Figure 88-Drill Table 28-Drill
Collar Grooves for Elevators and Slips
Collar Groove and Elevator Bore Dimensions
13.6 KELLYS
i-
The following inspection procedure is recommended for used
Original drill I kellys: collar size
I
a Follow all steps listed in 13.4 for drill collar inspection Worn drill collar
PIocedUreb. Examine junction between upsets and drive
section for
cracks.
4% Figure 89-Drill
Collar Wear
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
c. Check comers of drive section for narrow wear surface particularly on hexagonal kellys. If wear surface does not extend at least V 3 -SS flat, the kelly drive bushings should be adjusted if possible andor examined forwear. d. Kelly straightness canbe checked eitherof two ways: 1. Bywatching for excessive swing of the swivel and traveling block while drilling, or 2. By placing square kellys on level supports (one at each end of drive section), stretching a heavy cord from one end ofa vertical face of the squareto the other,measuring deflection, rolling kelly 90 degrees, and repeating procedure. On hexagonkellys,usethesamemethodexcept kelly will need to be placed in 120degree V-blocks so side face of drive section is vertical and deflection measurements taken on three successive sides (turning kelly through 60 degrees time). each
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13.7 RECUTCONNECTIONS
The following is recommended for recut connections: a When rotary shoulderedconnections are inspectedand u r ierecutting, the recut connection should comply found to q with the requirements of the section entitled “Gauging Practice, Rotary Shouldered Connections” of API Speciscation 7. b. It is recommended that a benchmark be applied to the recut connectionas suggested in 13.3.3.b. 13.8 PIN STRESS RELIEF GROOVES FOR RENTALTOOLS AND OTHER SHORTTERM USAGETOOLS
Following are recommendations for pin stress relief term usage tools: grooves formtal and other short
a Laboratory fatigue tests and tests under actual service conditionshavedemonstratedthebeneficialeffectsof stress relief contours at the pin shoulder. It is recommended that., where fatigue failures at pointsof high stress are a problem, relief grooves beprovided. Rental components suchas subs, drilling jars, vibration dampenem, stabilizers, m e r s , etc., are usuallyemployed for relativelyshort periods of time before being returned to service centers for inspection and repair. Connectionrepairs are made primarily because of gallrepairs ing,shoulderleaksandhandlingdamageswhile caused by fatigue failures are secondary in occurrence. providers of short term usage rental tools havebeen reluctant to take advantage of the benefits of stress relief grooves because of the material loss in repairing shoulder andthread damage. Refacing the pin shoulder and reconditioning the threads is restricted by the toleranceon the groove width per Am Speciscation7. b.To encomge the use of stress relief grooves on pins of short term usage tools, the following is recommended. For tools returned to a service facility after each well, such as
rental tools, a modified pin stress relief groove is recornmended. It is recommendedthat the modified pin stress relief groove conform to Figwe 90.Dimensions forDm are found in Table 16 of API Specification7. c. Recommended initial width of the modified stress relief groove is 3/4 (+Vl6, 4)inches. After reworking for damaged threads and shoulders, the width of the modified stress relief l1I4inches. groove should not exceed d. Technical data-stms at theroot of thelastengaged thread of the pin depends on the width of the stress relief groove (SRG). Table 29 shows calculated relative stresses for an NC50 axisymmetric finite element model with 6V,-inch box OD and 3-inch pinID. A pin with no stress relief groove is the basis for comparison. Table 29”aximum Stress at Rootof Last Engaged Thread for the Pin of an NC50 hisymmetric Model Load condition SRG width,
Note 1 Maxm i um Maximum Axial E4ylivalent StreSS
stress
stress
Stress
%
84%
82%
83%
81%
1
70%
56%
63%
53%
73%
64%
inches
111.
No SRG
75%
l m
63%
100%
100% 100%
Notes: 1.Make-up only at 562,000 pounds axial force OII shoulder. 2.1,125,000 pounds axial~ O Iapplies I t~ connection Which clulse~b u l daseparation. 3.Equivalentstressisequalto0.707[(~-~+(~-q)2+(~-~~’R u,,q,and q are principle stresses. 4.Ineachcsseshown,equivalentstressattherootoftheLestEngaged l’?mxdhasexceededtkyieldstrengthbecausethesefmiteelementcalculati~hanbeeamadeforliacarelasticmataialbeha~~.~Thebehaviorofan actualpin is elastic-plastic.
I
Nab:~’Igble16ofAPISpecificstion7 forDimensimDm
Figure 9O“odified Pin Stress-Relief Groove COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
Note 2 uaxirmun Maxm i um Axial Equivalent
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127
Note that the least stress is expected for a groove width of 1 inch. Consequently, inoperations where fatigue failuresare a of 1inch isrecommended. (SeeFigproblem, a groove width ure 16 of API SpecXcation 7.)
16 Classification Size and Make-up Toque for Rock Bits
is performedafter welding, which cannot be done in the field.
16.2 Bits’maybeclassifiedanddesignatedbyanalphanumeric code on the bitcarton with a seriesof three numbem and one letter keyed to the classification system shown in Tables 30 and 3l.
