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INTENTIONALLY LEFI BLANK

ManagingSystem Integr¡tyof Gas PipetinesASME Code for Pressure Piping, B31Supplement to ASME 831.8

".;",:ll'"'li3.":l',i'i"i':#li:iïlï:i"i.;:i;'lìi:ï::i::Ìli:;î,,u&

Date of lssuance: June 1, 2010

The next edilion of thìs Code is scheduled for publìcation in 2012. There will be no addendawritten interpretations of the requirements of this Code issued to this edition.

ASI¡E ]s the registered lrademark of The American Society of i\4echanical Engineefs.

ThiS code or standard was developed under procedures accredited as meeting the criteria for American NationalStãndards. lhe Siandards Committee that approved the code or standard was balanced to assure that individuals fromcompetent and concemed interests have had an opportunity to parLicipate. The proposed code or 5tandard was madeavailable for public review and comment th¿t provides an opportunity for additio¡al publìc input from índustry, academia,regulatory ¿gencies, and the public-¿t-l¿rge.

ASI\4E does not "approve," "rate," or "endorse" any item, construction, proprielary device, or actlvity.ASI\4E does not take any position wilh respect to the validity of any patenl rights asserted ¡n conneclion wilh ¿ny

iterns meniioned ln this document, and does not undertake to insure anyone utilizing a standard agaìnst liability lorinfringement of any applicable letters p¿lent, nor ¿rssume ãny such liability. Users of a code or standard are expresslyadvìsed that determination of the validity of any such patent rights, ¿nd the risk o[ infÍingement of such rights, isentirely their own responsibility.

Participatioñ by feder¿l agency reprcsentative(s) or persoñ(s) affiliated wilh industry ìs noi lo be interpreted asgovernment or lndustry endorsement of thi5 code or standard,

AS[48 accepts respo¡sibilÌiy for only those interpretations of this document issued in accordance wiih the establìshedASME procedures and policies, which precìudes the issuance of interprelations by individuals.

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No part ol this document may be reproduced in any form,in an electronic retdev¿l system or otherwise,

without the prìor writlen permission of the publisher.

The A1"eri.rn Sociely ol [,lech¿nkal Fngineers

lhree Park Avenue, New York, NY 10016-5990

Copyríghl @ 2010 byTHE AIIIERICAN 50CIEry OF ]\¡ÊCHANICAL ENGINEERS

Al1 rights reservedPrinled in iJ.S.A.

Copyright O 20I 0 by the Anìericån Society of Mechanical Engincers &No be rnade ofthis rÌateÌial without writte¡ conselt of ASME.

CONTENTS

Forcworcl .........Commìttee Rostor ............Summ.rry of Clranges

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Perfo¡m¡nce Metrics ...........Overall Performance Measures

llr

Coplright O l0l0 by llìe ^merrcân

Socrery ol Mechanicll Lnginecrs. f&No repro<luction rnay be made ol tlrrs nralcrral wilhoul wfllrcn conse¡ìt of

^SVF. 'CQx

lntroduction

lntegr¡ty Management Program Overv¡ew. . . . . . . . . . .

Consequences

Gather¡ng, Rev¡ew¡ng, and lntegrat¡ng Data ., . . . ., ., ., . ..

R¡sk Assessment.

lntegr¡ty Assessment. . . . . . . . . . . . . . . . . . .

Responses to lntegrity Assessments and M¡tigat¡on (Repa¡r and Prevent¡on). . . . . . . . . .

lntegrity Management Plan. . . .

Performance Plan

Management of Change Plan ....

Quatity Control Ptan..... ....... .

Terms, Def¡n¡tions, and Acfonyms

References and Standards . . . . . . .

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tiguresI tntegrity ManâBement Program Elements2 Integrity Mânâgement PIan P¡ocess Flow DiagrâmJ l'otenliJl lmpact Area4 fimirìg for Scheduled Responses: Time-Dependent Threats, Prescriptive

In(c8riLy \4dna8emenl. PIiìn ....5 Hierarchy of 'l'erminoìogy for lnte8rity Assessment

Tables1 Dâta Elements for Prescriptive Pipeline Integrity Program ..........2 Typicâl Datâ Sources for PipeÌine lnlegrity ProBram3 Integrity Assessment Intervalsr Time-Dependent Threats, Internal ând ExteÌnal

Corrosion, Prescriptive Integrity Mânâgement PIan .

4 Acceptable ThreaL Prevention ând Repair Methods ....5 Example of lntegrity Mânâgement Plân for Hypotlìeticâl Pipeline Segment

(Segment l)ata: Line 1, Se8ment 3)6 !ìxampìe of lntegrity Maûa8ement Plân for Hypothetical Pipeline Segment

(lntegrity Assessment PIan: Line 1, Se8ment 3)7 Exâmple of Inlegrity Management Plan for Hypothetical Pipeline Segment

(Mìtìgâtiorì PIan: Line 1, Segment 3)Performance Measu¡es

349

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10

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28

29303031

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Nonmandatory Append¡cesA Thleat Process Charts and Prescriptive Intetrity Marìa¡jement Plans ...B Direct Assessment Process ...C Preparatiorì of Technic¡l Inquiries .

4:3

66

Copyr ight O 20lo by lhc Anìcricân Socicry of \4cchan¡cal Engrneers. fftNo rcproductiorì may bc made o l tl,lsDìaterial wrlhoulllrillcnconscnrofASMF.'GDl

FOREWORD

Pipeline system operators continuously work to ìmprove the safety of their systems and oPera-tions. ln the United States, both ìiquid arrd gas pipeÌine operato¡s have been working with theirregulators for several years to develop a mo¡e systemâtic approach to piPeline safety integritymarìagement.

'Ihe gas pipelíne incìuslry needed to address marìy teclìnical concerlìs before an integritymanagement standard could be writben. A number of initiatives were undertaken by tlìe industryto answer tlìese questions; as a result of 2 yr of intensive work by a number of teclìlìical exPe¡tsin lheir fields,20 r'eports werc issuecl that provided the lesponses required to comPlete the 2002edition of this Code. (The Ìist of these reports is included in the refcrence section of this Code.)

This Code is nonmandatory, ancl is designed to supplemenl 831.8, ASME Code fo¡ PtessurcPiping, Gas Transmission and Dìstribution Piping Systems. Not all oPerators or countries willdecide to implement this Code. This Code becomes mandatory if and when pipeline regulatorsinclude it as a requirement in tlìeir regulatiens.

This Code is a process code, whicÌr describes the process an operator may use to deveÌoP ânintegrity management program. lt also provides two approâclìes for developing an integritymânâgement progrâm: â prescriptive approach and a performance or risk-based apProâch. PiPe-line operato¡s in a numbe¡ of countries are currently utilizing risk-based or tisk-maÍIâBementprinciples to improve the safety of theiÌ systems. Solne of the international standards issued onthis subject were utilized as resources for writing thìs Cocle. Particular recognition is given toAPI and their liquids integrity managcment stânda¡d, API 1160, which was used as a model forthe format of this Code,

'Ihe ìntent of this Code is to provide a systematic, comprehensive, and ir'ìteg¡ated aPProach tomanaging the safety and integrity of pipelilìe systems. The task fo¡ce thaf developed this Codehopes that it has achieved that intcrt.

'fhe 2004 SuppÌement was app¡oved by tlìc 831 Standards Committee and by the ASME Roa¡don Pressure lechnology Codes arìd Stârìdards. It was approved as an Americân National Slandardon Mârch 1Z 2004.

Tlìis Supplemer'ìt was approved by the 831 Standards Corìrmittee and by the ASME Board onPressu¡e Technology Codes and Standards. II was approved as an American National Standardon .Àpril 20,2010.

Copyr¡ght O 2010 by the Anìerican Society ol'Mcchanical Engrneers. &\o rcDroduclion mây bc ll)ade ofrhis rnalcrral wrtlloul r+rillcn conscnl otASME. '

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ASME 831 COMMITTEECode for Pressure Piping

(the following is the roster of the Committee at the time of approval of this Code.)

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STANDARDS COMMITTEE OFFICERS

M. L. Nãyyer, Ch¿lrK. C. Eodenhamer, Y¡¿e Ch¿lr

N. Lobo, .Secle¡rry

STANDARDS COMMITTEE PERSONNEL

R. j. T, Appteby, Exxontvlobil lJpstream Research Co.

R. A, Appteton, Conlribul¡ng MenbeL Refr¡geration Systems Co.

C, Secht lV Becht Engineering Co.

A, E. Ðeyer, Fluor EnterprlsesK, C. Bod€nhemer, Énterprise Products Co.

C. J. Campbell, Air Liquide

,. S. Ch¡n, TransCanada Pipeline U.S.

D. D. Chr¡stian, VictaulicD. L. Coym, WorleyParsonsR. P. Deubler, Fronek Power systems, LLC

I, A. Dråke, Spectra Energy lransrnissionP. D. Flenner, Flenner EngÌneering Services

J. W. Frey, Stress E¡gineering Service, 1nc,

D. R. Frikken, Becht Engineering Co.

R. A. Gr¡chuk, tluor Corp.

R. W. Haupt, Pressure Piping Engineering Associates, lnc.L. €, Hayden, lr., ConsultantB. P. Holbrook, Babcock Power, lnc.G, A. lolly, Vogt Valves/Flowserve Corp.

l. A. Dßke, Choir, Spectra Energy TransmissionM. J. Rosenfeld, V¡ce Chah, Kielner and Associates, lnc,R, l. Horvath, lr. Secretory, The Amerìcan Society of À,{echanical

Engineers

D. D. Arderson, N¡Source G¿s Tr¿nsmission and Siorage

R. ,. T, Appleby, ExxonlMobil tlpslream Research Co.

R. C. Becken, Energy Experts lnternationalC. A. Bullock, Centerpoint Energy

,. S. ChiÍ,lran5Canada Pipeline U.S.

S. C, Chr¡stense¡, ConsuLtant

A. M. Ctarke, Spectra Energy TransmissionP. M. D¡cklnson, Forerunner Corp.

I, W. Fee, lJnlversal PegasusD. l. Fetzner, BP Exploration (Al¿ska), lnc.

E. N. Freeman, T. D. Williamson, lnc.

R. W. Ga¡l¡ng, Southern Caìifornla Gas Co.

M. W. Gragg, ExJ(onMobil Development Co.

S- C. G1lp¡a, Delegate, Bharat Petroleum Corp. Ltd,M. E. Hov¡s, Panhandle Energy

M. D. Huston,0NEOK Partners, LP

0. L. lohnson, Panhandle Energy

K. B. Kaplan, KBR

R. W. K¡veta, Spectra Energy TransmissionM. P. Lamontagne, L¿montagne Pipeli¡e Assessment Corp,

W. l. Koves, E(-Ortclo, UOP LLC

N. Lobo, The American Society of lvlechanical Engineers

W r. Mauro, American Electric Power

C. l. Melo, Alternote, WorleyPargons

J. Ë. Mey€r, Louls Perry and Associates, lnc.

E. M¡chaloporilos, University of i\4acedoniã

M. L. Nayyar, Bechtel Power Corp.

R. G. Payne, Alstom Power, Lnc.

I, T. Powers, WorlevParsonsA. P. Rangus, Ex.Olïicio, BechlelE. H. R¡naca, Dominion Resources, lnc.

M. l. Rosenfeld, k;etne' rnd Ascociales, ln(.R. r. S¡lv¡a, Process Engineers and Constructors, lnc.

^, Soî1, Delegûte, Engineers lndìa Ltd.

W. l. Sperko, Sperko Ëngineering Services, lnc.F. W. fôtar, FM GlobalK. A, v¡tmlnot, glack and veatchA. L. Watk¡ns. First Energy Corp.K. H. Wooten, ConocoPhlllÍps Pipe Line Co.

831.A GAS TRANSMISSION AND DISTRIBUTION PIPING SYSTEMS SECTION COMMITTEE

K. G. Leew¡s, P'PIC, LLC

R. D, Lewis, H, Rosen tl.S.A., lnc.

C. A, Mâncuso, Exxontvlobil ProductÌon Co.

W. l. Manegold, Pacific Gas and Electrlc

M. I, Mechlow¡cz, Southern California Gas Co

C. r. M¡tler, Fluor Enterprises lnc.

D. K. Moore, El Paso Pipeline Group

R. A. Muelbr, lì¡C/Ml TechnologiesG. E. Orteg3, ConocoPhillipsB. ,. Powell, NiSource, lnc.C. G. Roberts, FluorR, A, Schm¡dt, Hackney Ladish, lnc.A. Soni, Delegale, Engineers lndia Ltd.

C. l. Tat€os¡an, G¿s 5yslem Engineeri¡g. rnc.

P. L, Vaughn,0NEOK Partners, LP

F. R, Votgstådt, Volgstadt and Assocìates, lncw. ,. Walsh, EN EngineerìngD. H. Wh¡tley, À4ATE

l. K, w¡tson, WilliamsR, A. Wolf, ConsultantK. F. Wrenn, Jr., Wrentech Services, LLC

D. W. Wr¡ght, Wright Tech Services, LLC

M. R. zere[a, National Grid

I. Zhou, TransCanada Pipelines Ltd,

l. S. Zurcher, P-PLC. LLC

Copyrighl O 2t,10 by lhc A rÌcrican Socicly of Mcch¿rical ErgiDeer.. fftNo reproducuon rnay be rnadeoflhis rnalerial uilhour wrtlcrì conscnl of^SME. '(Éy

831.8 SUBGROUP ON DESIGN, MATERIALS, AND CONSTRUCTION

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l. S. Chin, Chair, TransCanada Pipeline U.5.R. l. T. Appleby, ÉxxonMobil upstream Research Co.

R. C. gecken, Ênergv Êxperts lnternationalA, M. Clarke, Spectra Energy TransmissionP. M. Dlck¡nson, Forerunner Corp.

D. J. Fet¡ner, BP Exploraiion (Alaska), lnc.R. W. Gall¡ng, Southern Callfornia cas Co.

M. D. H(ston,0NEOK Partners, LP

K. B, Kaplan, KBR

M. r. Mechlow¡cz, Southern California Gas Co.

C.l. M¡tter, tluor Enterprises, lnc.

E, K. l{ewtofl, Southern Cãlifor¡ia G¿s Co.

G. E. Ortega, ConocoPhilllpsC. G. Roberts, Fluor

M. J, Rosenfeld, Kíelner and Associãtes, lnc.

R. A, Schm¡dt, Hackney Ladish, lnc.

C. J. Tat€os¡an, Gas SVstem Lnq;reeri"g, l1c.

P. [. Vaughn,0NE0K Parlners, LP

t R. Votgstadt, Volgstadt and Associâtes, lnc.

W. r. Walsh, EN EngiñeeringD. H. Wh¡ttey, /VATE

l. Zhou, Transcanada Pipelines Ltd.

831.8 SUBGROUP ON EDITORIAL REVIEW

D. K. Moore, Cha¡L El Paso Pipeline GroupR. C. Becken, Energy Experts lnternaiionalR. W. Gait¡ng, Southern Calìlornia Gas Co.

K. B. Kaplan, KBR

K. G. Leew¡s, P-PIC, LLC

R. D. Lew¡s, H. Rosen U.S.A., lnc

831.8 SUBGROUP ON OFFSHORE PIPELINES

K. B. Kapbn, Ch¿ir, KBR

R. J.T. Appleby, ExxorìMobil Llpstream Rese¿rch Co.

M. W. Gragg, El Paso PipelLne Group

831.8 SUBGROIJP ON OPERATION AND MAINTENANCE

D. D. Anderson, Cáall., NÍSource Gas Transmission and StorageD,Ê, Adler, Co esponding l\4enbeL Colombia Gas Transmission

C. A, Aultock, Centeeoint EnergyA. lvl, Ctarke, Spectra Energy TransmissionD. M. Fox, Atmos EnergyE. N, Freeman, T. D. Williamson, lnc.M. E. Hovis, Panh¿ndle EnergyM. lsran¡, PHMSA/DOTD. L. ,ohnson, Panh¿ndle Energy

R. W. K¡veta, Spectr¿ Energy TransmissìonM. P. lamontagne, Lamont¿gne Pipeline Assessment Corp,

K. G. Leew¡s, P-PIC, LLC

R. Ð. L€w¡s, H. Rosen U.5.4., lnc.

C, A. Mancuso, ExxonMobil Production Co.