16.1 A classi6cationsystemfordesignating roller cone rock bits according to the type of bit (steel tooth or insert), the 14 Welding on Down Hole DrillingTools type of formation drilled, and mechanical features of the bit, was developed by a special subcommittee within theInter” 14.1 Usually the materials used in the manufacture of down tional Association of Drilling Contractors (IADC). The syshole drilling equipment (tool joints, drill collars, stabilizers tem was accepted by IADC in March 1987 and approval by and subs)are AISI-4135,4137,4140, or 4145 steels. 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 hasbeen performed. Standardization of DrillingandServicingEquipmentand subsequently approvedby letter ballot. It was further deter14.3 It should be emphasizedthat areas welded can only be mined that the approved form be included in API Recomreconditioned and cannot be restored to their original state free of metallurgical chauge unless a complete heat treatmentmended practice 7G.
15 Dynamic Loading Of Drill Pipe Note: For quantitative rmdts, see Refmœ 15, Appendix C.
15.1 When running a stand of drill pipe into or out of the hole, the pipe is subjected not to its static weight, but to a dynamic load. 15.2 The dynamic loadoscillates between values whichare greater and smaller than the static load (the greater values may exceed the yield), which resultsin fatigue, i.e., shortening of pipe life. 15.3 Dynamic loadingmay exceed yield in longstrings, such as 10,OOO feet. 15.4 Dynamic loadingincreases with the length ofdrill collar string.
16.3 Series numbers 1, 2, and 3 are reservedformilled tooth bits in thesoft, medium, andhard formation categories. Series numbem 4,5,6,7, and 8 are for insert bits in thesoft, medium, hard, and extremely hard formations. 16.4 Type numbers 1 through 4 designate formation hardness subclassificationfrom softest to hardest within each series classification. 16.5 Thesevencolumnlistingsundertheheading,Features, include seven featurescommon to the milled tooth and
insertbits ofmost manufacturers.Columns 8 and 9 have been removed and reserved for future bit development.
15.5 In theeventthesmallestvalueofthedynamicload
16.6 The form is designed to include only one manufacturer’s listingon each sheet, andto allow each specific bit desdropped into the hole. the string may be ignation in only one classi6cation position. It is m g x u z e d , 15.6 Thelikelihoodofdynamicloadingresulting in a however, thatmany bitsw l l idrillefficiently in a range of types 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 statement ofthis principle. Itis the responsibility of the manu15.7 For a long drill pipe string, such as l0,OOO feet, a of efficient use in spefacturer anduser to determine the range jumpoff is possibleonly if drill pipe,afterhavingbeen cific instances. pulled from the slips, is dropped at avery high velocity, such as 16 Wsec. 16.7 In using the form shown in Table 30, in conjunction 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 sequencebetofollowed is: sectional area of the annulus is large, and the mud viscosity First number designates Series. and weightare low. Second number designates Third number designates Feature.. 15.9 In case of small damping, the running time of a stand as shown in Table 3 1. Letter designates additional features, of drill pipe should notbe less than 15 seconds. tries to become negative, thepipe is kicked off the slips, and
m.
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
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API REC~MMENDED PRACTICE 7G
sapas
m
ijg Pœ I
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
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STD-APIIPETRO RP 7G-ENGL L998
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0732290 Ob09799 3 4 3
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RECOMMENDED PRACTICE FOR DRIU STEM DESIGNAND OPERATING LIMITS
Table 31"IADC Bit ClassificationCodes Fourth Position
Table 32"Recommended Make-up Torque Ranges for Roller Cone Drill Bits
Thefollowingcodesareusedinthe4thpositionofthe4-character IADC bit classification code to indicate additional desien features:
COdeFeature
COdeFeature
A Air application'
N
B
O
C Center Jet D DeviationControl E kteudedJe&
P
F G Ex&aGauge/BodyRotection
Maximum Make-upTorque Mb
R ~ e n i o f c r e d welds3 S
standardsteel ~ 0 0 t h~ode14
T
..
I
V
V
JetDefldon
K L M
-
connection
Minimum Make-upTorque Mb
Q
H J
129
W
x
ChiselInSerts
Y WCalIlsxt
z
OtherIllsxtShapes
in that series,with standard gauge,and no exirafeatures. will be designated 1-1-1-S on the bit calton.The manufacturerwill also list this bit designation
Note: Basisofcalculationsforlecommendedmake-uptorq~assumedtheuse of a thread compound containing40to 60 percent by weightof finely powdenxi metallic zinc or 60 percent by weight of finely powdered metallic lead, with not more than 0.3 percent total active applied thoroughly to all threads and shoulders(see the caution regarding the use ofbazradoPsmaterialsinAppendixGofAPISpecificafion7).Duetothe imgular geometry of the ID bore in roller cone bits, torque valves are based on estimated cross-sectional ateas and have been proven by field
inthisblockontheform
experience.
'Journal bearingbits with air circulationnozzles. 2Full extension (weldedtubes with nozzles). wmal extensions shouldbe noted elsewhere. 3 F o r percussion applidons. 4 M i l l e d tooth bits w ith nune of the extra features listed in this table. As an example,a d e dtoothbit designed for the softest sere i s,softesttype
16.8 Classification forms are available h m : International Association of Drilling Contractors (IADC), P.O. Box 4287, Houston, Texas 77210.
16.10 Common sizes for roller bits are listed in Table 34. Sizes other than those shown maybe availablein limited cutting structure types.
16.9 Recommended torque for roller cone bits isshown in Table 32. Recommendedtorque for diamond drill bits is shown in Table 33.
Common sizes for fixed cutter bits are listed in Table 35. S i z e s other than those shown may be available in limited cutting s t r u m types.
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
-
Table 33-Recommended Minimum Make-up Toques for Diamond DrillBits
Table 34-Common Roller Bit Sizes Size of Bit, in.
Bit Sub
PinID
OD
Make-upme
conneclion
in.
in.
M b
234 m REG
1 1791*
3
Size of Bit in.
3%
9'4
3718
9%
4314
1W8
918
11
4617
6
12v4
4658
6'4
13V2
6V,
14V4
@12
16
@14
17V2
2419
3OM* m3*
5171* 6306* 7660 12451*
20
16476* 17551 17757 371W
834
22 *
8'12
24
831,
26
37857 38193 38527
Table 35-Common Fwed Cutter Bit Sizes
482w
Size of Bit,
mo4*
in.
59966
371,
Size of Bit, in. 811,
60430 834 9'12
16
60895
4'12 4314 918
9111
6
1V18
6V8
12v4
6V4
14314
6V2
@I,
7%
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17V2
STD.API/PETRO R 7PG - E N G L
L998
m
0732290 Ob09803 8 2 1 H
APPENDIX A-STRENGTH DESIGN AND
~
A.1TorsionalStrengthofEccentrically Worn Drill Pipe Assume 1: Eccentric hollow circular section (seeFigure A-1). Reference: Formulusfor Stress & Strain, Roark, 3rd Edition.
FORMULAS
Note: To~ionalyield strengths for Premium Class, Table 4, and Class 2, Table 6 were calculatedfrom Equation Al, using the assumption that wear is uniform on the externalsurface.
A.2Safety
Factors
Values for various performancepperties of drill pipe are given in Tables2 through 7.The values shownare minimum values and do not include factorsof safety. In the design of drill pipe strings, factors of safety shouldbe used as are considered necessary for the particular application.
A.3 Collapse Pressure for Drill Pipe Note: See API Bulletin 5C3 for derivationof equations in k 3 .
The minimum collapse pressures given in 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 that yield similar results. The Dlt ratio determines the applicable formula,since each formulais based on a specifìc Dlt ratio range. For minimum collapse failure in the plastic range with minimum yield stress limitations: the external pressure that generates minimum yieldstress on the inside wall of a tube. ( D / t )- 1 I
Figure A-1-Eccentric T =
Hollow Section of Drill Pipe
xS,(D4-d) 12xl6xDxF’
where
F = I + - 4N2$ 32N2q2 (1-N2) ( 1 - N ’ ) ( 1 - $ ) +
48N’( 1 + 2N2 + 3 h p + 2N6)q3 ( 1 - N ’ )( 1 - h p )( 1 - N 6 ) ’ = d/D, e = D’ = torque, ft-lbs., = minimum shear strength, psi, = outside diameter,in., = inside diameter,in.
+
N
q T S,
D d
Assume 2 The internal diameter,d, remains constant and ID of the pipe throughout its life. at the nominal Assume 3: The external diameter D is d + t nominal + t minimum; i.e., all wear occurs on one side.This diameter is not the same as diameter foruniform wear.
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Applicable Dlt ratios for application of Equation A.2 are as follows: Dlt Ratio
Grade
.............................................. X95. ............................................. G105. ............................................. S135 .............................................. E75
13.60andless .12.85 and less 12.57 and less 11.92andless
For minimum collapse failure in the plastic range:
PC = Y m [D( /Lt ) - B ] - C Factors and applicable Dlt ratios for application of huation A.3 are as follows: Formula Factors Glade
A
13.60 E75 1806 0.0642 3.054 x95 3.124 G105 3.162 S135 3.278
B
C
Dlt Ratio
0.0743 0.0794
2404 2702 3601
to 22.91 12.85 to 21.33 12.57 to 20.70 11.92to 19.18
0.0946
~~
STD.API/PETRO
PRACTlCE RECOMMENDED
132
m
RP 7G-ENGL L998
API
For minimum collapse faihm in conversion or transtion zonebetweenelasticandplasticrange:
~~
0732290Ob09802
7bB
m
76
where
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 Equation A.4 are as follows:
where E = 30 x 106, this formula becomes:
Grade
E75 0.0482 x95 G10 0.0615 S135
735,294 x e x W,,
L, =
FonnulaFactas A
B
Dlt Ratio
1.m 2.029
0.0418
2.053
0.0515
22.91 to 32.05 21.33 to 28.36 20.70 to 26.89 19.18 to 23.44
2.133
A.5
Internal Pressure
A.5.1
DRILL PIPE p . = 2Y,t -
'
For minimumcollapse failure in the elastic range: 46.95 x lo6 P, = ( D / t ) [ ( D / t )- 11' Applicable Dlt ratios for application of Equation AS are as follows:
P
D '
where Pi = internal pressure, psi, Y, = materialminimum yield strength,psi, t = remaining wall thickness oftube, in., D = nominal outside diameter oftube, in.
mt Ratio
(irade ~~~~
E75.. ..........................................
32.05 andgreater
........................................... G 1 0 ........................................... S135. ..........................................
.28.36andgreater
X95
where PC = *D = *t = Y, =
26.89andgreater
.23.44andgreater
minimumcollapse prtsmle, p si nominal outside diameter,in., nominal wall thickness,in., material minimumyield strength, psi.