W. l. Manegotd. Pacific Gas ãnd Eìectric

D. K, Moore, El Paso Pipeline Group

R. A, Mueller, McMl TechnologiesB, l. Powell, Nisource, lnc.

,. K. W¡lson, WilliamsD. W. Wrlght, Wrlght Tech Services, LLC

M. R. zeretla, National Grid

l. S. Zurcher, P-PIC, LLC

831 EXECUTIVE COMMITTEE

N. Lobo, Secretary, The Ar¡erican Society of ¡!,lechanical EngineersC, B. Becht lV Becht Engineering Co,

K. C. Bodenhâmer, Enterprise Products Co.

D. A. Chr¡st¡an, Victaulic

l. A, Drake, Spectra Energy TransmissionP. D. tten¡er, tlenner Engineering SeruicesD, R. Frlkken, Becht Engineering Co,

R, W Haupt, Pressure Piping Engineeriñg Assoclates, lnc.L. E, Hayden, lr., Consulta¡t

A, P. Rangus, Chol¡r BechtelR, J. Howath,,r., Secre¿o¡y, The American Society of [,lechanical

Engineers

,. P Eltenberger, WFI Division, Bonney torgeR. l. Ferguson, MetaìlurgistD.l. Fetzner, BP Exploration (Alaska), lnc.P. D. Flenner, Flenner Engineering Services

l. W. Frey, Stress Engineering Service, nc.

B. P. Holbrook, Babcock Power, Lnc.

G. A. ,olty, Vogt Vaìves/Flowserve Corp.

W. ,. Koves, UOP LLC

E. M¡chalopoulos, Universily of l\4acedonia

lVl. L. Nayyar, Bechtel Power Corp,

R. G. Payne, Alstom Power, lnc.

Á. P Ra¡gus, BechtelW r. Sperko, Sperko Engineering Servìces, lncK. H. Wooten, ConocoPhillips Pipe Line Co.

831 FABRICATION AND EXAMINATION TECHNICÄL COMMITTEE

W. W. Lew¡s, E. L DuPontS. P. Licud, Weirich Co'rsull;ng Services, l1(.A,0. Natbðnd¡an, Thìelsch Engineering, lnc.

R. l, seals, ConsultanlR, l. Sitvia, Process Êngineers and Constructors, lnc.

w l. sperko, Sperko Engineering services, lnc.

E. F. Summers, lr,, Babcock and Wilcox Construction Co.

B L. Vaughan, ONEOK Parlners, LP

Copyright O 2010 by fhe A,nerican SocieLy of Mechanical Erìginccrs. &No rep¡oduclio¡ rnay be rnade ol lhis rnaler ial wirhoul wrirtcn consenl ol ASM E.

R. A. Gr¡chuk, Chol,; Fluor Corp,

N, Lobo, Secretary, The American Society oF Mechanical EngineersM. H. Barn€s, Sc¿ntec, lnc,

l. A, Cox, Lieberman Consulting LLC

R. P. Deubbr, Fronek Power Systems, LLC

Z. Diílali, Contribut¡nq MenbeL BEREP

831 MATERIATS ÏECHNICAI COMMITTEE

831 CONFERENCE GROUP

W tl. Eskr¡dge, Jr, Aker Kvaerner E and C

C, l-. Henley, Black and VeatchD. W. Rahoi, [,letallurgistR. A, Schm¡dt, Hackney Ladìsh, lnc.H. R. Slmpson, lndustry and Energy Associates, LLC

l. L,sm¡th, lacobs Engineering G¡oup

831 MECHANICAL DESIGN TECHNICAL COMMITTEE

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W. J. Koves, Cbøtl, UoP LLC

G. A. Antak¡, V¡ce Choir, Bechl Englneering Co., lnc.

C. E. O'B¡leî, Secrctary, The American Society of Mechan¡cal€ngineers

C. Becht lV Becht Engineering Co.

,. P Breen, Becht Engineering Co.

N. F. Consumo, GE Energy (IGCC)

,. P. Etlenberger, WFI Division, Bonney Forge

D, J. Fetzner, BP Exploration (Alaska), lnc.

J. A, Graz¡ano, Tennessee Valley Authority

L D. Hart. sSD, lnc.

R. W. Haupt, Pressure Piping Engineering AssociâtesB. P. Holbrook, Babcock Power, lnc.G. D, Mayers, Alion Science and TechnologyT' Q. McGwley, Tachry l-rgineer:rg Co'poràlionR. ,. Medv¡ck, swagelokJ. C. M¡n¡chlello, Bechtel National, lnc.A. W. Paul¡n, Paulin Resource GroupR. A, Robleto, KBR

E. C. Rodabaugh, Honordry Member, ConsullanlM.l. Rosenfeld, Kiefner and Associates, lnc.G. Stev¡ck, Berkeley Eñgineering and Rese¿rch, lnc.E, A. Wa¡s, wais and Associates, lnc.

A. Bell, Bonneville Power AdministrationR. A. Coomes, Commonwealth of Kentucky, Departr¡ent of

Housing/Boiler SectionD. H, Hônrath, ConsultantC. r. Haruey, Alabara Public Service Comîiss:onD. T. Jagger, Ohio Department of CommerceM. Kotb, Régie du Bâtiment du QuébecK.l Lau, Alberta Boilers Safety AssociationR. G. lvlar¡n¡, New Hampshire Public Utililies Cornmissionl. W. Meult, Manitoba Departmenl of LabourA, W. Melr¡ng, Fire and BuÌlding Boiler and Pressure Vessel

Division/fndianaR. F. lrilulhney, Boiler and Pressure Vessel Safety Branch/

J. T. Schm¡tz, Choit Southwest cas Corp.

D. K. Moore, vice Choit El Paso Pipeline GroupP D. Stumpf, Secretoly, The American Society of /Mechanical

E¡gineerst, B, Ables, EPCO, lnc.W Bãn¡ister, BP Pipelìnes (North Arneric¿), lnc.M. Bürkhart, Nicor Gas

G. E. Cêrter, State of California/Public Utilities Committee

1.5. Ch¡n, TransCanada Pipeline U.S.

M. R. Comstock, Contributìng Member, City of l\ esa/Gas DivisionG. M. Cowden, EquÌtable ResourcesK, Dent, Spectra Energy TransmissionR. Evafls, PHi\¡SA/DOTM. A, Gruenberg, Soulhwest Gas Corp.

S, C. Guqtd, Delegate, Bharal Peiroleum Corp. Ltd.O. Halnelgh, Flinl Hills Resou¡ces l-P

L, M. Haynos, K¿nsas Co'por¿lion Com11issionB. A, Heck. lMiller Pipeline Corp.L, L. Hughes, LecetS. Kem¡nska, Shell Pipeline Co.

831 QUALITICATION OT PIPEI.INE PERSONNEt TECHNICAL COMMITTEE

P. Sher, Stãte of Co¡necticutM. E, Skârdâ, Arkànsås Dep¿Irìe1t of LaborD. A. Starr, Nebraska Department of LaborD. l. Stursne, lowa UtiliLies BoardR, P Sull¡vân, The Nalion¿l Eoard of Boiler and Pressure Vessel

lnspectors

I, E. Troppma¡, Divlsion of Labor/St¿te of Colorado Boilerlnspections

C, H, Walters, Naiio¡al Board of Boiler and Pressure Vessel

lnspectorsÌV. À. M, ÌVest, Lìghthouse Assistânce, Inc.

T. F. w¡ckham, Rhode lsland Deparlment of Labor

T. j. Kasprzyk, leco Peoples Gas

T. M. Ldel, Conttibuting Membe,; ConocoPhillips Pipe Line Co.

A. r. L¡vlngston, El Paso Pipeline GroupD. D, Lykken, Washlngton lllilities and Transporlation Comr¡issionW. B, Mccaughey, Jr., Contt¡but¡ng LiembeL U.S. DOT/PHMSA'1. Meek, Contributing Nlember, El Pâso Corp.

W. l¡¡tler, PHI\4SA

L, P. Mwây, Contributing ll4embeL MidwesT Energy Associãtes

I.liyets, Contr¡but¡ng l\em¿ret EPCO, lnc.K, Riddle, Contribut¡ng Me¡¡rber, ¡¡agellän lvlidsfeam Partners, L. P

D. R¡st¡g, Cerler DoinÌ Fnergy Gds lranen'issiolR. L. Ryan, T. D. Willìar¡son, lnc.

R. E. Senders, ConLribu\ing lllember, U.S. DOT/PHMSA

E. W. Scott, AmerenR. C. Sm¡th, AGL ResourcesR. L. Stump, Consumers EnergyD. Ë. Thacker, Klnder À¡organ, lnc.T. L T¡g€r,0klahoma Corporation CommissionA. N. Welker, lnfrasource UndergroundK. WesterHayes, Contributing Member, Explorer Pipeline Co.

Copyn8lìl @ 2l,l 0 by rhc A ùrcdcan Socicry of Mcchanical Enúineers. f&No rcnroduclion rÌay be made oflhrs rnarerial witbout $rìtrcn conscnr of^SM[. '{Ðr

ASME 831.85-2010SUMMARY OF CHANGES

FoÌÌowing approval by the ASME 831 St¿ìndards Committee, the ASME Board on P¡essure Teclìnol-ogy Codes and Stanclards, and ASME, and after public levieq ASMF U31.85-2010 was approvcdby the,American National Standards lnstitute on ,Ap¡il 20,2010.

ASME Il31.85-2010 consists of B3i.85-2004; editorial chaùges, revisiorìs, ând correctiorìsi as wellâs tlìe followirìg changes identified by a margin note, (10).

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Poge Locatiotl

1 1.1

3 2.2

Chttllge

Second sentence of first paragraplldeleted

(1) Paragraphs (b)(2)(a) and (c)(1Xb)revised

(2) Penultìmate paragraph deìeted(3) Last pâ¡agraph added

Equatiorìs iìnd nomenclature rcvised toinclude metric values

Metric vaÌues added

(1) Fleadings for third, fourtlì, and fifthcolumns revised

(2) Values in fourth and fifth columrìsrevised

(3) Note (4) revised

Metric values aclded to first and secondparagraphs

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Revised

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Refe¡ence information addecl

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MANAGING sYsTEM INTEGRITY OF GAs PIPELINES

1 INTRODUCTION

1,1 Scope

This Code applies lo orìshore pipeline systems con-structed with ferrous materials and that transporl gas.Theprinciples and processes embodied in integrity man-agement are applicable to all pipeline systems.

This Code is specifically designed to provide the oper-ato¡ (âs defined in sectiorì 13) with the information nec-essary to develop and implement an e{fective integritymanagement program utilizing proven industry prac-tices and p¡ocesses. The processes alìd approacheswithin this Code are applicable to the entire pipelinesystem.

X.2 Purpose and Ob¡ect¡ves

Managing the integrity of â gas pipeline system is theprimâry goal of every pipeline system operator. Opera-to¡s wânt k) continue providing safe and reliable deliv-ery of natural Bas to their customers without adverseeffects on employees, the public, customers, or the erìvi-ronment. Incident-free operation has been and continuesto be the gas pipelire industly's goal. The use of thisCode as ¿r supplement to the A.SME 831.8 Code willallow pipeline ope¡ators to move close¡ to that goaÌ.

A comprehensive, systematic, and integrated integritymanagement program provides the means to improvetlìe sâfety ofpipeline systems. Such an integrity manage-ment p¡ogram provides the information for an operaLorto effectively allocâte resources for app¡opÌiate preven-tion, cìetection, ând mitigation activities that will resultin improved safety ând a reduction in the numbe¡ ofincidents.

This Code descrjbes a process that an opelator of apipeline system can use to assess and mitigate risks inorder to recluce both thl] ìikelihood and consequencesof inciden[s. It covers both a prescriptive- and a

performance-based integrity mârìagement program.The p¡esc¡iptive process/ when Éollowed explicitly,

will provide all the inspection, prevention, detection,and mitigation activities necessâry to produce a sâtisfac-to¡y integrity marla8el¡elìt p¡ogrâm. TIììs does not prc-clude colìformance with the requirements ofASME 831.8. The performance-based ¡ntegrity manage-ment program âlternative utilizes more data and moreextensive ¡isk analyses, which enables the operator toâchieve a grealer degree of flexibility in o¡der to meeto¡ excecd the requirements of this Code specifically in

the areas of inspection intervals, tools used, and miti8a-tion technjques employed. An operator cainot proceedwith tlìe performance-based integrity pro¡lram untiladequate inspcctions âre performed that provide theinformation on tlìe pipeline condition required by theprescriptive-based program. 'l-he level of assurance of a

performance-based program or an alternative interna-tional standa¡d must meef or exceed tlìat of a prescrìp-live program.

TIìe requi¡ements for prescriptìve- and performance-based integrity marìagement pro8rarns â¡e p¡ovided ineach of the sections in tlìis Code. hì additioù,Nonmandatory Appendix A provides specific âctivities,by tlìreat categories, that an operabr shall follow inorder to produce â satisfactory prescriptive ìntegritymânagement ProSram.

This Code is intended for use by individuals andteams charged with planning, implenentilì9, andimproving â pipeline integrity management program.Typically, a tcdm will include manrgers, engint'ers,operatìng persolìnel, technicians, and/or specialistswith specific expcrtìse ìn prevention, detection, and mit-igation activities.

1.3 lntegr¡ty Management Principtes

A sel of plincìples is the bâsis for the intent ând spe-cific details of this Code. They are enumerated here sothat the user of tlìis Code cân understand tlìe breadthand depth to which integrity shall be an integ¡al ândcontinuing part of the safe operation of a pipelinesystem.

Functional requirements for inteBrity mânagementshall be engineered into ncw pipeline systems from ini-tial pÌanning, desìgn, mâte¡ial selection, and consfruc-tion. lntegrity management of a pipcline starts w¡thsouncl design, mâte¡ial selection, and construction ofthe pipeÌine. Guidance for these âctivities is primalilyprovicled in ASME 831.8. There ale also a number ofcorìsensus standards thât mây be used, as well as pipe-line jurisclictional safety regulations. If a new line is tobecome a part ol an inteBrity mânagement p¡ogram, thefunctional requirements for tlÌe line, including preven-tion, detection, and mitigatìon activities, shall be consid-ercd in orcler to meet tlìis Code. Complete ¡eco¡ds ofmaterial, design, and construction for the pipeline areessential for the iùìtìatìon of a good integrity Ì¡anâge-ment program.

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System ilìtegrìty requires commitment by alloperating persorìnel using comprehensive, systematic,and ilìtegrâted processes to safely operate and maintainpipeline systems. ln order to have an effective integritymanagement program, the program slrall address theope¡âtor's olganization, processes, and the physicalsystem.