Nokc * 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 ' ' lbyadjustinghenominaloutside~,D,andwallthi~f,asifthewearisuniformonthe
outpideofthepipebodydtheinside"constaatvaluesof DandtfoPeachclaasofuseddrillpipefollaw..'~~are~obe~in 8pplicable Epation k2, A.3. A.4. or A.5, depending on the Dlt ratio, to determiaecollapseplessum. Runium Qasp: t = (0.80) (nominalwall), D = nominalOD - (0.40)(nominal wan) Class 2: t = (0.70) (nominelWau), D = nominalOD - (0.60) (nominalwall)
115.2 KELLYS
where Pi = internal pressure,psi, Y, = material minimum yield strength, psi, Dm. = distance across drive section flats, in., t = minimumwall,in. Note:lbedimensioatistheminirmunwallthicknessoftheddnaectimand ~bedetuminedmeachcasethroughtheuseofau~thic~
gaugeorsimilardevice. A.6
Stretch of Suspended Drill Pipe
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 astuckstringofsteelpipeduetoadifferentialpullis:
e =
L1 [Wa-2Wf(1-p)],
24E
where e = shtchin., L, = length of freedrill pipe, R,
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STD*API/PETRO RP 7G-ENGL L998
m 0732290
Ob09803 b T 4
RECOMMENDEDPRACTICE FOR DRU STEM DESIGN OPERATING AND
E W, W, m
= = = =
For steel pipe where W,= 489.5 lb/cu ft, E = 30 x 106 psi and p = 0.28,this formula will be: [489.5 - 1.44W,] ,
e="--
LIMITS
133
Toque Calculations for Rotary Shouldered Connections(see Table A-1 and Figure A-2)
A.8
modulus of elasticity, psi, weight of pipe material, lb/cu ft., weight of fluid, lb/cu ft.. Poisson'sratio.
m
A.8.1
TORQUE TO YIELD A ROTARY SHOULDERED CONNECTION
(A.11)
72 X lo7
or
where e =
9.625 x lo7
[65.44- 1.44W,],
(A.12)
where W, = weight of fluid, Ib/cufi., Wg = weight of fluid, lb/gal.
(A.13)
P = Y,A,
where
P = minimumtensile strength, lbs., Y,,,= material minimumyield strength, psi, A = cross-section area, sq.in.(Table 1, Column 6, for drill pipe).
Figure A-2-Rotary
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Y, = material minimum yield strength, psi, p = lead of thread in., f = coefficient of frictionon mating surfaces,threads
Tension
A.7
5 = tuming momentor torque required to yield, ft-lbs.,
and shoulders,assumed 0.08 for thread compounds containing 40 to 60 percent by weight of fmely powdered metallic zinc. (Reference the caution regardingthe use of hazardousmaterials in Appendix G of Specification7.), q = V 2 included angle ofthread (Figures 21 or 22, Specification7), degrees, R, =
C + [ C - ( L , , - . 6 2 5 ) x t p r ~ '42 ]
Shouldered Connection
4
1
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
API R E M E N D E D PIUCTICE 76
134
= length of pin (Specification 7, Table 25, Column 9), h., R, = 'i4(OD + Qc), in. The maximumvalue ofR, is limited to the value obtained from the calculated OD where A, =Ab, A = cross-section aread, or A, whichever is smaller, sq.in.
where OD = outside diameter,h, Qc = box counterbore (Specification7,Table 25, Column 1l), in., E = lpr x 'i8xVl2 A.8.2
MAKE-UPTORQUE FOR ROTARY SHOULDERED CONNECTIONS
where x. A, = - [(C- B y - ZP] = without relief grooves, 4
or
where A = A, or Apwhichever issmallm.Ap shall be based on pin comectiom without relief grooves, sq. in., S = recommended make-up stress level, psi.
where (Specification7, Table DX = diameter of relief groove 16, Column5), in., thread at gauge point(Speci6caC = pitch diameter of tion 7, Table 25,Column 5). in., ID = h i d e diameter, in., B =
H = t h a d height not truncated (Specification 7, Table 26, Column 3), in., S, = root truncation (Specification 7, Table 26,Column 51, ill-, tpr = taper (Specification7, Table 25, Column 4), in&, Ab=
[Oo2-
(R-w],
O
Note: For values of S,see 4.8.1 forTool Joints and 5 2 for Drill C o h .
A.8.3COMBINEDTORSIONANDTENSIONTO YIELD A ROTARY SHOULDERED CONNECTION Figure A-3 shows thelimits for combined torsion and tension for a rotary shouldered connection. The connection nomenclature is d e h e din A.8.l. The loads considered this in simplifìedapproach are torsionand tension. Bendingand internal pressure are notincluded,nor is the contribution of shear stress due to torsion. A design factor of 1.1 should be used to provide some safety margin. This safety margin may not be sufkient for cases involving severe bending or elevated temperatm. (See4.5.) The failurecriteriais either torsional yield or shoulder sep &on.