Arì i1ìtegrity management program is continuouslycvolvilìg and must be flexible. An integrity managementprogram should be customized to meet each operator'sunique coiìditiens. The program slrall be peliodicallyevaluated and modified to accommodâte changes inpipeJine operation, changes irr thl: operating cnviron-ment, arìd the influx of rìew datâ ânLl irìformatiorì âboutthe sysfem. Periodic evaluation is reqtrìred fo ensulethe p¡ogrâm takes âppropriate advântâge of improvecltechnologics and that the program utilizes the best setof prevention, detection, ancl mitigation activities thatareavailabÌe fo¡ the conditjons at lhat time. Additionally,as the integrity manaBement program is implemented,the effectiveness of the activities slìall be reâssessed andmodified to ensure the contìnuing effectivcness of theprogram and all its activities.

Information integration is a key component for man-aging system integrity. A key element of tlìe iùtegritymanagenent framewo¡k is the integration of all perti-nent irìformation wÌren performing risk assessments.Information tlìat cân impact an operator's undelsLand-ing of the important risks to a pipeìine system comesfrom ¿ì variety of soulces. Thc operator is in the bestpositiorì to gather and analyze this informâLion. By àna-lyzing all of the pertinent information, tlìe operator candetermine where the risks of an incident are tlìe greatest,and make prudent decisions to âssess ancl reducetlìose risks.

Risk assessment is an analyticâl process by which anoperator defermines the types of adverse events or con-ditions lhat miBht jmpact pipeline integrity. Risk assess-ment also determines the likelihood or probability ofthose events or conditions that wìll leâd to â loss ofintegrity, anc{ tlìe natu¡e aùd severity of the conse-quences that might occur folkrwing a failure. This ânâÌyt-ical process involves the integration of design,construction/ operatin8, mainteluncc, testìng, ilìspcc-tion, and other informatiorì âbout a pipeline system,Risk assessments, which are the ve¡y fourìdation of ânin(egrity m¿nngemerìt prôBrdm, c.rn vary in scope orcomplexity and use different methods or teclìniques.The ultimate goal of assessing risks is to iderìtify themost significant risks so lhat an operâtor can developan effective and prioritized p¡evention / dctection /mitig.ìtion pl.ìn to addrcss tlìe r¡sks.

Assessing rìsks to pipeline integrity is a conlinuousprocess. The operator shall pe¡iodically gather new oradditional information ân.l system opelating experi-ence. These shall become part ofrevisecl risk assessmelìts

ancl analyses that in turn may require adjustments tothe system integrity plan.

New technology should be evaluated and imple-mented âs appropriate. Pipeline system operatorsshould avail themselves ofnew techrìology âs it becomesproven rnd prJctical. New tcchnologics mdy improvean operator's ability to prevent certain types of failures,detect risks more effectivcly, or imp¡ove tlìe mitigâtionof risks.

Pe¡formance measurement of tlìl] systern and the pro-gr¿ìm itself is an integ¡âl part of a pipeline irìtegritymanagemenl program. Each operator sllâÌl choose sig-nificant perÉormance meâsures at tlìe beginnìng of theprogram and then periodically evaluate lhe resuìts oftlìese measures to monitorând evaluate tlìe effectivelìessof the program. Pe¡iodic reports of the effectiverìess ofân operator/s integrity malìagement program shall b(}iss(ed ând evaluated ilr o¡der to continuously improvethe program.

Integrity management activities shall be communi-cated to tlÌe appropriate stakeholders. Each operato¡shaìl ensule that all appropriate stakeholders ale giventhe opportunity to participate in the risk assessmentprocess and that tlìe results are communicatedeffectively.

2 INTEGRITY MANAGEMENT PROGRAM OVERVIEW

2.1 General'lhis section describes the required elements of an

integrity management program. These program ele-ments collectively p¡ovide thebasis for a comprehensive,systematic, and integrated integrity management pro-gram. ï'he program elements depicted in Fig. 1 ar€required for all inte¡rrity managenent programs.

This C<lde requires that the ope¡ator document howits integrity management prog¡âm will âddress the keypÌogram elements, This Code utilizes recognized indus-try practices for developing ân integrity managelnent

Program.The process shown in Fig. 2 p¡ovides a common basis

to develop (and periodically reevaluate) an operaLor-specific p¡ogrâm. In developing the program, pipelineoperators slìâll corìsider their companies' specific integ-rity management goals ¿ìnd objectives, and tìren applythe processes to ensure that these goals are achieved.This Code details two approaches to inlegrity manage-ment: a prescriptive method and a performance-basedmetlìod.

'l'he prescriptive ilìtegrity management methodrequires the Ìeast amount of dâtâ and ar'ìalysis, and canbe successfully implementcd by followin8 tlìe steps pro-vided in lhis Code and Nonrìandato¡y Appelìdix A.The prescriptive metlìod incorporales expected worst-case indication growth to establish inteNals betweersuccessive jntegrity assessments incxchange for reduceddata requirements and less-extensive anaÌysis.

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The performalrce-based integtity mânâgementmethod lequires more knowledge of the pipeline, andconsequently more data-irìfelìsive risk assessments andanalyses can be completed. The resulting performance-based integrity managemenf program can contiìin moreoptions for jnspectiorì intervâls, inspeclion tools, mitiga-tion, ând prevention metlìods. The results of the per-formance-based method must meet or excced the ¡esuìtsof the prescriptive method. A performance-based pro-gÌam cannot be implemented untìl the operator has per-formed adequate integrity assessments tlìat provide thedata fo¡ a performance-based program.,\ performance-based integ¡ity management p¡ogrâm shall include thefollowing in the integrity management plan:

(r¡) a description of tlìe risk analysis metlìodemployecl

(b) documentation of âÌ1 of the appÌicable data fo¡each segment and wlìe¡e it wâs obtained

(c) a documented analysis fol dete¡minirìg integrityassessment intervals ând mitigation (repair and preven-tion) methods

(d) a documented performance mâtrix tltat, in time,will confirm the performance-based options chosen bythe operator

The processes for developing and implementing aperformance-based integ¡ity manâgement program areincluded ir¡ this Code.

There is no single "best" âpproâclì tlìat is applicableto allpipeline systems for all situations. l'hisCode recog-nizes the importance of flexibility in designing integrityman¿rgement p¡ograms ancl providcs âltclnatives com-mcnsurate with this nced. Operators may clìoosc eithe¡ aprcsciiptive- or â performance-based app¡oach for theirentire system, individuâl lines, segmelìts, or itrdividualtlìreats. The program elements showtì in Fig. 1 arerequired lor aÌl integrity manâgement ptograms.

The process of managing integrily is an integratedând iterâtivc process. Although tlìe steps depicted ìnFig.2 are shown sequentially for ease of illustratiùì,there is a significânt âmount of information ilow andinterâction âmong the different steps. For example, tlìeselection of a risk assessment âpproâch depends in parton what ìntegrity-related data and information is avail-able. While periorming a risk assessment, additionalclata rìeeds may be identifìed to more âccurâtely evaluatepotentiaì tlìreats. Thus, the data gathering arìd riskassessmenl steps are tighlly coupled and may requireseverâl iterations untiÌ an operâtor has confidence thâta satisfactory assessment has been achieved.

A brief overview of the individual p¡ocess steps isprovided in section 2, as well as inslructions to the rì1orespecific and detâilcd dcscription of the individual ele-ments that compose the remainder of this Code. Ileferences to the specific delailed sections in this Code areshown in Figs. 1 and 2.

2.2 lntegrity Threat Ctass¡fication'Ilìe first step irì marìaging integrity is id'rntifying

potentiaÌ threats to integrity. All threats to pipelilìe ìnteg-¡ity shall be consìdered. Gas pipeline incident data hasbeen analyzed and classified by tlìe Pipeline ResearclrCommittee Inlernational (l'RCl) irrto 22 root causes. Eâchof the 22 caüses represents â tlìreât to pipeline integtitythat slìall be managed. One of the causes reported byoperators is "unknown"; tlìat is, no root cause o¡ causcswere identifiecl. Tlìe rcmâining 21 threats Ltave beengÌouped into nine categories of related failu¡e typesâccording to lheir nature and growth charâcteristics, andfurther clelineafed by tlìree tirne-rclated defect types.Tlìe nine categories are useful in identifying potentialthreats. Risk assessment, integrity assessmenl, and miti-gation ac[ivities shall be correctÌy addressed accordirgto the timc f¡clors and iailurc modc groupin6.

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(n) Tine-Depcnc[ent11) external co¡rosiol(2) internal corrosíon(3) stress corrosion cracking

(l)) Stnble(1) manufacturing-related defects

(d) dcfective pipe seâm(b) clefective pìpe

(2) welding/fabrication related(a) defective pipe girtlì weld (circ um ferentia l)

including branch and T joints(ü) defective fabrication weld(c) w¡inkle bend o¡ buckle(d) st¡ipped threads/l¡roken pipe / couplì1ìg

failure(3) equipment

(4) gasket O-¡inB failure(¿r) controÌ/relief equipment malfunction(c,) seal/pump packing failtrre(¡l) miscellaneous

(c) Tine-ltñepctule nf(l) lhird partylmechanical damage

(n) darnage inflicted by first, second, or third par-ties (irìstântaneous/immediate failure)

(ü) previousÌy damaged pipe (srrch as dents and/or gouges) (delayed failure mode)

(c) vandalism(2) incorrect operationâl proccdure(3) weather-related and outside ferce

(n) coìd weathe¡(ll) lightrting(c) heavy rains or floods(d) earth move¡nents

The iuteractive nature of tlìreâts (i.e., more than onethreat occurring on a section of pipeline at the sametime) slìall also be considered. An exampie of such aninteraction is corrosion at a location that also has third-party dâmage,

The operator shall consìder each lhreat irrdividuallyor in the rìine câtegories when lollowing the processseÌected for each pipeline system or segment. The pre-scriptive approach delineâted in Nonmandato¡yAppendix A enables the operator to conduct tlÌe threatanalysis irì lhe con[ext of the nine categories, All 21

th¡eats shall be considered when applying the perform-ance-basecl approach.

If the operational mode changcs ând pipeline seg-mcnts are subjected to sigr'ìificant pressure cycles, pres-sure differerìtial, ârìd rates of change of pressu¡efluctuations, fatigue shallbe considered by the operâtotincluding any combinecl effect from othe¡ fâilure mecha-nisms tlìât are considered to be p¡esenf, such as coll.o-siorì. A useful ¡eference to help tlle operator with thiscolìsidcration is GRI 04-0178, "Effect of Pressure Cycleson Gâs Pipelines."

2.3 The lntegr¡ty Management Process'Ihe integrity management process depicted in Fig. 2

is described below.

2.3.1 ldent¡fy Potent¡al P¡peline lmpact by Threat.'lhis program element involves tlìe identificatìon ofpotential threats to the pipeline, especiaÌly in a¡eas ofconcern. Each iclentified pipeline segment shall hâve thethreats considered individuaìly or by the nine catego¡ ies.See para.2.2.

2.3.2 Gather¡ng, Rev¡ew¡ng, and lntegrat¡ng Data,The first step in evaluating tlìe pofential tììreats for a

pipeline system or segnerìt is to define and gather tlìenecessa¡y data and informa[ion that clìaracterize thesegments and the potenlial lhleals to thât se8ment. Inthis step, the ope¡ator performs the initial collection,review, and integr¿ìtion of Ìelevânt data and informationthÂt is needed lo understand the condition of the pipe;identify the location-specifìc threats to its integrity; arìdunderstand the public, envi¡onmental, and operatìonalconsequences ofan jnciclent. The types ofdata tosupporta risk âssessment wilÌ vary depeirding on the threatbeing assessed. Informâtion on the operation, mainte-nânce, patrolling, desiBn, operâting history, and specificfailures and coiìce¡ns thât are unique to each systemand se8ment wilÌ be needed. Relevant data and inlorma-tion also include those conditions or actions tÌìat affectdefect growlh (e.9., deficiencies i¡r cathodic protection),reduce pipe properties (e.g., field weldìng), or reìate tothe introduction of new defects (e.fl., excavation worknear a pipeÌine). Section 3 provides information on con-sequences. Section 4 provides details for data gathe¡irìg,review, and integration of pipeline data.

2.3.3 Risk Assessment. frì this step, thc dâLa assem-bled frorn the previous step are used to conduct a riskassessment of tl-ìe pipeline syslem or se8ments. Throughthe integrated evaluatiorì of tlìe information ând datacollected in the previous step, the risk assessmerìt pro-cess identifìes the location-specific events and/o¡ corìdi-tions that could lead to a pipeline failure, and p¡ovidesan understanding of the likelihood and consequences(see section 3) of an event. The output of a risk assess-ment should include the nature and Ìocation of the mostsignificânt risks to the pipeline.

Under the prescriptive approach, âvailable data arecompared to p¡escribed criteria (see Nonmandato¡yAppenclix A). Risk assessments are required in order toral.lk the segments for integrity assessments. The pel-fo¡mance-based approach relies on detailed risk assess-ments. 'Ilìe¡e ¡re â vâr'iety of risk assessment methodsthat can Lre applied based on the available datâ ârìd thelìaturc of the tlìreats. l'he ope¡ator shoulcl taiìo¡ themethod to meet tlìe needs of the system. An initialscreenilì8 risk âssessmerìt car'ì be beneficial in terms offocusing resources on the most important arcâs to beaddressed and wlìere additional data may be of value.

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Section 5 provicles details on the crite¡ia selecbion fo¡the prescriptive approaclì âlìd risk assessmenL for theperformarìce-based approach. The ¡esults of this stepenable the operator to prioritize tlìe pipelille segmentsfor appropriate actions that will be clefined in the integ-rity management plan. Nonmandatory Appendix A pro-vides the steps to be followed for a prescriptive program.

2.3.4 lntegr¡ty Assessment. Based on the riskassessment made in the previous step, tlìe appropriateinte8rity assessments are selectecl and conctucted. TÌìeintegrity assessment metlìods are in-line inspection,pressure testing, di¡ect assessmenl, or other integrityassessmelìt rnethods, as defined in para. 6.5. Integrityassessmelìt method selection is based oir tlìe threats thâthavc been identified. More thân one integrity assessmentmethod may be lequired to acldress all tlìe threats to a

pipeline segment.A performance-bascd prograrn may be able, through

appropriatc cvâluation and analysis, to determine alter-native courses of action and time frames for performingìnteg¡ity assessments. lt is the operators' responsibilityto document the ânaÌyses justifying tlìe alternativecourses of action or time frames. Section 6 providesdet¡ils ol't tôol :,elcction ¡nd inspection.

Data arìd irìfo¡mation irom integrity assessments fora specific threat may be of value when considering thepresence ofother threats and perfo¡ming risk assessmentfor those threats. For exâmple, a dent m¿ìy be identifiedwhen running a magnetic flux leakage (MFL) tool whilechecking for corrosìon. This data element should be inte-g¡ated with other data elements for othcr tlìreats, suchas third-party or constmction damage.

Indications that a¡e .liscovered during inspectionsshall be examined and evaluated to determine if theyare actual defects or not. Indications may be evaìuatedusing an appropriate examination and evâluation tool.Fo¡ local internal o¡ externâl metâl loss, ASME Il31G orsimilar analytical methods may be used.

2.3,5 Responses to lntegr¡ty Assessment, M¡t¡gat¡on(Repair and Prevent¡on), and Sett¡ng lnspectionlntervats. In this step, schcdules to ¡espond to indica-tions from ilìspcctions are developed. I{epair activitiesfor the ânomalies discovered during inspection are iden-tified ând ìniliated. Repairs are performecl in accordancewith accepted industry standards and p¡actices.

Prevention prâctices arc âlso implemeùted in tlìis step.For thi¡d-party dâmâge prevention ând ìow-stress pipe-lines, mitigation may be an appropriate alternative toinspection. Iror example, if clam¿ìge from excavation wasidentìfied as a significant risk to â p.1¡ticular system orsegment, tÌìe oper¿ìtor may elect to conduct damage-prevenlion activities such âs increased public communi-cation, more effective l}xcavation notification systems,or increased excavator âwareness in conjunction witlìinspectiorì.

The mitigâtion âlternatives Ànd implementaLion Lime-frames for perfornìance-based integrity ùìànaBementprograms may vary frorn the presc¡ iptive requirements.ln such instânces, the performance-based analyses thâtlead to these conclusions shall be documer'ìted as pal t ofthe integ¡ity nanagement program. Section 7 providesdetâils on repair and prevention techniques.

2.3.6 Update, lntegrate, and Rev¡ew Data. After theìnitial integrity assessments have been performcd, theoperator has improved and updated information abouttlìe coûdition of the pipeline system or segment. Thisinformation shall be ret¿rined and added to the d¿ìtâbaseof information used to support future risk assessmentsand integrity assessûlents. Furthermore, as the systemcontinues to opelâte, âdditionaÌ operating, mainLenance,and othe¡ info¡mation is collected, thus expanding andimproving the historicaì databâse oi operatingexPerience.

2,3.7 Reassess Risk. Risk assessrnent shall be per-formed periodically within regular intervaìs, ancl whensubstantial chânges occur to the pipeline. lhe operâto¡shall conside¡ recent operatin8 data, consider changesto the pipeline system design and operation, analyzethe impact of any external changes that may haveoccurred since the l¿ìst risk assessmenL, and incorporatedaLa from risk assessment activities for olher threats.TÌre results of integrity assessmenL, such as internâlinspcction, shall also be factorcd ilìto fúture risk assess-merìts, to erìsure that the ânalyticâl process reflccts tlìeIatest undersl¡ndinE of pipc co¡diriôn

2,4 lntegrity Management Program

Tlìe essential elemerìts of an integrity managementprogram aÌe depictecl in FiB. 1 and are described below

2.4.1 lntegr¡ty Management Plan. The inlegritymanâgementplan is the outcome ofapplying the p¡ocessclepicted in Fig.2 and discussed in section L The planis the documentâtion of the execution c¡f each of thesteps ând the supporting analyses that âre corìducted.The plan shall include prevention, detection, ând mitiga-tion prâctices. The plan shall also have a schedule estab-Ìished that considers the timing of the p¡acticesdeployed. Tlìose sys[ems or segments with the lìi8hestrisk shouÌd be addressed fjrst. Also, tlte plan shall con-sider those practices tlìat may address more Lhân onetl-ìreaL. For instance, a hydroslatic test may clemonstratea pipeline's integrity for both time-dependent threatslike internal and external corrosion as welÌ as staticthreâts suclì âs seam wcld defects and defective fâbrica-fior weìds.

A performance-based integrity mâlìagement plan con-tains the same basic elemcrìts as a prescriptivc plarì. Aperfo¡rnânce-based plan requires mo¡e cletailed infor-matiorì and analyses based on more extensive knowl-edge about tlìe pipeline. This Code does lìot require a

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specific risk arlaÌysis rnodel, onÌy that the risk modclused carì be slìowrì fo be cffcctive. Ihe deLaiied ¡iskanâlyses will provide â bcttcr understanding of i¡tegtity,which will enable an operator to have a greater degreeof flexibiÌity in the timing and methods for the imple-mentation of a performance-based integrity manage-ment plan. Sectìon 8 provides details on plândevelopment.

The plan shalì be periodically updated to reflect newinformâtion and tlìe currelìt unde¡standing of inLegritythreâts. As new risks or r'ìew marìilestations of pre-viously known risks are identified, addirional mitigativeactioiìs to address these risks shâll be performed, asapprop¡iate. Furthermore, the updated risk asscssrnenLresults shaÌÌ alst¡ be usecl to support sclìeclulitìg of futureinteBrity âssessments,

2.4.2 Performance Ptan, Tlìe ope¡ator slìall colleclperformance information and periodically evâluate thesuccess of its integrity assessment teclìniqucs, pipelinerepair activities, and the mitigative risk control activi-ties. Ihe operâtor shall also evaluâte tlte effectivcncssof its managemenl systems and p¡ocesses in supportingsound integrity management decisiolìs. Section 9 pro-vides the info¡mation required for developirg perform-arìce measures to evâluâte program effectiveness.

Tlìe application of new technologies into the irtegritymarìagement progrâm shall be evaluated for furtlìer useìn the program.

2,4,3 Communicat¡ons Ptan. The operator shalldevelop and implernent a plan for effective communica-tions with employees, the public, emergency responders,local officials, and jurisdictional authorities in ordel tokeep thc publìc informecl about their integrity manage-ment efforts. This plan shall provide infolmatiolì to becommunicated to each stâkeholder about the integtityplan and the results achieved. Section 10 provides fur-ther irìformation about communicâtions plans.

2.4.4 Management of Change Plan. Pipelirìe sys-tems and tlìe erìvironment in which they operate ateseldom static. A systematic process shall be used toensure tlìat, p¡ior to implementation, changes to thepipeline system design, operation, or mâinterance arcevaluated fo¡ tlìeir potential risk impâcts, and to ensuÌethat changes fo the environment in which thc pipelineoperates are evâluated. Aftet these changes are rlade,tlìey shall be irìco¡porated, as appropriâte, into futurerisk assessments to ensure tÌìât the risk assessment pro-cess addresses the systems as currenliy configured, oper-ated, and maintained. The results of tlìe pìan's mitigativeacfivities slìould be used as a feedback for sys[ems andfacilities design and ope¡ation. S(]ction 11 discusses theimportant aspects of managilìg clwrgcs as they relateto integrity ûlânagement.

2.4.5 Quatlty Control Plan. Section 12 discusses thceval(ation of the integrity management program for

quality control puryoscs. That section outlilìes tlìe rìeces-sary documentatiorì for the integrity marìagemelìt pro-gram. The section also discusses auditing of thcprogram, incìuding the processes, inspections, mitiga-tion activities, ancl prevention activities,

3 CONSEQUENCES

3.1 General

Risk is th(] màthematicâl product of lhe likelihood(probability) and tlìc colìsequer'ìccs of events tÌ-ìat tesultfrom a fâilure. Risk may be decrcascd by teducing eitlìerthe likelihood or the consequences of a failure, or both.Tlìis section specifically addresses the conscquence por-tiorì of tlìe lisk equation. The operator shall considerconsequences of a potential failure when prioritìzinginspectiorìs ancl mitigation activities.

'l'he 1J31.8 Code manages risk to pipeline integrity byadjusting design ancl safety factors, and inspection àndmaintenalìce frcquencies, as the potelìtial consequencesof a failu¡e increase. This has been done on an empiricalbasis without quantifying the consequences of a fâilure.

Paragraph 3.2 desclibes how to determine tlìe âreathat is affected by a pipeline failure (potential impâctarea) in order to evaluate the potentiaÌ consequerìces ofsuclì an event. Tlìe areâ impacted is a function of thepipeline diameter and pressure.

3.2 Potentiat lmpact Area

The refined radìus of impact for natu¡âl gas is c¿ìlcu-latecl ûsing tlìe formula

t = 0.6,) . d.tÇ (/ = o.oo31s . d\,[) (1)

whered = outside diameter of the pipeline, in. (mm)p = pipeline segment/s maximum allowable

operating pressure (MAOP), psig (kPa)r' = radius of the impact circle, ft (m)

UXAMPI"ìI1r A 30 ìn. cliameter prpe ra'itlì a mâximum allowableoperâtjng pressure of 1,000 psig lìas  poteÌrtral impâct radius ofapproximâtely 660 ft.

r : o.6e.dli: 0.(r9 (30 i¡.)(1,000 lb/in.'?)r/'?

= 654.6 ft - 660 ft

IIXAMI'I"D 2r A 762 Dìù diameter pipe witlì a maximurn allow-ablc operÂtiig pressure of 6 900 kPa hiìs a poterìtial impact nìdiLìsof approximately 200 m.

f = 0.00315. d!6

= 0.0031s (762 mnr)(6 900 kPa)r/'?

= 199.4 m = 200 nì

Use of tlìis equation slìows that failure of a smallerdìameter, Iower p¡essure pipl]line will affecl a smaller

7

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a¡ca than a larger diameter, higher pressure pipeline.(See GRI-00/0189.)

NOTII: 0.69 is tlìe factor lor rìahìrâl Bas using U.S. Customaryunits and 0.00315 $ tlÌe factor usìng metric ruìits. Ot¡er gâses orrich natural gas shall use dilferent factors.

Eqüâtion (1) is derived from

(úi) property damage(¿) envircnmentaì clâmage

f) effects of unignited gas releases(g) security of gas supply (e.9., impacts resulting from

irìte¡ruptiolì of service)(/r) public conve[ience and necessityli) putcntial h'r 'ccrrnd¿ry failu¡esNote thât the consequences may vary based on the

¡ichness of thc gas trânsported and as ¿r result of howtÌìe gas decompresses. The richer the gas, the moreiûlportant defects and material properties a¡e in model-ing the characteristics of the failure.

4 GAÍHERING, REVIEWING, AND INTEGRATINGDATA

4.1 Generat

This section provides â systematic process for pipelineoperators to collecl and effectively ütilize the data ele-ments necessary for risk assessment. Comprehensivepipeline and facility knowledge is an essential compo-nent of a performance-based integ¡ity manâgement pro-gram. In addition, information orì ope¡âtionâl hislorythe erìvironmenL a¡ound the pipl]line, mitìgation techniques ernployed, and process/procedure reviews is âlsonecessary. Data are a key element in the decision-makingprocess required for program implementation. Whentlìe operator lacks sufficient data or where data qualityis below requìrements, the operatol shall foìlow the prc-scriptive-based processes as shown in NolìmâlìdatoryAppendix A.

Pipelirìe operator procedu¡es/ operation ar'ìd mainte-narrce plans, incìdent informatiorì, and other pipelineoperâtor documents specìfy and require collectìon ofdata that are suitable fo¡ inte8rity/risk assessmelìt. [nte-gration of the datâ elemelìts is essential in order to obtaincomplete and accurate infolmation needed for an integ-rity ûìan¿ìgeDìent program.

4.2 Data Requ¡rements

'I'he operator shall have a comprehensive plan forcolìecting all data sets. The operator must first collectlhe data required to perform a risk assessment (see sec-tion 5). Implementâtion of the ìrìtegrity marìagementprogram will drive tlìe collection and prioritization ofaddilional data elements required to more fully under-stâlìd ând p¡event/mìtigate pipeline th¡eats.

4.2.1 Prescr¡ptive lntegr¡ty Management Programs.Lìmited data sets slÌall be gathered to evaluate eacl-r

threat for prescriplive integrity managemenl programapplicâtions. These data lists a¡e provided ilìNonmandatory Appendix A for each threat ând súmma-rized in Tâble 1. All of the specified data elements shallbe available for eÂch threat in order to perform tlìe risk¿ìssessment. If such data a¡e not available, it shall be

sonic velocity of gâs =discharge coefficientlìne diameterIìeat of combustionth¡eshold heat fluxgas molecular weightlive pressure

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¡ì = gas constant¡ = refined ¡adius of impactT = gas tempelaturc/ = specific heat ratio of gasI = ¡elease rate decay factor

¡, = combustion efficiency fâctor

l,q = emissivity factor

In a pelformance-based program, the operâtor mayconsider alternate models that calculâte impact areasand conside¡ additional factors, such as depth of burial,thât may reduce impact areas. Tlìe operâtor shall countthe numbe¡ of houses and indìviduaÌ units in buildingswitl.tiù the potential impact area. The potential ilnpactarea extends from tlìe center of the first âffected circleto the center of the last affected circle (see Fig.3). ThisIìousirìg unit count carì then be used to help determinetlìe Ìelative consequences of a ¡upture of the pìpelinesegment.

Tl-ìe ranking of these areas is an iù-rportarìt element ofrisk assessment. Determjning the likelihood of failureis the other impo¡tant elemenl <¡f risk assessment (seesections 4 and 5).

3,3 Consequence Factors to Cons¡der

Wlìcn evaluating the consequences of a failure withintlìe impact zone, the ope¡ato¡ shall consicle¡ at leasl thefollowing:

(/r) popuÌâtion densjty(ú) p|oximity of the populâtion to the pipeline

(including consideration of marrmade or natural barriersthat may provide some level of profeclion)

(c) proximìty of populations with limited or impairedmobiÌity (e.9., lìospitais, schools, child-care cenLers,Ìetirement commulìities, p¡isons, recreation areas), par-ticularly in unprotected outside areas

ASME 831,8S-2010

F¡9. 3 Potent¡al lmpact Area

Potent¡al impact area(withln dashed lines)

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assumed thât the particuÌar tlìreat âpplies to the pipelinesegment being evaluated.

4.2,2 Performance-Based lntegrity Management Pro-grams. TIìe¡e is no standârd list of required data ele-ments that âpply to all pipeline systems for.performance-bâsed integrity manâgement programs.Flowever, the operato¡ shall collect, ât â minimum, thosedata elements specified in rhe prescriptive-based pro-gram requiremer'ìts. Tlìe quantity and specific data ele-ments will vary betweerì operators and within a givenpipeline system. fncrcâsilrgly complex risk assessmentmethods applied in performance-basccl integrity man-âSement programs require lnore daLa elements thanthose listed in Nonmandatory Appendix A.

Initially, the focus shall be on collecting the data neces-sary [o evaluate areas of concern and other specific areasof high lisk, The ope¡ator will collect the data ¡equiredto perform system-widc integrity assessments, alrd anyadditional data required for general pipeline and facilityrisk assessments. This data is then integrated into Lheinitial data. The volume and types of data will expandas lhe plan is implemented ove¡ years of operation.

4.3 Data Sources

The data needed for integrity management prog¡amscan be obtained from within tlìe ope¡ating companyand f¡om externaì sources (e.g., industry-wide data).Typically, the documentation containing the requireddata elements is located in design arrd colstruction doc-umentâtion, and current operational alìd mainteùiìncerecords.

1,000 ft1305 m)

300 fr(90 m)

Pipeline

ând to dete¡mine if significânt .lata .teficicncies exist. Ifcleficiencies are found, action to obtain the data can beplanned ancl initiated ¡elative to its importance. Thismay require âdditional inspections ând field data collec-tion efforts.

Existin8 management information system (MIS) orgeographic information system (GlS) databâses and theresults of any prior risk or threat assessments are alsouseful data sources. Significait insight cân also beobtained from subject mdtter experts ¿ìnd those involvedin the risk assessment and integrity management pro-g¡am processes. Root cause analyses of previous failu¡esare a valuable data source. l'hese may reflect âdditionalneeds in personnel trailìing or qualifications.

Valuable dara for integrity management p¡ogramimplementation can also be obtained from externalsources. These may include jurisdictiolal agency reportsând databases that ìnclud(] i1ìformatiorì suclì as soil dâta,demograplìics, and hydroÌogy, as examples. Researchorgalìizatiorìs can provide background olì manypipeline-¡elated ìssues Lrseful for applicatìon in an integ-rity managemenI program. fndustry consortìa ârìd otheroperak)¡s can also be usefuÌ information sources.

The datâ sources listed in Tâble 2 are necessary forintegrity management program initiation. As the integ-rity mânagemcnt prog¡am is dcvelopcd and irnple-mcrìted, âddifional dâta will becomc avaìlable. This wiLlinclucle inspectiorì, examìnation, and evaluation dataobtained from the integrity management prograrn anddatâ developed for the pe¡formance metrics covered insection 9.