T4
T3
1
1
Pin Meld
Applied Torsion
Figure A"Limits for Combined Torsion and Tensionfor a Rotary Shouldered Connection
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~-
S T D - A P I I P E T R O R P 7G-ENGL I1998 D 0732290 0609805 477 RECOMAENDED PRACTICE FOR DRILL STEM DESIGN AND OPEFiATlNG LIMITS
The endpoints for thelimits lines are defìned by fiveequations: Pl =
(%)Ap
Tl = (‘-)Ab(’+-+R,f) 1 . 1 ~ 1 2 2n: cose Rf
(-)A
T2 = 1 . y1nl~ 1 2 P ( 2p1+~A cose R +f R 3 f )
135
J = polar moment of inertia x = - (o”- 8)for tubes 32 = 0.098175 (o”- &), D = outside diameter, in., d = insidediameter,in., Y, = material minimum yield strength,psi, P = total load in tension, lbs., 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
11x12 A +A
+
27~ cose
+ R,f
)
B BSR = Z-
2,
Depending on the connecfion geometry, 23 may be greater or smaller thanT4. The sameis true forTl and Z2. The line (0,O)to (T4, Pl) represents shoulder separation for low makeup torque. The line (22, O) to (23,Pl) represents pin yield under the combination of torque and tension. The line (Tl,O ) to (Tl,Pl) represents box yield due to torsion. The horizontal linefrom P1 represents maximum tension load on the pin.
A.9
Drill Pipe Torsional Yield Strength
A.9.1
PURE TORSION ONLY
Q=
.
O.096167JYm D
(kW
where Q = minimum torsional yieldstrength,fi-lb., Y, = material minimum yield strength,psi, J = polar moment of inertia x = - (o” - 8)for tubes 32 = 0.098175 (o”- &), D = outside diameter,in., d = insidediameter,in. A.9.2
(D4- b4) 0.098 -
-
=
D
/Y:-$
To use Fquation A.17, &st calculate: Dedendwn, b, and R
(A.16)
where QT = minimum torsional yieldstrength under tension, fi%.,
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
’
where BSR = bending strength ratio, 2, = box section modulus, cu.in., 2, = pin section modulus, CU. in., D = outside diameter of pin and box (Figure A+, in., d = inside diameter or bore (Figure A+, in., b = thread mot diameterof box threads at end of pin (Figure A+, in., R = thread root diameter of pin threads inch from shoulder of pin (FigureA+, in.
De&&
,
D4- b4 D R4-d
(A. 17)
R
TORSION AND TENSION
QT
D (R4-&) 0.098 R
H 2
= - -f,,
(A.18)
where H = thread height not truncated, in., f , = root truncation, in. b = C-
t p ~ ( L , , --625)
12
+ (2 X dedendum) , (A.19)
S T D - A P I I P E T R O RP 7G-ENGL
L998
m
0732290 0609806 303
m
API RECOMMENDED PRACTICE 76
136
Pin length, Lpc
BSR (NC46-62)=
BOX 1
I
D" - b4 D
I
"
R (6.25)4 - (4.1
20)4
6.25 (4.465)4- (2.8125)4 4.465 2.64:1 Figure A"-Rotary Shouldered Connection Location of Dimensions for Bending Strength Ratio Calculations
A.11 Torsional Yield Strength of Kelly Drive Section The torsional yield strength of the kelly drive section values listed in Tables 15 and 17 were derived h m the following equation:
where C = pitch diameter at gauge pint,in., tpr = taper,insft.
Y= R = C - (2x && - (tprh x x) V1J
(A.20)
0.577Y,,,[0.200(a3 - b3)] , 12
where
Y,,,= tensile yield, psi,
An example of the use ofEquation A.17 in determining the bending strength of a typical drill collar connection is as fol-
u = distance across flats, in.,
lows: Determine thebending strength ratio of drill collar N 62(61/40Dx213/,~IDconnection.
b = kellybore,in.
M
D = 6.25 (Specification 7,Table 13,Column 2), d = 213/16 = 2.8125 (Specification 7,Table 13,Column 3). C = 4.626 (Specilìcation 7,Table 25, Column 5), Taper = 2 (Specifìcation 7,Table 25, Column 4), Lp = 4.5 (Specification 7,Table 25, Column 9), H = 0.216005(Specification 7,Table 26,Column 3), f, = 0.038000(Specifìcation7, 'Mle 26,Column 5).
First calculate dedendum, b, andR =H - -f,= *216005- .O38000= .O700025 2 2 b=
C - tpr(L,,- .625)
A.12 Bending Strength, Kelly Drive Section The yieldin bending values of the kelly drivesection listed in Tables15 and 17 were determined by one of the following ~UatiOns:
a. Yield in bending throughcomers of the square drive section, Ym ft-k yBC
b = 4.626 - 2(4.5 - '625)+ (2X .0700025)
12
b = 4.120,
R = C - (2x && - (@r h x x) V1J R = 4.626 - (2X .07-) - (2X '/B X '/1J R = 4.465. Substituting thesevalues in Equation A. 16 determines the bending strength ratio as follows:
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
Ym (0.118u"- 0.069b> 12a
b. Yield in bending through the faces of the hexagonal drive section Y , ft-lb
+ (2x &&h)
12
=
YBF=
Y,,,(0.104a"- 0.085 b> 12a
A.13 Approximate Weight of Tool Joint Plus Drill Pipe Approximate Weight of ToolJoint PlusDrill Pipe Assembly, lb/ft =
(Weight ApproximateAdjusted + of Drill Pipe x 29.4
Approximate Weight of ToolJoint Tool Joint Adjusted Length + 29.4
(A-21)
RECOMMENDED PRACTlCE FOR DRU STEM DESIGNAND OPERATING LIMITS
where Approximate Adjusted Weight Drill of Pipe, lb/ft = Upset Weight Plain End Weight+ (A.22) 29.4 Plain end weightand upset weight are found inA P I Specification 5D. Approximate Weight of Tool Joint,=lbs 0.222 L.(D- 8)+ 0.167 (O3 - Dm3)- 0.501 &(D - D,,& (A.23) Dimensionsfor L,D, d, and Dm are in API Specification7 , Figure 6 and Table 7. Adjusted Length of Tool Joint,ft = L + 2.253 ( D - DTE) 12
A.14
(A.24)
Critical Buckling Force for Curved Boreh&s27,293J831,S
W,,,= W,(
65.5 -MW 65.5
137
)buoyantweightofpipe(lb/ft),
W, = actual weight inair (Ib/ft), MW = mud density (lb/gal), h, =
radial clearance tool of
joint to
hole (in.), DH= diameter of hole (in.), TJOD = OD tool joints(h), BL= lateral curvature rate (O/lOOft), B, = total curvature rate (O/lOOfi),
R,= 5730 - lateral build radius (ft), BL 8 = inclination angle (deg). A.14.2 If the hole curvature is limited to the vertical plane, the buckling equations simplify to the following: 12xh,xF,? 4xExZ ’
A.14.1 The following equations define the range of hole curvatures that buckle pipe in a three dimensionally curved borehole. The pipe buckles whenever the hole curvature is between the minimum and maximum curvatures d e h e dby the equations.
if F b < 4 x E x z pipenotbuckled, 12x h,xRL
if
4xExI 12xh,xRL’
where B,
= minimum vertical curvature rate for buckling (+ building, - dropping) (“/lo0 ft), B , = maximum vertical curvaturerate for buckling (+ building, - dropping) (“/lo0 f i). Fb= buckling force (lb), E = 29.6 x 106 (psi),
12xh,xFl 4xExZ ’
5730
(2)) w,x
IC
2 1/2
-
-
sine],
I = -(OD4-1D4), 64 W, = buoyant weight equivalent for pipe in curved borehole (lb/fi),
where Fb= critical buckling force(+ compressive) (lb), B,,, = minimum vertical curvaturerate to cause buckling (+ building, - dropping) (O/lOOft), By- = maximum vertical curvature rate that buckles
pipe (+ building, -dropping)(“/lo0 ft), W, = equivalent pipe weightrequiredto buckle pipe at F b ilXial load, E = 29.6 x 106 psi,
Z=
0.7854(0D4- ZD4) 16
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65.5 -MW 65.5
W, = W,(
) buoyantweightof
W, = actual weight of pipe in air (lb/ft), MW = mud density (lb/gal), h, =
pipe (lb/ft),
(””-y) radial clearance of tooljoint to
hole (in.),
DH = diameter of hole (in.), TJOD = OD of tool joint (in.), 8 = inclination angle (deg).
138
#I
RECOMMENDED P M C E 76
A14.3 figures A-5 and A-6 show the effectof hole curvaturn on the buckling force for 5-inch and 322-inch drillpipe. Figure A-7 shows the effect of lateral curvatureson the buck-
L = length of one joint of pipe (in.), E = Young’s modulus 30 x 106 for steel (psi), Z = moment of inertia of pipe (h4)
ling force of 5-inch drillpipe. For lateral and upward curvatures, thecriticalbuckling force increases with the total cutvaturerate.
Bending Stresses on Compressively Loaded Drillpipe in Curved BoreholePIM
A.15
1115.1 The type of loading can be determinedby comparing theactual hole curvatureto calculated values of the critical curval-um that d e h e the transition from no pipe body contact to point contact and f h n point contact to wrap contact. The two critical curvatures are computed from thefollowing equations. R -c
=
5 7 . 3 ~lOOx 1 2 x A D 573xL J X L tan --4XJ 4:Jl’
A.15.2 If the hole curvatureis less than the critical curvature required to begin point contact, the maximum bending stress is given b y the following: ,
57.3x 1OOx 12X4XZX sin
= &=bending stress @si), B = holecurvature, F = axial compressiveload on pipe (lb),
E = Young’s modulus 30 x 106 for steel (psi), Z = moment of inertia (in.)
--
x( OD4- ZD4) 6
4
’
1115.3 If the hole curvature is betweenthe two critical cur-
vatwescalcdated,thepipewillhavecenterbodypointcontact and the maximum bending stress is given by the following equation:
I
r
BxODxFxJxL
S, =
Sb
2
’
OD = pipebody OD (in.), ID = pipebodyZD(h). L = length of onejoint of pipe (in.),
IC(OD4- ZD4) 64 F = axial compressiveload on pipe (lb), ID = pipebody ZD (in.).