A survey of all potential locations that could house 4.4 Data Cottect¡on, Review, and Anãlysisthese records may be required to document wlìat is avail- A plan for coÌlectìng, reviewing, ancl ânalyzing theâble, its form (inch.tding lhe units or referencc system), data shalÌ be created and in place from the conception

9

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ASME 831.85'2010

Table 1 Data Etements for Prescriptive Pipelinelntegr¡ty Program

Tabte 2 Typical Data Sources for Pipelinelntegrity Program

Attribute dätã

of the data collection effort. These processes are neededto verify the quality and consistency of the data. llecordsshall be maintained tlìroughout the process that identifywhe¡e aDd how unsubstanliâted data is used in the¡isk assessment process, so its pote[tial impâct on tlìevariability and âccutacy of âssessment results can bcconside¡ed. Tlris is often refe¡red to as ¡rrclldit0 or i^Ior-mation about the data.

Data resolutiolì and units shall aÌso bc determilìed.Consistency in units is essential for jntegration. Everyeffort should be madc to utilize all of the actual data

Process and instfumentôtion drâwìngs (P&lD)

Pipeline alignr¡ent drawings0rigi.lal Lolslructiol inspeclo' notes/recordsPipeline aerial photogÊphyF¿cility drawings/maps

As-built drawings[¡¿lerial .ertifi.ãtionsSurvey reports/drâwingsSafety related condition reporlgOperator slandards/specifications

lndustry standards/specificationsO&lvl p¡ocedures

Emergency response planslnspection records'fest reporls/records

lncident reportsCompliance recordsDesi gñ/engineering reportsTechnical evaluationsl\¡anufacturer equip ment data

for the pipeline or facility. Generalized i1ìtegrity assump-tions used in place of specific data elements should beavoided.

Another data collection consideration is wlìethe¡ theage of the data invalidales its applicability to the threat.Dâtâ pertâìning to time-dependent threats such âs corro-sion o¡ stress corrosion cracking (SCC) may lìot be rele-vant if ìt was collected many years before the integritymanaBement pÌotram was developed. Stable and time-independent threâts do not have ìmplied time depen-dence, so earlier data is applicable.

The unavailability of identified data elements is nota justification for excÌusion of a threat from tlÌe integritymana8ement program. Depending on the impo¡tanceof the data, additional inspection actiorìs or field dâtacollection efforts may be required.

4.5 Data lntegratíon

Individual data elernents shâll be brought togetherand analyzed in fheir context fo ¡ealìze the full valueof integrity marìagemenL and risk assessment. A majorst¡ength of an effective integrity mana8ement programlies in its ability to merge and utilize multiple dataelemenfs obtained from several sources to provide animprovecl confidence tlìat a specific threat rìay or maynot âpply to a pipeline segment. It can also lead to animproved analysis of overall risk.

Ëor integrity manâgement p¡ogrâm applicatiorìs, oneof the first datâ integration steps inclucles developmentof a common reference system (ar'ìd consistent measure-ment units) that wilì allow daLà elements f¡om va¡ioussources to be combined and accurâtely associâted withcommon pipcline locations. Ëor instânce, in-line

Pipe wall thickrìessDiameterSeam type and ioìnt faclorl\,lanufacturer1\'lanufacturing datel,¡aterial propertiesEquipmenl propenieg

Year of installationBending methodJoining method, process and inspection

resultsDepth oi coverCrossings/casingsPlessure lestField coating methods5oil, backfilllnspection reportsCathodic protection installedCoaling type

Gas q uality

Normal maxir¡um and minimum operatìngptessures

Leak/failure historyCoating conditionCP (cathodic protection) system performancePipe wall temperatureP¡pe inspection reportsOD/lD corrosion mo¡itoringPressure fluctLlationsRegulator/relief performanceEncroachmentsRepâirsVandalismExtemal forces

Pressure teslsln-line ìnspectionsGeometry tooì inspectionsBell hole i¡spectionsCP inspections (ClS)

Coating condit¡on ¡nspections (DCVG)

Audits and reviewç

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i¡ìspectiorì (ILI) data may refe¡ence the distance lraveledalong the irìside of the pipeline (wheel count), whichcan be difficult to directly combine wiflì over-the-linesurveys such as close inlerval survey (CIS) that a¡c refer-enced to engirìeering station Ìocations.

läble 1 describes data elements that can be evaÌuateclin a structu¡ed manne¡ to determine if â pârficulâ¡ threatis applicable to the âreâ of corìceûì or the segment beingconsidered. Initially, tlììs can be accomplislred withoutthe benefit of ilìspectìon datâ and may only inclucle thepìpe attribute alìd constructiorì data elements shown inTable 1. As othe¡ information such as inspection datâbecomes available, an additional inlegration step can beperfo¡med to confirm the p¡evious irlference concerningLIìe validity of the presurned threat. Such data integra-tion is âlso very effective fo¡ assessing the need andtype of mitigation measures to bc used.

Data integration can also be accomplished manuallyor graplìically, An example of manuâÌ integration is thesuperimposing of scaled potential impact ârea circlcs(see section 3) on pipeline aerial photograplìy to dcfer-mine the extent of the potential iùÌpact area. Graphicalirìtegration can be accomplished by loading risk-relatccldatâ eÌements into alì MIS/G[S systern ancl graphicallyoverlaying them to establish tlìe location of a specifìcthreat. Depending on tlìe data resolution used, this couÌdbe applied to Ìocal a¡eas or larger segments.Mo¡e-specific data integratìon software is also availabletlìât facilitates use irì coñbined analyses. The benefitsof clatâ integÌation cân be ilÌustrated by the followinghypothetical examples:

EXAMPL,ES:(1) ln reviewirg Il.,l data/ arì operator suspccts meclìanicaìdam-

â8e nì the top quadr;ùìt of a pipeline in ¡ cultivated fielci. It is Âlsoknow¡ that the farmer hâs bec¡ plowjng iÌl t1ìis area and thattlìe depth of cover may be rc.luccd. llâch of these fâcts takerìindividuâlly providessome indication of possible mechallical dam-age, bLrt as a group ilìe resült is more definìtive.

12) Arì operator suspects that â possible cor¡osrcn problcmexistson a large'diame ter pipelirìe loc;rtecì in a populâted area. Howcveta CIS iììdicates good catlrodic protectrorì coverage jn the ârea.

^direct c rferìt voltage grâdient (DCVC) coating condition inspec,tiùì js performêd ¡ì)ìd r€veals tlìat tlìe welds \,reÌe tape-coated ânclare in poor condition. Tlìe CIS r€sults did not irdicate a potentiaìinte8rrty issue, tlut dâtâ irtegrâtion preventcd possjìrly incorrect

5 RISK ASSESSMENT

5.1 lntroduct¡on

Risk assessments shall be conducted fo¡ pipelines andrelated facìlitìes. llisk assessments are required for bothprcscriptive- ând performance based inteBrity manage-ment programs.

For prescriptive-bâsed programs, risk âssessments ¿ìre

pri¡narily utilized to priolitize irìtcg¡ity managementplan âctivities. TIÌey help to orgarìize dâfa arìd i¡forma-tion to make decisions.

For performance-based programs, risk assessmenlsserve the following purposesr

(f¿) to organize data a¡d information to help opelatorsprioritize and plan activilies

(¿r) to dete¡rnìne wlìiclì ì1ìspectiorì, prevenLiotì,and/or mitigatìolì activifies will be perfo¡med andwhen

5.2 Def¡n¡tion

Tlìe operalor shall folìow section 5 in its entirety toconduct a performance-based inteB¡ity malìagernentp¡og¡âm. A prescriptive-based integrity managementplogram shall be conducted using the requirementsiclentifiecl in this section ând irì NonmandatoryAppendix .4.

Ilisk is typicâlly described as the procluct of two pri-mâry factors: the failure likelihood (or p¡obabiÌity) tlÌatsome adverse event will occur and the resulting conse-quences of Llìat event. One method of describing risk is

Riski = P¡ x C¡ for a single threat9

Risk = ! (P¡ x C,) for thrcat categories 1 to 9

rotut sogil'l.'t .irt=Pr x Cr + P2 x C2+... + P9 x Ce

whereC = failure consequenceP = failu¡e Ìikelihood

1to9 = failure th¡eât category (see para. 2.2)

The risk analysis metlìod used shall add¡ess alì ninetlìreât categories or each of the indìvidual 21 threats totlìe pipeline system. Risk consequerces typically con-sider components such as the potential impâct of lheevent on iÍìdividuals, property, business, and the envi-ronment, as shown in section 3.

5.3 Risk Assessment Obiect¡ves

For application to pipelines and fâciìities, risk assess-ment has the followirìg objectives:

(d) prìoritizâfion of pipelìnes/segmenfs for schedr.rl-ing integrity assessmer'ìts and mitigatilìg action

(¿,) assessment of the benefits clerivecl from mitigatingactiôn

l.) dctcrmin¡tion ol lhc mosl cffcctive mitigàti()nrneasures for the identified threats

(rl) assessmen[ of the integrity impact f¡om modifiedinspection i1ìtervals

(e) assessment of the use of or need for âlternativeinspectiorì rnethodologies

f) mo¡e cffective resou¡ce allocationRisk assessment provides a measure that evaluates

both the potentìâì impact of different ircident types arìdthe likelihood thât such events may occur. l-laving suclìa measure supports the integrity management pÌocessby facilitating rationâl and consistent decisions. Risk

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results are uscd to iderìtify locâtions for integrity assess-ments and resulting mitigative âction. Examin;ng bothprimary risk factols (likelihood and consequences)avoids focusing soÌely otì the most visible or frequentlyoccurring p¡oblems while igno¡ing potential events thatcould cause significantly greater damage. Converseìy,tlìe process also avoids focusìng on Ìess likely cata-st¡oplìic events while overlooking more likely scenarios.

5.4 oevetop¡ng a Risk Assessment Approach

As an integÌal part of âny pipeline integrity manage-¡¡ent program, an effectìve risk assessment process shaÌlprovide risk estirÌlâtes to facilitate decision-making.When propelly implemented, risk assessment methodscan be very powerful analytic metlìods, using a vârietyof inputs, that provide atì improved undetstanding ofthe natLre ând loc¿ìtions of risks along a pipeÌine orwithin a facility.

Risk assessment methods alone shouÌd not be com-pletely relied upon to establish risk estimates o¡ toaddress or mitigate known risks. Risk assessment meth-ods slrouÌd be used in colìjunction with knowledgeable,experienced persolìnel (subject matter experts and peo-ple familia¡ with the facilities) that regularly review thedata input, âssumptiorìs, ând ¡esults of the risk assess-ments. Such experience-based reviews should validâte¡isk assessment output with otlÌer relevant factors notincluded in the process, the impact of assumptions, orthe potential risk variability causecl by lì'tissirìg or esti-mâted data. Ihese processes and tlìeir results shall bedocumentecl in the ilìtegrity manâgemelìt plân.

An inteBral part of tlìe risk assessment procetis is theincorporation of additional data eìements or changes tofacility data.'Io ensure regular updâtes, the operato¡slìall incorporate lhe risk assessment process itìtoexisting field reporting, engineering, and facilìty map-ping proccsses and incorporate additional processes asrequired (see section 11).

5.5 Risk Assessment Approaches

(n) ln order to organize integrity assessments for pipe-line segments of concern, a risk priorily shall be estab-lislìed. This risk vaìue is composed of a numbe¡¡eflecfing the overâlI Iikelihood of faiìure and a numberreflecfing the conseqlrences. The risk analysis can befairly simple with values ranging from 1 to 3 (to reflecthigh, medium, ancl low lìkclihood and consequences)or can l¡e more complex and involve a lâtger rânge toprovide greater diffe¡entiation between pipeline seg-ments. Multiplying the relative likelihoocl and corìse-quence numbers togetlìer provides tlìe operatol.with arelative risk for the segment and a relative prio¡ity forits assessment.

(¿r) An operâtor shall utilize one o¡ ¡nor.e of the folÌow-jiìg risk assessment appro¿ìches consistent witlì tlìeobjectives of the integ¡ity mânagement program. Thcse

approaches are listed in a hierarchy of increasing com-plexit, soplìistication, ancl data requi¡ements. '[ heserisk assessme¡ìt approaches are subject mattcr experts,reÌative assessments,scenario assessments, alìd probabi-listic assessments. The following paragraphs describerisk assessment methods for the four listed approaches:

(1) Subjec! Mattet Ê.xpetts (SMËs). SMEs from theoperating compârìy or consultants, combined with infor-mation obtaincd from technical liteÌature, cân be usedto provide a relative lìumeric vâluc describing the likeli-hood of failure for eaclì threat arìd thc resulting conse-quences. The SMEs are ùtilized by the operator toanalyze each pipelinc segmerìt, assigr'ì relative likelihoodand consequence vâlues, ând calculâte the relative ¡isk.

(2) l<elntiae Assessment Models. This type of assess-ment builds on pipeline-specific expe¡ience and moreextensive data, and includes the development of riskmodels addressing the known threâts thât ììave histori-câlly impact(rd pipeline operations. Such ¡elative ordatâ-based methods use models that identify ând quan-titatively wcigh tlìe môjo¡ threats and consequences rele-vant to pâst pipeline operations. I'hese approaches areconsiclcred relative risk models, since the risk ¡esrÌlts arecompâred with results flenerated from the same model.They provicìe a risk ranking for the integrity manâge-ment clecisior-r p¡ocess. These models utilize âlgorithmsweiglìing the major threâts and consequences, and pro-vide sufficienl data to meaningfully assess them. Rela-tive âfìsessment modeÌs arc more complex arìd requiremore specific pipeline system datâ tlìân subject matte¡expert-bâsed risk assessment approaches. The relativerisk assessment approach, the modeÌ, and the resultsobtairìed shall be documented in the integrity manage-ment pro8ram.

(3) Scetnria-Bnsecl Morl¿ls. I'his risk assessmentapploach creates models tlìat gene¡ate â description ofan event or series of events leading to a Ìcvel of ¡isk,and includes both the likelihood and consequences fromsuclì events. This method usually includes constructionof event trees, decisior'ì trees, and fault trees. From theseconstructs, risk values a¡e determined.

(4) I\'obnbilistic Mo¡l¿ls. This approach is the mostcompÌex and demanding with respect to data requite-ments. The rìsk output is provided in a format that iscompared to acceptâble risk probâbilìties established bythe operator, ratlìer than using a comparative basis.

It is the operator's responsibility to apply the level ofintegrity/risk analysis methods llìat meets the needsof the operator's integrity managemenI progrâm. MorcLhan one type of model may be used throughout anoperator's system. A tlìo¡ouglì understânding of thestrelìgths and Iimitations ofeach risk assessmcnt methodis necessâry before â long-term strategy is adopted.

(c) All risk assessment approaches described abovehave the following comûlon comporìents:

(i) they identify potentiâl events or conditiorìs thatcouìd threatcn system integrity

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(2) tlìey evalLrate likelihood of failure and conse-qucnces

(3) they permit risk ranking arìd iderìtification ofspecific th¡eats that primarily influelce or drivc tlìe ¡isk

(4) they lead to the identificatiorì of integ¡ity assess-ment and/or mitigation options

(5) they provide for â dâtâ feedback loopmeclìanism

(6) they plovìde structure and contir'ìuous updatìnflfor risk reâssessmcnts

Some risk assessmelìt âpproâches colìsider the likeli-hood and consequences of damage, but they do notconsider whetlìer failure occurs as a leak or rupture.Ruptures hâve more potential for damage than leaks.Consequently, wherì a risk assessment approach doesnot consicler wlìetlìer a failure may occür as a leak orrupture, ¿ì worst-câse assumption of rupture shall bemâde.

5.ó R¡sk Analys¡s

5.6.1 R¡sk Analys¡s for Prescr¡pt¡ve lntegrity Manage-ment Ptogfams. The risk analyses developed for a pre-scriptive integrity management program are used toprioritize tlÌe pipeline segmelìt integrity assessments.Once tlìe integrity of a segment is estâblishecl, the rein-spection intervâl is specified in Table 3. The risk anaÌysesfor prescriptive integrity managemenL progrâms usemirìimâl data sets. Ihey cannot be used to increâse thereinspection intervaìs.