B, =
4
Sb
L = length of onejoint of pipe (in.), E = Young’s modulus 30 x 106 for steel (psi), Z = moment of inertia of pipe body (h)
57.3
6
F = axial compressive load on pipe (lb), ZD = pipebodyZD(in.).
where B, = the critical hole curvature that defines the transition from no pipe body contact to point contact (O/lOOfi), AL) = (TJOD-OD), TJOD = tooljoint OD(in.), OD = pipe body OD (h),
--
x( OD4- ZD4)
where
)
[ (
--
=
x loox 12xAD
4R
1’ L 57.3 L
Where B, = the critical curvaturethat d e w the transition from point contactto wrap contact ( O / l O O fi), ALI = (TJOD- OD), TJOD = tool joint OD (h), OD = pipebodyOD(h),
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
where E = Young’s modulus, 29.6 x 106 for steel (psi), OD = pipe body OD (in.), ID = pipebodyZD(in.), L u=-
25 ’ L = length of onejoint of drillpipe for point contact of pipe body (h), L = L, forwrap contact (in.),
REC~MMENDED PRACTICE FOR DRILLSTEM DESIGNAND OPERAllNG LIMITS
-1o
-5
5
O
Vertical build r a t e - O / l
O0 ít.
Figure A-5-Buckling Force vs Hole Curvature
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139
10
~
STD.API/PETRO RP
7G-ENGL 1'498
W 07322'40 Ob09810 834 W
API RECOMMENDED P
140
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 Vertical build ra+o/lOO ft.
Figure A H u d d i n g Force vs Hole Curvature
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
5
10
RECOMMENDEDPRACTICE FOR DRU STEM DESIGNAND OPERATING LIMITS
Figure A-7-Budding
COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
Force vs Hole Curvature
141
API RECOPMENDEDPRACnCE 76
142
A = (1+4xR L' x m ) s i n U -U~ x s i n 2 ( ~ ,
+
B = 2[ l-T-(l sin u
e
=
J =
x
y AD)sin'(3],
-m($),
r+)"'
(in.),
7c
I = - - ( o D ~ - I D ~ ) (in.3,
64
AD = diameter difference tool joint minus pipe body OD, AD = (TJOD - OD) (in.), TJOD = tooljoint O D ( h ) , R = 57.3 x 1OOx l m , B = holecurvature (O/lOOR).
A154 If the hole curvature exceeds the critical curvature that separates point contact from wrap contact, we need to first compute an effectivepipe length in order to calculate the maximum bending stress. The &&ve pipe span length is calculatedfrom the following equation by trial and enor until the calculated curvature matches the actual hole curvature:
A15.5 The maximum bending stresses cau then be computed usiug the equation for point contact and a pipe body length equal to the &&ve span length. A.15.6 One of our major concerns when drilling with compressively loadeddrillpipe is the magnitudeof the lateralcontact forces between the tool and joints the wallof the holeand the pipe body and the wall ofthe hole. Various authors have suggested operatinglimits in the range of two tothree thousand pounds or more for tool joint contact faces. There are no generally accepted operating limits for compressively loaded pipe body contact forces. For loading conditions in which there is no pipe body contact, the lateral force on the tool joints is given by: LFTJ =
FxLxB 57.3 x 100x 12 '
where FTJ = lateral force on tool joint (lb), L = length of onejoint of pipe (h), B = hole curvature (V100 R). A.15.7 For loading conditions with pointor wrap contact, the following equations give the contact forces for the tool joint and the pipe body:
57.3x 100x 1 2 x m
B =
r -
2
where L, = effective span length (h), B = holecurvature(Wooft.), AD = a d m i edif€em~ce between tool jointand pipe body* AD = TJOD-OD(h), TJOD = tool joint OD (h), OD = pipe body OD (in.), ID = pipebody ID (h).
= lateral f o m on tool joint (lb), OU pipe body (lb), L = L-L,, L, = lengthofpipe (h), L, = L forpoint contact (in.), L, = effective span length for wrap contact, 57.3 x loo x 12 R = B B = holecurvature ("/looft),
' F L = lateral force
E = Young's modulus 29.6 x 106 for steel (psi), IC
F
L, L, L
= 6 - ( 4O .D ~ - Z D ~ ) , = axidcompressiveload(Ib), = length of pipe body touching hole(h), = L-L,, = length of one joint of pipe (h.).
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AD = diameterdifference tool jointminus pipe OD (in.), AD = TJOD-OD (h), x
Z = -(OD4-ID4).
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APPENDIX B-ARTICLES AND TECHNICAL PAPERS Many of the topics covered in Recommended Practice7G have been the subject of significant investigation by various parties in the industry. Following is a partial list of articles and t e c h u i d papers on topics relatedto items found in Recommended Practice 7G.
16. Huang T., Dareing D.W., ‘%uCkling andLateralvibration of Drill Pipe,” Journal OfEngineeringfor lmkstry, November 1968, pp. 613-619. 17. Dming D. W., Livesay B.J., ‘Zongitudinalandhgular Drillstring Vibrations With Damping,” Journal of Engineering for Indzmry, November 1968, pp. 671-679.
1. Axthur Lubinski, “Maximum Permissible Dog-Legs in Rotary Boreholes,”Journal of Petroleum Technology, Febru18. Combes J. D., Baxter V. R., “Critical RotarySpeeds Can 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 DrillHole Problems. Follow Acceptable Dogleg Severity Limits,” string Vibration Measurement System, ” Society of PetroTmnsactions of the 1974 Intemutionul Associationof Drillleum Engineers (SPE) SPE 14327, presented at the 1985 ing Contrac&rs ( M C )Rotaty Drilling Conference. Technical Conference,Las Vegas, September22-25,1985. 3. K. D.Schenk,“Calco Learns AboutDrillingThrough 20. Burgess T.M., McDaniel G. L.,Das P.K., ‘Improving Excessive Doglegs:’ oil and GUS Journal, October 12, 1964. Tm1Reli&fitywithDrillstring M&&Field 4. G. J. Wilson, ‘DoglegControl In Directionally DrilledExperienceand Limitations,” SpE/IADc 16109, presentedat Wells:’ Transactions of TheAmerican InstirUte OfMining, Metthe 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 OfPetroSlipstick Motion,” SPE 18049, presented at the 1988 Techlem Technology,March 1966. Conference, nical Orleans, March New 1987. Arthm “The Effectof 6. Hansford, John E. and Lubinski, 22. Cook R. L., NicholsonJ. W., Sheppard M. C., and WestDrilling Vessel Pitch or Roll on Kelly andDrill Pipe Fatigue,” lake W., ‘FirstReal Time Measurements of Downhole VibraTmactions of MME, 1964, Vol. 23l. tions, Forces, and Pressures Used to Monitor Directional Drilling Operations,”SPElLADc 19651, presented at the 7. Thad Vreeland, Jr., “Dynamic Stresses In Long Drill Pipe 1989 SPE/IADc Drilling Conference, New Orleans, FebruStrings:’ The Petroleum Engineer;May 1%1. ary 28 to March3,1989. 8. Henry Bourne, ContinentalOil Co., Ponca City, Okla23. Warren T. M., Brett J. F., andSinor L. A., ‘Development homa, Drilling Fluid Corrosion,Unpublished. 19572, presented at 1989 SPE of a Whirl-Resistant Bit,” SPE 9. Edward R Slaughter, E.Ellis Fletcher,Arthur R. Elsear, Annual Technical Conference and Exhibition, San Antonio, and GeorgeK. Manning, “An Investigationof the Effects of October 8-1 l. Hydrogen on the Brittle Failure of High Strength Steels:’
24. Yanglie Bang, Zaiyang Xiao, ‘Motion of Reviewingthe WADC TR 56-83, June 1955. Section 9 of API RP 7G,” presented at the API Standardizato Oil and 10. H. M. Rollins, ‘Drill Stem Failures Due H$,” tion Conference, June1993. Gas Journal, January 24,1966. 25. Nicholson J.W., “An Integrated Approach to Drilling 11. Walter Main, Discussionof Paper by Grant and Texter, Dynamics Planning, Identification, and Control,” SpE/IADc “Causes and Prevention of Drill Pipe and Tool Joint Trou27537, presented at the SPE/IADC Drilling Conference, Dalbles,” World Oil, October 1948. las, February15-18,1994. 12. J. C. Stall and K. A. Blenkam, “Allowable HookLoad 26. Fereidoun Abbassian,‘Dillstring Vibration Primer,”BP and Torque Combinations For Stuck Drill String,” Mid-ContiUnpublished. Exploration, nent A P I District Meeting, Paper No. 851-36-M, April 6, 1962. 27. Dawson, Rapier, and Paslay, P.R., “Drillpipe Buckling in Inclined Holes,”Jm,October 1984. 13. Armco Steel Corporation,‘‘OilCountry TubularProducts-Engineering Data,” 1966. 28. Standard DS-I, Drill Stem Design and Inspection, Second Edition, T.H. Hill Associates, Inc., Houston, Texas, 14. Arthur Lubinski, ‘Fatigueof Range 3 Drill Pipe,”Revue August 1997. de L’Institut Fmncaisah Petrole, November 2,1977 (English 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 SympoTripping,” Journal of Petroleum Technology, August 1988. sium, Oklahoma City, A@ 1995. 145
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30. Schuh,FJ., ‘The Critical BucklingFolce and Stresses for 35. Morgan, R.P.; Roblin, MJ., “A Method for the InvestigaPipe in Inched Curved Boreholes,”SpE/IADc 21942, SPEI tion of Fatigue Strength in Seamless Drillpipe,”ASME ConIADC Drilling Conference,Amsterdam, March 11-14,1991. ference,lbha,Oklahoma, Septembex22,1%9. 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 Engineer1/21/95to JohnAltermann. h g , 12,1995, pp. 209-218. 32.Suryanarayana, PVR.; McCann,R.C., “AnExperimental 37. Hansford, J.E.; Lubinski,A., “Cumulative Fatigue DamStudy of Buckling and Post-Buckling of Laterally Conage of Drillpipe in Doglegs,”JournalOfPetroleumTechnolstrained Rods,” Journal OfEnergy Resoumes Technology,Vol. ogy, March 1966, pp. 359-363. 177, June 1995, pp. 115-124. 38. Lubinski,Arthur A., “Maximum Permissible Dog-Legs 33. Paslay, €?R; Cemocky, E.€?, ‘Bending Stress M a & c a - in Rotary Boreholes,”Journal of Petroleum Technology,Febtion 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. Exploration by Mobil and Production Center, Technical Dal34. Acknowledgment: Subcommitteeappreciates the use of las, Texasof the report, “Buckling of a Rod Confined to be in Shell Explorationand productionCompany proprietary BSM Contact with a Toroidal Surface, Parts I and H,” by Paul R. Bending Stress C ode. paslay, October 15,1993.
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