Wlìcn the operator follows the presc¡ìptive reir'ìspec-tion inte¡vals, the mo¡e simpljstic risk assessmentapproaches provicled in para. 5,5 are considereclappropriale.

5.6.2 Risk Analys¡s for PeJformance-Based lntegrityManagement Pfogfams. Perfo¡mânce-based integritymarìâgement programs shall prioritize initiâl integ¡ityassessments utilizilìg any of the methods desc¡ibed irrpara.5.5.

Risk analyses for pcrformânce-based integrity man-âgement programs may also be usecl as a basis for estab-Iishing inspection ilìle¡vals. Sttch risk analyses will¡equi¡e more data elemenls than required inNonmandatory Appendix A ¡ncl more detailed analy-ses. The results of these analyses may âìso be used toevaluate alteúìative mitigation and prevention methoclsand tlìeir timing,

An initial strategy for arì operator with minimal expe-rience using structu¡ed risk analysis methods mayinclude âdopti\g a more simple approarch for tlìe sho¡tLerm, such as knowledge-based or a screening relativelisk model. As additional dafâ alìd cxperience are

Sairìed, tlì(] ope¡atorcan transition to à more comprehen-sive ñethod.

5,7 Character¡stics of an Effect¡ve R¡sk AssessmentApproach

Considerilrg the objectives summarized in para. 5.3,a r'ìumber of general characteristics exist lhat wiÌl con-t¡ibute to the overall effectiveness of a risk assessmerìtfor eitlìe¡ presc¡iptive or pelfolmance-based ilìtegritymanagement programs. These characteristics shalli1ìclude tlìe following:

(n) Afh'ih fes. Any risk assessment approach shallcontain a definecl logic and be structured to provicìe a

complete, accuraLe, alìd objective analysis of risk. Somerisk methocls require a more rigid strucfure (and consid-erably more input data). Knowledge-based methods areless rigolous kr apply and require more input fromsubject-matter experts. They shall all follow an cstab-Iished structure and consider the nine categories of pipe-line threats and consequences.

(b) ResoLLrces. Adequâte personnel iìnd time shâll beâìlotted to permit implementation of the selecteclapproach and future consider¡tions.

(c) Operotittg/Mitigatiaú Hislotll. Any risk assessmentshall conside¡ the frequency and .onsequences of pastevents. Preferably, this slìould include the subject pipe-Iine system or a similar system, but othe¡ industry clatacan be used where sufficient data is iÌìitially not avail-âble. In addìtiorì, tlìe ¡isk âssessment method sÌìâllaccount fo¡ âny cor¡ective or risk miti8ation action tlìathas occu¡red prcviousÌy.

(cl) Prcdictiae Capnl:i/ify. To be effective, a risk assess-ment method should be able to identify pipeline integ-rity blìreats previously nol colìsidered. It shall be able tomake use of (or irìtegrate) the data from various pipelìneinspecfions to provide lisk estimates llìat llìay resultfrom threats lhat have not been previousÌy recognizedas polential problem areas. Another valuabÌe approachìs the use of trending, whcre the ¡esults of inspections,examinations, and evaluations are collected over timein order to predict future conditions.

(c) Risk Cotficlcnce. Any data applied in a risk assess-

ment process shall be ve¡ified and checked for accuracy(see section 12). Inaccurate data will produce a less accu-rate ¡isk re$ult. For missing or questionable dâta, theopeÍato¡ shoulcl determine and document tÌìe defaultvalues lhat will be used ând wlìy they we¡e chosen. Theoperator should choose defâLÌÌt vâlues llìat conserva-tively reflect the values of otÌre¡ similar segmenls on thepipeline or in tlìe operator's system. These colservativevalues may elevâte the risk of the pipeline and encou¡âgeâctiolì to obtailì accurate data. As the data are obtained,lhe uncerlainties will be elimir'ìated and the rcsultantrisk values may be reduced.

(f) Feedbock. One of tÌre most important steps in aneffective risk analysis is feedback. Any risk âssessmentmetl¡od shall not be considered as â stâtic tool, but as

a process of continuo!¡s improvement. Hffective feed-back is ârì essential process component in contintou!ì

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ASME 831.8S"2010

Table 3 lntegr¡ty Assessment lntervals:Time-Dependent Threats, lnternaI and External Corrosion, Prescr¡ptive lntegrity Management Plan

¡nspect¡on Techn¡quelnterval, yr

tNote (1)lOpetating Pressure

Above 50% of SMYS

OpeÉting PressüreAbove 30% But Not Operating Pressure Not

Exceedìng 50% of SMYS Exceedìng 30% of SMYS

Hydro5tatic testing IP to 1.?5 times I!4AOP

INote (2)l

ïP to 1.39 times MAOP

[Note (2)]

Not allowed

Not allowed

Pf above 1.2 5 times]MAoP [Note (3)]

Pf above 1.19 timesrMAoP lNote (3)]

Not allo!^/ed

Not allowed

Sample of indicatìonsexamined [Noie (4)]

All indications examined

Not allowedNot allowed

lP to 1,39 tlr¡es I¡AOP

INore (2)lfP to 1,65 times À440P

[Note (2)]

TP to 2.00 times MAoP

lNore (2)l

Not allowed

Pf above 1.39 tir¡esIMAOP [Nole (3)]

P¡ ¿bove 1.65 timesMAoP [Note (])l

P/ above 2.00 iimesIIAOP [Note (3)]

Not allowed

Sample of rndicâtionsexamined INote (4)l

Sãmple of indicationsexamined lNote (4)l

Aìì indicatio¡s examinedNot allowed

TP to 1.65 times I,IAOP

lNote (2)lTP to 2.20 times [,\AOP

INote (2)l

TP to 2.75 times MAOP

lNote (2)l

TP to 3.33 times IMAOP

lNore (2)l

Pf above 1.6 5 tìmesIMAoP lNote (3)]

Pf above 2.20 timesMA0P [Note (3)ì

Pr above 2.75 timesNIAOP {Note (3)l

Pf above 3.31 tir¡esIVAoP lNote (3)]

Sample of indicationsexanrined [Note (4)]

Sample of indìcatìonsexamined INote (4)l

All indications exäminedAll indications exämined

ln-line inspection

Direct ãssessmenl

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NOIES:(1) lnleruâls are maxìmum and may be less, depending on repairs made and prevention activit¡es instituted. ln addition, certain lhreâts

c¿n be extremely agg¡essive and may significantly reduce the interval belween inspectlons. Occurrence of a time-dependent failurerequires immediate reassessment of the intelval.

(2) lP is test pressure.(3) P¡ is predicted failure pressufe as determined from ASIME B31G or equivalent.(4) tor the Direct Assessment Process, the intervals ior direct examìnatÌon of indications are contalned within the process. These inlervals

provide ior sampling of indications based on their severity and the results of previous exami¡ations. lJnless all indications are exam-ined and repaired, the maximuùì interval iof reinspection is 5 yr for pipe operâting above 50% SI,IYS ãnd 10 yr for p]pe operating upto but not exceeding 50o/o of sMYS.

¡isk model validation. hr addition, the modcl shall beadaptable and changeable to accommodate new thteats.

(g) DocuDtctltatíoa. The risk assessment process slìallbe thoroughly and completely rlocumented, to prþvidethe background and technical justification for the metlÌ-ods and procedures used and their impact on decisionsbased on tìre risk estimates. I-ike the risk process itscl{,such a documclìt should be periodically updated asmodifications or risk process changes are incorporated.

(h) "WhaL ìf' Deterninntions. An effective ¡isk modelshould contain the structure rìecessâ¡y to perform "whatif" calculâtions. This structure ca¡ì provide estimates ofthc effects of charnges oveÌ time and the risk recluctiolìbcnefit f¡om maintenânce oÌ remedial actiorìs.

(i) Weighlittg Fnctots. l\ll threats and consequencescontained in a relative risk assessment process sìroulclnot have the same level of i1ìflucrìce on the risk estimate.

Iherefore, a structured set of weighting facto¡s shall beincluded that indicate the value of each risk assessmentcomponent, including both failure probability and con-sequences. Such factors can be l:ased on operationâlexperience, the opinions of subject malter experts, orindust¡y experi(]ncc.

(j) Sftuclne. Any risk asscasment process shall pro-vidc, as a mirìimum, the ability k) co|npâre âùd ranktlìe risk results to support the irìtegrity DÌanagementprogram's decision process. [t should aÌso provide forseveral types of datâ evaluation and comparisons, esfab-Iishing which particulal threats or factors have tlìe mostinfluence on the result. The risk assessment process shaìlbe structured, documented, and verjfiable.

(k) Segtfieúfntiatl. An effective risk âssessment proccssshall incorporate sufficient resolution of pipeline seg-ment size k) anaÌyze clatâ as it exists âlong tlìe pipeljne.

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St.rch analysis will facilitate location of local higlr,riskareâs that may need immediate attetìtion. For risk assess-mcnt purposes, setmetìl lengtÌts can rânge from unitsof feet to miles (m to km), depending on tìre pipeÌineâttributes, its environment, and otlìer dâta.

Another requi¡emclìt of the model jnvolves the abilityto update the rìsk model Lo ¿ìccount for mitigation orotlìer action that changes the dsk in a particular length.This can bc illustrated by assuming tlìat two acljâcentmile-Iorrg (1.6 km-long) segments have been identified.Suppose a pipe replacement is completed f¡oln the mid-poirìt of one segment to sone poìnt within the other lnorder k) âccount for tlìe rìsk reduction, tlìe pipelinelength comprising tlìese two segments now becomesfour ¡isk analysis segmeùts. Ihis is câlled r/l/rdû¡icseg rcntotiol1.

5.8 Risk Estimates Us¡ng Assessment Methods

A descriptiorì of various details ând complexities asso-ciated witlì different risk assessment processes Iìâs beenp¡ovided in pa¡a. 5.5. Operatoß that have not previouslyinitiated a iormal ¡isk assessment process may firìd aninitiaÌ screening to be be¡reficial. The ¡esults of lhisscrcening can be inplemented withìn â short time frameand focus given lo tlÌe most important areas. A screeningrisk assessment may not include the enti¡e pipeline sys-tem, but be limited to âreâs with a history of problemso¡ whe¡e failure could ¡esult in fhe most severe conse-quences, such as areas of concern. Risk assessment alìdclata collectìon may then be focusecl on the most likelythreats without requi¡ing excessive detail. A scrceùilrgrisk assessment suitable fol tlìis âpproach can includesubject matLer experts or simple relâtive risk models asdescribed in pata. 5.5. A group of subject-matter experts¡epresenting pipelìne operatioûs, engineering, andothers knowledgeable of threats thât mây exist ìs assem-bled to focus on the potential tlìreats and risk reductionmeasures tlìat would be effective irì the ìntegrity mâtì-agement p¡ogram.

Application of any type of risk allalysis methoclologyshaÌl be conside¡ed as ân clemenl of continrcus p¡ocessand lìot a one-time evenL. A specified period definedby tlìe operator shall be esrablished fo¡ a system-widerisk reevaluation, butshâll rìot exceed the required maxi-mum ìr'ìterval in Table 3. Segments colìtairìing indica-tiorls thâl are scheduled for exâmination or that ar(3 tobc monilored must be assessed witlìin time intervalsthat will maintain system integrity. The frequency of thesystem-wide ¡eevaluation must be ât least annuâlly, butmay be mote freqrLent, based on the frequency arrdimportance of clata modifications. Such â ¡eevalualionshoulcl include all pìpeÌines or segments included inthe risk analysis process, to ensute thât the mosl recentinspection resuÌts and information are reflected itì thercovJluâtiorì arrd .rny risk compalis('ns iìre on ânequal basis.

The processes and risk assessment methods used shallbe periodically reviewed to ensure they continue to yieldrelevant, accurate results consistenL with tlìe objectivesof the ope¡ator's overall integrity management profÌram.Adjustments and inÌprovements to the risk âssessmentmethocts wilL be necessary as more complete arìd accu-râte informâtion concerning pipeline system att¡ibutesand history becomes available. These adjustments shallrequire a reanalysis of the pipeline segments includedilì the integrity mânagcment program, lo ensute thatequivalent assessments or comparisons are macle.

5.9 Data Collection for R¡sk Assessment

Data coÌlection issueshavebeen discussed ìn section 4.

When analyzing lhe ¡esults of the risk assessmerìts, theoperator may find lhat additional data is requircd. Itera-tion of the risk assessment process may be ¡equired toimprove the clarity of the results, as well as confi¡m thereasonableness of the results.

Determining the ¡isk of pqtential threats will ¡esultin specificâtion of the minimum data set required forimplementation of the selectecl risk process. IfsignificantdaLa elements are not avaiÌable, modifications of tl'reproposed rnodel may be required after carefullyreviewing the impact of missing dâtâ ând taking intoaccount the potential effect of uncertainties created byusing required estimated values. An alte¡rìâtive couldbc to use related data elements in order to make anirìferelìtial threat estimate.

5.10 Prior¡t¡zat¡on for Prescr¡ptive-Based andPerformance-Based lntegrity ManagementPrograms

A first step in prioritization usually involves sortingeâch pârtìcula¡ segmenl's risk results in decreasing orderof overall risk. Sìmilar sortilìg can aÌso be achieved bysepamtely considerirìg decreasing consequences ot fail-urc probability levels. The lìighest risk level segmentshall be assigned a higher priority when deciding whereto implement integrity âssessment and/or mitigationactions. Also, the operator should assess risk facto¡s thatcause higher ¡isk levels for pa¡ticular segments. Tlìcsefactors can be applied to help select, p¡ioritize, andschedule locations for inspection actions such as hydro-static testing, inline inspection, or direct âssessment.For example, a pipeline segment may rânk extremelyhigh for a singÌe threat, but rank much lower for theâggregate of thrcats compared to all othe¡ pipeline seg-ments. Timely resoìution of lhe sirrgìe highest threatsegment ûìay be more appropriate tlìan resolutìol ofthe highest agg¡egate threat segment.

For initiaÌ efforts and screening purposes, risk resultscould be evaluated simply on a "high-medium-low"basis or as a mrmerical vaÌue. When setments beingcompârcd lìave similar risk values, the failure probabil-ity alìd conscqueiìces should be considered separately.This rnay lcad to rhe highest consequence segment being

15

Copyrighf O 2010 by the ,Americân Society ofMechanical EDgineers. fSNo reprcductrorì rnay be made oflhis nraterial wrthout written consenl ofASME. 'le)l

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given a l.righer prio¡ily. lìactors including line availabilityand system tlì¡oughput requirements can also influencep¡ioritization.

The integrity plan shall also provide for the eliminâ-tion of any specific lhrcat from tlìe risk assessment. Fora prescriptive irìtegrity mâr'ìagement program, the mini-mum data requircd and the ctiteria for risk assessmentin order to eliminate a tlìreat from furtlìer corìside¡ationare specified in Nonmandâtory Appendix A.Pe¡formance-basecl integrity ñanagement programsthat use more comprehensive alralysis methods shouldconsider the folÌowirìg irì o¡der to exclude a threat in asegmentl

(a) therc is no history of a threat impacting the partic-ular segment or pipeìine system

(ll) tlìc threat is not supported by applicable industrydata or expeÌience

(.) the threat is not implied by related datâ elements(d) tlìe th¡eat is not supported by like/sirnilar

analyses(¿) tlìe threat is not applicable to system o¡ segment

operating conditionsMorc specificaìly, para. (c) considers the application

of ¡elated data elements to provide an indication of athreat's p¡l]seiìce when otlìer data elements may lìotbe available. As an example, for the external corrosiolìtlìreat, multiple datâ eÌements such as soiltype/noìsture level, CP data, CIS data, CP cu¡¡er'ìtdemand, and coating condition can âÌl be used, ol if oneis unavailabÌe â súbset may be sufficìent to determinewhether the thre¿ìt shall be considered for thât scgment.I'aragraph (d) considers the evaluation of pipeline seg-ments wifh known and similar conditions that can bcused as a basis for evaluatirìg tlìc existence of threatson pipelines with rìissirìg data. Parâgrâph (e) aÌlowsfor the fact that some pipeline systems or segments a¡cnot vulnerable to some tlìreats. For instance, based onindustry resea¡ch and experience, pipelines operatingat low st¡ess levels do not develop SCC-related failures.

The unavailability of identified data elements is rìota justification for exclusion of a threât from lhe integritymanâgement program. Depending on the importanceof the datâ, additional inspection actions or fielct datacollection effoÌts may be required. hì additio¡t, a threatca¡not be excluded without consideration given to thelikelihood of interaction by other threats. For ir'ìstance,cathodic p¡otection shielcling in rocky terr¿ìin whe¡eimpressed currerìt may not p¡event corrosiolì in areasof damaged coating must be considered.

When corìside¡ing threat exclusion, a cautionÂry lìoteapplìes to threals classified as time-dependent.Although such an event mây rìoL lìave occur¡ecl in anygiven pipeìine segment, system, or facility, the fact thatthe tlìreât is collsidered time-dependent slìould requirevery stÌorìg justificatiolì for its exclusion. Some threâts,

such âs irìLl]rnal corrosion and SCC, may not be immedi-ately cvident and cân become a significânt threât evenaftcr exterìded operating periods.

5.11 lntegr¡ty Assessment and Mit¡gat¡on

The process begins with examining tlìe nature of themost significant risks. The risk drivers for each high-¡isk segmerìt should be considered in determining flìcmost effective integrity assessment and/or mitigâtior'ìoptior'ì. Section 6 discusses integrity assessment ând sec-tion 7 discusses optiors that are commonly used to ûliti-Bâte threâts. A recalcuÌation of each segment's risk âfterinteg¡ity assessment arrd /or mitigation acfiolìs isrequired to ensu¡e that the segmcnt's ilrte¡lrity can bemaintained to the next inspectiorì interyal.

It is necessa¡y to consider a variety of options or com-binations of integrity âssessments and mitigation actionsthat directly address the primary threat(s). It is alsoprudent to consider the possibility of using new technol-ogies that cân provide a mole effective or comprehensiverisk mitigation approach.

5.12 Val¡dat¡on

Validation of risk anaìysis lesults is one of the mostimportant steps in any assessment process. Thìs shaÌlbe done lo ensule that the metlìods used have producedresults that are usable and are consisLent witlì the opera-tor's and irìdustry's experience. A reassessment of andrnoctificatir¡n to the risk assessment process shall berequired if, as a result of maintenance o¡ other activities,areas are found that are i¡accurately reprcsented by thelisk assessment process. A risk validation process slìallbe identified and documented in the irìtegrity manâgc-ment Progrâm.

Risk ¡esult validations can l¡e successfully performcdby conclucting inspections, examinations, and evÂlua-tions at locations that âre indicâted as either high riskor low risk, to clete¡mine if thc methocls a)e correctlycharacterizir-r8 the risks. Vâlidâtion can be achieved byconsidering another location's information regardingtlìe condilion of a pipeline segment and the conditiondetermined during maintenânce âction orprior lemedialefforts. A speciaÌ risk assessment performed usingklìowù data prior to the maintenance activity can indi-cate ìf mcâningful results are bejng generatecl.

6 INTEGRITY ASSESSMENT

ó.1 General

llâsed on the priorities determined by risk âssessment,tlì(: ope¡âtor shaÌl conducI integrity assessments usiltgthe appropriatc integ¡ity assessment methods. Theintegrity âssessment methods that catì be used are in-line irNpection, pressu¡e tcstilg, direct assessment, orother mellìodologies provicled ìr'ì para. 6.5.l'he integrityassessment metlìod is basecl on the threats tô which the

Copyright O 2010 by the At¡edcan Soclety olMechanicat Engineers lt!LæNo rnay be made ofthis matcrial wilhout wriltcn consent ol'ASME

asME Bi1.8S-2010

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segment is susceptible. More tlìan one method and/ortool may be required to âddress all tlìe threats in a pipe-line segment. Conversely, inspection using any of theintegrity assessment mêtlìods rì'ìay not be the appro-priate action for the operator to take fo¡ ce¡tain threats.Other actions, such as prevention, lnây provide betterintegrìty malìagement results.

Section 2 provides a listirìg of threats by thrce groups:fime-dependent, stable, and time-iÌìdepelìdent. Time-dependent thleats can typically be addresscd by utiliz-ing any olìe of tlÌe ilìtegrity assessûrelìt metlìods dis-cussed in this section. Stâble tlìreats, such as dcfectsthat occulred duling manufacturìrìg, ca1ì fypìcâlly be¿rdd¡essed by pressure testing, while constluctiolì ândequipment threats carr typically be addressed by exami-[âtion ând evaluation of the specific piece ofequipment,component, or pipe joirìt. Random threats typically can-not be adclressed through use of any of tlìe integrityassessment methods discussed in this sectiorì, but aresubject to tlìe prevention measures discussed insection 7.

Use of a pârticulâr integrity assessment method mayfind indications of fhreats other than tlìose that theâssessment was intended to addrcss. For example, thethird-party dâmage threat is usually bcst addressed byimplementation of prevention activities; however, an in-line inspection tool may indicate a dent in the top half oftlìe pipe. Examination of the dent may be an approp¡iâteactiorì in order to determine if the pipe was damageddue to tlìird-party activity.

ftis important to note thatsome of the integ¡ity âssess-me1ìt rnethods discussed in section 6 only provide indi-catiorìs of defects. Exâmination using visual irìspectionand a variety of nondestructive examination (NDE) tech-liques are rcquired, followed by evaluàtion of theseinspection results in order to characterize the defect. Tlìeoperator may clìoose to go directly to examination andevaluation for tlìe erìtire length of the pipeìine segmentbeing assessed, in lieu of conducting inspections. fìorexample, the operâtor may wish to conduct visual exam-ination of aboveground piping for the external corrosiontlìreat, Since the pipe is acccssible for this technique andcxternal conosion can be readily evaluated, performinginline inspection is not neccssâry.

6.2 P¡petine ln-L¡ne lnspect¡on

LÌ-line irìspection (ll,l) is an integrity assessmentmelhod used fo locâ[c ând preliminarily characterizeilìdications, suclì as rnctal loss or deformation, in a pipe-line. 'I lìe effectìvelìcss of the ILI tool used depends onthe conditiorì of the specific pipeline section to beinspected and how well the Lool lnatches thc require-ments set by tlÌe inspectior-r objectives. API Starìdard11,63, I tl-Li11e [¡lspectian S,:jstents Qual ificatiort, provrdesadditional guidance on pipelÌrre in-line inspection. Tlìefollowing paragraphs discuss the use of ILI tools forcertâin threâts.

ó.2.1 Metat toss Toots for the lnternal and ExternalCorros¡on Threat. For these threats, the following toolscanbe used. Thei¡ effectiveness is limited by the technol-ogy tlìe tool employs.

(a) Mngnetic FIux Leakoge, Stnúdiftl l<esolulioll 'lbol.'Ihis is better suitl]d for detcctior'ì ol melal loss than forsizing. Sizing accuracy is limited by sensor size. It issensitive to cerlain metallurgical defects, sLlch as scabsand slivers. It is not reliable for detectiorì or sizing ofmost defects other thân metal loss, and not relial¡le fordetection or sizilrg of axially alignecl metal-loss defects.Higll inspection speeds degrade sizinB ¡ccuracy.

(b) Mngnetic FIux Leaknge, Higll l?.esolLttioll 7bol. Thisprovicrles better sizing âccuracy tlìan standard resolutiontools. Sizing accuracy is best for geometricâÌly simpledefect shapes. Sizing âccuracy degrades where pits arepresent or defect geometry becomes complex. I'here issome ability to detect defects otheÌ tlìalì metal loss, butability vâries witlì defect geometries and clìaracteristics.It is not genc¡ally reliable for axiâlÌy aligned defects.Higlì irìspcctior'ì speeds degrade sizing ¡ccurâcy.

(c) Ullrnsottic Cottptcssiott Wnoe TooÌ. This usuallyrequires a liquid couplant. It provicrles no detection orsizing capability wlìere return signals are lost, whicl-lcan occur indefects with rapidly changing profiles, somebends, and wlìen a defect is shielded by a laminatìorì.It is sensitive to debris arìcl deposits on the inside pipewâll. High speeds degradc axial sìzir'ìg resolution.

(tl) Ultrnsonrc Sllenr Wnue Tool. This ¡equires a liquidcouplant or a wheel-couplecl systern. Sizing accuracy islimited by the numl¡er of sensors and the complexity oftlìe defect. Sizing accuracy is degraded by tlìe p¡eser'ìce

of incÌusions and irnpu¡ities in the pipe wall. Highspceds degrade sìzilìg resolutiolì.

k) Tt nnst¡ersc FlLtx Tool. This is mo¡e sensitive to axi-ally aligned metal-loss defects than standard ancì higlìresolution MFL tools, It may also be sensitive to otlìe¡axially aligned defects. It is less sensitive than standardand high resolution MFL tools to circumferentiâllyâligncd defecfs.It generally provides lcss sizing accuracythan high resolution MFL tools for most defect geome-tries. High speeds can degrade sizìrìg âccuracy.

6.2.2 Clack Detect¡on Tools for the stress Corros¡onCrack¡ng Threat, Èor this threat, tlìe following tools carìbe used. Their effectiveness is limited by the technologythe tool employs.

(n) Ultrnsonic Slte¡r W¡ae Too/. "l'his requires a liqLrìdcouplant or a wheel couplecl system. Sizing accurâcy isIimited by the numbe¡ of senso¡s and the complexity ofthe crack colony. Sizing accuracy is degradecl by thepresence ol inclusions and impurities in the pipe wall.High irspection speeds degrade sizing accuracy aldresolution.

(b) Trnusaetse F/¡rx T0o/. Tlìis is able to detect someaxially aligned cracks, not incÌucling SCC, br-rt is not

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cor'ìsidered ¡ccurate for sizing. Higlì inspectioÌì speedscan degrade sizinB accuracy.

6.2.3 Metat Loss and Caliper Tools for Third-PartyDâmage and Mechanical Damage Threat. Dents andareas of metâl loss are the only aspect of these fh¡eatsfor which Il,l tools calì be effectively used for detectionand sizing.

Deformation or geometry tools âre most often usedfor dctecting damage to the line involvilìg defolmatiolìof the pipe cross sectìorì, which can be caused by con-struction dalnage, dentscaused by the pipe settling ontorocks, thircl-pârty damage, and w¡inkles or bucklescaused by compressìv(] ioâding or uneven settlement oftlìc pipeline.

The lowest-resolution geometry tool is tlìe gagjrìg pigor single-channeÌ calipcr-type tool. l'his type of tool isadequate for icìentifying ând locating severe defo¡ma-tion of tlìl¡ pipe cross section. A higher resolution isprovided by standard caliper tools that record a channelof data for each caliper arm, typically 10 o¡ 12 spaceda¡ound the circumference. This type of tool can be usedto.tiscern deformation severity and overall shapeaspecls of the cleformation. With some effort, it is possi-ble to identify s}rarpness or estimate strains associatedwith the deformation using the star'ìdard caliper tooìoutput. High-¡esoÌution tools p¡ovicle the most detailedinformatiorì about the deformation. Some also ilìdicateslope or change in slope, which can be useful fot identi-fyitrg bending or setllement of the pipeline. Third-partydamage th¿ìt has rerou¡ded unde¡ the influence of inte¡-nal p¡essure in the pipe may challenge the lower limitsof ¡eliable detection of both tlìe standard andlìiglì-resolution tools. There lìas been limited successidentifying tlììrd-pâ¡ty damage using magnetic-fluxleakage tools. MFL tools are rìot usefuÌ fot sizingdcfo¡mations.

6.2.4 All Other Threats. Inline jnspection is typi-cally not tlìe appropriate inspectìon method to use fo¡all otlìer tlìreâts listed in section 2.

6.2.5 Spec¡at Cons¡deratlons for the Use of ln-L¡nelnspect¡on Toots

(n) The folkrn'ing shall also be considered whenselecting the appropriate tooì:

(1) Dctcclìon Senstti?i¡f MìrìiDlum defect size spec-ified lol rhe ILI tool should be smalle¡ th¿ìn the sìze ofthe defect sought to be detected,

(2) Clossificaliou. Classification allows differentia-tjon among types of anomalies.

(3) Sizilg Accurncy. Sìzing accuracy enables priori-tization and is a key to a successful ilttcgrity manage-mcnt plan.

(4) Locoliott Acc¡r¡'ncy. Location accuracy enableslocation of ¿ùìomâlies by excavation.

(5) RequienettlsJltr Defect Assess1lte11!. Resultsof ILIhâve to be adequate for thc specific ope¡ator's defectâssessment ProSram-

(ú) Typically, pipelìne operators provide ar'ìswcrs toa questionnaire provided by the ll-t vendor that shouldlist âll tlìe signifìcarìt parameters and clìaracteristics ofthe pipelilìe section to be ìnspected. Some of the moreiÌnportarìt issues tlìât should be conside¡ed are asfollows:

('1) Pipelirrc Quesfiotttnire. TIìe questionnaire pro-vides a review ofpipe clÌaracLerisLics, such as steel grade,type ofwelds, Iength, diameter, wall thickness, elevafiorìprofiles, etc. Also, the questionnaire identifies anyrestrictions, bends, known ovalities, valves, unbarredtces, coupìirìgs, and clìill Ìings the ILI tool may need tonegotiate.

(2) Lo nclters øtd lì¿¿¿in¿,'s. These items slìould bereviewed for suitability, since ILI tools vary in overallIength, complexit, geometry and rnaneuverability.

(3) Pipe Cleanlitrcss. The cleanliness can signifi-cantly affect data coìlection.

(4) "lype of Fluid. l'lìe type of phase - gas orìiquid - affccts the possible choice of teclìnologies.

(5) Flozo llalc, Prcssu|c, ntul Teúlpcrollte. FÌow râteof the gas will influcnce the speed of the ILI tool inspec-tion. [f speeds are outside of the no¡mal ranges, resolu-tion can be compromised. Total time of inspection isdictated by irìspection speed, but is limited by tlìc totalcapacity of bâtteries and data storage available orì thetool. High tempe¡atures can affect tool ope¡ation qualityand slrouid be considered.

(6) Ilrodlct Bypnss/Supplentent. Iìeduction of gasflow and speed reduction capability on tlÌe ILI tool maybe a consideration in higher velocity lines. Conversely,the availability of suppìementary gas where the flowrâte is too Ìow shalÌ be conside¡ed.

(c) Thc operatol sÌralÌ assess the general reliabiÌity ofthe ILI method by looking at the following:

(1) confidence level of the ILt method (e.g., proba-bility of detecting, clâssifying, and sizing the anomaÌies)

(2) history of tlìe I[,] method/tool(3) success rate/failed surveys(4) âbility of the tool to irìspcct the full length ancl

full circumfe¡ence of tlìe scction(5) ability to indicate tÌìe p¡esence of multiple câuse

anomaliesGenerally, representatives from the pipelilìe opcrâtor

and the ILI service vendor should analyze tlìe goâl ândobjectìve of the inspection, and match signìficant factorsknown about the pipeline and expected arìomalies withtlìc capâbiÌities and performance of tlìe tool. Choice oftool will depend on the specifics of tlre pipeline sectionand the goal set for the inspection. The operator shâlloutline the process used in the integrity managementplan foÌ the selection and implcmentation of the ILIinspections.

18

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6.2.6 Examlnatlon and Evaluat¡on, Ìlesults of in-line inspection only provide ilìdications of defecls, withsome clìaracterization of the defect. Screening of thisinformation is required in order to determine the timeframc fol examination arìd evâluation. Ihe time frameis discussed in section 7.

Examination consists of â variety of direct inspectionteclìniques, including vìsual inspectiolì, inspcctionsusirìg NDE equipment, and taking lneasurcments, inorder to characterize tlìe defect in confirmatory cxcava-t;oiìs where anomalies are detected. Or'ìce tÌìe defect isclìaracterizcd, the operator musL evâìuate the defect inorder to determine the appropriâte rnitigatìon actions.Mitigation is discussed in section 7.

6.3 Pressure Test¡ng

Pressure testir-rg has lolg been an industry-âcceptedmethod for validatirìB the ìntcgrity of pipelines. 'Ihisintegrity assessment method can be bolh a strength testând a leak test. Selectiorì of tlììs method shall be appro-pri,ìte for the threats be¡rìg ¿sscs{cd.

,^.SME 831.8 contairìs details ()1ì conducting pressuretests for both post-corìst¡uctìon tcsting and for subse-quent testing after a pipeline has been ilr se¡vice for a

period of time. The Code specifies tlìe test pressurc k)be attained and the test duration irì o¡der to âddrcsscertain tlìreâts. It also specifies allowable test mediumsand unde¡ what conditions the various test mediumscan be used.

The operator should consider the results of tlìe ¡iskassessmentand the expected types ofanomalies to deter-mine when to conduct inspections utilizil-tg pressu¡etesting.

6.3.1 Time-Dependent Threats. Pressure testing isapp¡opÌi¿ìte for use when addressing time-dependelìtthreats. Time-dependent threats are external corrosion,internal corrosion, st¡ess corrosion cracking, and otlìerenvi¡onmentÂlly assisted corrosion mechanisms,

6.3.2 Manufactur¡ng and Related Defect Threats.Pressure testing is appropriate for use wherì âddressir'ìgthe pipe seâm âspect of the manufâcturing threat. Pres-sure tesfing shall comply with the requirements ofASME 831.8. Tliis will define whelhe¡ air or water shâllbe used. Seam issues have bcen known to exist fo¡ pipewith a joint factor of ìess than 1.0 (e.9., lap-welded pipe,hammer-welded pipe, and butt-welded pipe) or if thepipeline is cornposed of Ìow-frequency welded electricresistance welded (ERW) pipe or flash-welded pipe. tìefercnces for determinìng ìf a specific pipe is susceptibleLo seam issues arc ltltegrity Clt]tictcrisLics of V¡l1lagePipelitrcs (The INGAA Foundation, Inc.) and Histoty ofL,ine Pipc Mnû fncturittg irt Not lh Anrcrica (ASME rcsearchreport).

When raising tlìc M,{OP of a steel pipeline or wììerìrâising the operating pressure above the historicaloperating pressure (i.e., highest pressu¡e recorded in 5 yr

prior to the effective clate of this Cocle), p¡essure testingmust be perf.rrmed tU addresq the "eam is5ue.

P¡essure testing shall be in accordânce withASME 831.8, to at least 1.25 times tlìe MAOPASME 831.8 clefines how to conduct tests for botlì post-conshuction and in-service pipelines.

6.3.3 Atl Other Threats, Pressure testing is typicâlly1ìot the approp¡iâte ilìtegrity âssessmelìt method to usefor aÌl other tlì¡eâts lìsted in sectiorì 2.

6,3.4 Exam¡nat¡on and Evatuat¡on. Any section ofpipe that fails a pressure test slìall be examined in o¡derto evaluate tlìat tlìe failure was due to the thrcaf thalthe test was irìtendecl to acld¡ess. lf the failure wâs dueto another threat, tlìe test failure info¡m¿rtiorì must beintetrated with otlìer infolmation r€ìative to tlìe otlìcrthreat ancl tlle segment [eassessed lor risk.

6.4 Direct Assessment

Direct assessment is arì integrity assessment metlìodutilizint a structured proccss thlough which the opera-tor is able to jntegrate knowledge of lhe physical charac-feristics and operating history of a pipeline system orsegmert with the results of inspectioir, examinatio¡, aììdevaÌuâtion, in order to determine the intcgrity.

6.4.1 External Corrosion D¡rect Assessment (ECDA)

for the E(ternal CoÍos¡on Thfeat. Ëxte¡nal corrosiondirect assessment can be used for delerminin8 integrityfor the external corrosion threat on pipeline segments.The process integrates facilities data, and cur¡ent andhistorical field inspections and tests, wilh tÌìe physicalcharâctcristics of a pipelile. Nonintrusive (typicallyaboveground or indirect) inspections are usecl to esti-mate tlìe success of the corrosion protection.'lhe ECDAprocess requires direct examinations and evaluations.Dìrect examilìatìorìs and evaluâtions confi¡m tlìe abilityof tlìe indirect ilìspections to locate actìve arìd pastcorro-sion locations on the pìpeline. Post-assessment isrequired to detelmìne a corrosion rate to set the reilìspec-tioÌì irìterval, reâssess the perforiÌlance metrics and theircurrent applìcabilìty, ând ensure the âssumptions madeilì the previous steps remàin co¡rect.

'lhe ECDA process therefore has the followirrg fourcomPonents:

(d) p¡e-assessment(¿?) ir'ìspections(c) ex¡min¡tiorrs and evalr¡.r(ionsl¿f) post-assessment'l'he focus of the IìCDA approach described in this

Code ìs to identify locations where external cor'¡osiondefects may have formed. It is recognized that evidenceof othe¡ threats such as mechânicâl damêge and stresscorrosion cracking (SCC) may be dctected during theECDA process. While implementing ECDA ancl wherrthe pipe is exposed, lhe operator is advised to conductexaminations for nonexternal corlosion threats.

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'Ihe prescriptive ECD^ process ¡equires the use ofal least two jnspectìon rnetlìods, verification checks byexâmination alìcì evaluatiotìs, and post-âssessmelllvalidâtion.

Iìor more informatìon on the ECDA process as alìinte8rity assessment method, see NonmandatotyAppendix B, section B-1.

6.4,2 lnternaI Cofrosion D¡rect Assessment Process(ICDA) for the lnternal Corros¡on Thteat, llìrernâl corro-sion direct âssessment can be used for determilìinginte¡rrity for the internal corrosion tlìreat orì pipelilìesegmeÌìts that uormally carry dry gas but may suffcrfrom slìort-tcrm upsets of wet gas or free watet (or otherelectrolytes). Exâminations of low points or at inclir'ìcsalol.ìg a pipeline, which force an electrolyte suclì âs waterto first accurÌulate, provide informatiolì about theremâining lengtlì of pipe. lf tlìese k)w pojnls have notco¡roded, then othcr locations futthe¡ dow\stream areIess likely to accumulate elect¡olytes and tlìerefore canbe considered free from cor¡osion. These downstrcamlocations woulcl rìot ¡equirc examination.

Internal corrosion is most likely to occur.wlìere waterfirsl accumulates. P¡eclicting the locations of water accu-ûulation (if upsets occur) serves as a methocl for prio-ritizin8 local examinatior'ìs. Predicting where water firstaccumulâtes requires knowledge about the multiphaseflow behavio¡ in the pipe, requiring certaiù data (seesection 4). ICDA applies between any feed points until anew input or output clìanges thc polential for electrolyteentry or flow characteristics.

Examinâtions are perfotmcd at locations where elec-troìyte accumulâtjon is ptedicted. For most pipeÌines it isexpected Lhat examinaliolì by radiography or ultrasonicNDE will be required to measure the remaining wallthickness at those locations. Oncc â site has beenexposed, internal corrosion rnonitoring method(s) [e.g.,coupon, probe, ultrasonic (UT) sensorl may allow anoperâtor to extend the leinspectiolì interval and be¡efitfrom real-lime monitoring in the locations most suscep-tible to internal corrosion, There may also be some appl!cations where the most effective app¡oach is lo conductin-line inspcction for a portion of pipe, and use theresults to âssess the downsl¡eam intertìal corrosionwhere inlìùe inspection cannot be conducted. If theÌocatiorìs most susceptible k) coltosiolì are determilìednot to corìtain defects, the integrity of a large portion ofthe pÌpeline has been ensured. For.mo¡e itìformâtion ontlìe ICDA p¡ocess as ân itìteg¡ity assessment metlìod,see Norìmandâfory Appendix B, section B-2, ând theNACE 0206-2006 Stândard Prâctice, Lìter.nal CorrosiorìDirect Assessment Methodology for Pipelines CarryingNo¡maÌly Dry Nâtu¡âl cas (DclCDA).

6.4.3 Stress Coffosion Crack¡ng Direct Assessment(SCCDA) for the Stress Corros¡on Crack¡ng Threat. Stressco¡rosìon cracking dj¡ect assessrncnt can be used todetermine the likely presence or âbrìencc of SCC on

pipeìine scgmcrìts by (rvalualing the SCC th¡eât. Notethat NACE RP0204 Stress Corrosion Cracking (SCC)Direct Assessrìerìt Mcthodology provides detailed guid-ance and proccdures fo¡ conducting SCCDA. TheSCCDA pre-assessrneiìt process integrâtes facilities data,cuuent and historical ficld inspections, ancl tests withthe physìcal châ¡acteristics of a pipeÌine. Nonintrusive(typicaìly tenain, aboveground, and/or indirect) obser-vations and inspectiorìs are used k) esfimate the absenceof cor¡osiorì protection. Tlìe SCCDA process requiresdi)ect examinations and evâluâtions. Direct examina-tions and evaluations corìfirm tÌìe ability of the indirectinspections to ìocate evìdcnce of SCC on the pipelinc.Post assessment is required to set the re-ìnspection intet-val, re-assess the performance metrics ar'ìd tlìeir currentapplicability, plus confirm the valìdity of the assump-tions macle in tlìe previorrs steps remaiì coÌlcct.

The focus of the SCCDA approach described in thisCode is to identify locations where SCC may exist. It isrecognized that evidelìce of other tlìreats such as exter-nal co¡rosion, internaÌ corrosion, or mechanical damagemay be detected during the SCCDA process. Whilei¡nplementing SCCDA, and when tlìe pipe is exposed,the operâtor is advised to colìduct examinations fo¡ rìorì-SCC threâts. For cletailed information on the SCCDAprocess âs an integrity assessment metlìod, see especiallyNACE RP 0204,

6.4.4 Att Other Thfeats. Di¡ect assessment is typi-câlly not the appropriate integrity âssessmenl metlìodto use for all odìer threats listed ir'ì sectiolì 2.

6.5 Other lntegrity Assessment Methodotog¡es

Othe. proven intcgrity âssessment methods may existfor use in mâlìagìng the irìtegrity of pipelines. For thepurpose of tlìis Code, it is acceptable for an operator touse these inspections âs an alternative to tlìose listedabove.

For prescriptive-based integrity mânagement pro-grams, the altelnative iìtegrìty âssessment shall be anindustry-recognized rnethodology, and be approved andpublished by an ìrìdustry consensus stanclarclsorganization.

For pelformance-based integrity management pro-grams, techrìiques other than tlìose published by consen-sus standards organizations may be utilized; however,the operabr slìall follow the performance requirementsof this Code and shall be diligerìt in colìfirming anddocunenting the validity of this approach to confirmthât â higheÌ level of integrity or integrity âssurêncewas achieved.

7 RESPONSES TO INTEGRITY A55E5SMENT5 ANDMITIGATION (REPAIR AND PREVENTION)

7.1 General

Tlìis section covers the schedule of resporìses to lheiiìdicâtìons obtained by illspection (see sectiolì 6), repair

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activities tlìat can be affected to remedy or eliminate anuns¿ìfe condition, preventive actìorìs tlìât can be takento reduce or eliminate a threat to the integrity of a pipe'ljne, ând estabÌishment oftlìe i1ìspection interval. Inspec-tion intervals are based on tlte clìâracterizatioÌì of defectindicâtions, the level of mitigatiorì achieved, the preven-tio¡ì methods employed, and the uscful life of the data,with consideration given to expected defect growth.

Examination, evaluation, and mitigative actions shâllbe selected and scheduled to aclìieve ¡isk rcductionwhere approp¡iate in each segmelìt witlìin thc ìnteg¡itylnanagement progtam,

'l'he integ¡ity management program slralÌ providearìalyses of existing and newly implemented mitigâtionactions to evaluate tlìeir eflectiveness atìd justify theiruse in the Éuture.

]àble 4 inclùdes a summary of some pleventiorì andrepair rnethods and their applicability to eaclì threât.

7.2 Responses to P¡pe(ine ln-L¡ne lnspections

An operator shall complete the response âcco¡ding toa prioritized schedule established by considering there$uÌts of a risk assessment and the severity of in-lineinspectìon ilìdications. Tlìe required response scheduleintelvaÌ begins at the time the condition is discove¡ed.

When eslablishing schedules, responses can bedivided into the following three groups:

(n) immediate: indicalion shows that defect is ât faìl-ure poiùt

(ú) scheduled: ir'ìdication shows defect is significantbut not a[ failure poirìt

(c) monitored: indication shows defect wilÌ not failbefore next inspection

Upon receipt of the characterization of indicafionsdiscove¡ed during a successful inJine inspcction, theoperator shaÌl promptly review tlìe results for ìmmediâte¡esponse indications. Other indicâtions shall be¡eviewed within 6 mo and a respolìsc plan sÌrall bedeveloped. The plan shall include the metlìods and tim-iùg of the response (examination and evâluâtion). ForscÌreduled or monito¡ed responses, an ope¡ator mayreinspect ralher than exâmine and evaluate, providedtlìe reinspection is conducted and results obtainedwìthin the specified time frame,

7.2.1 Metal Loss Tools for lnternaI and ExternalCofrosion. Indications requiring immediate responseare those tlìat might be expected to cause immediate o¡near-term Ìeaks or ruptures bâsed on their known o¡pe¡ceived effects on the strengtlì of the pipeline. Thiswould include any corroded arcas that have a predictedfailure pressure level less tlìan 1.1 tìmes the MAOP asdetermined by ÂSME B31G or equivâÌenf. Also in thisgroup wouìd be any metal-loss indicatìon âffectirìg acletected longitudinal seam, if tlìat seam wâs fotmedby direcl current or low-frequency electric resistâtìceweÌdinB or by electric flash welding. lhe operator shall

take ¿ìction on tììese inclications by either examirìingthem or reducir-rg the operating pressì.lre k) provide auaddilional margin of safety, within a period not to exceed5 days following determinâtion of tlìe condition. If theexamination cânnoL be compÌeted within tlìe lequited5 cl¿ìys, tlìe operâtor slìall tempora¡ily reduce theoperâtinB pressure until the indicâtion is examined.Figure 4 shall be used to determine the reducedope¡ating pressure based on tlìe selected response time.After examination and evaluation, any defect found torequire repair or removal shaìì be promptly remediatedby repair or removal unless the operating pressure islowered to mitigate the need to repair or remove tltedcfect.

Indicatiorìs ilì the sclìeduìed group are suitable forcolìtirìLrcd ope¡atiorì without imùediate response pro-vided they do not g¡ow to criticâl dimensions prior tothe scheduled ¡esponsc. hìdicatìons characterize.l withâ prcdictcd failure pressure greater tlìan 1.10 times theMAOP shall be examined and evaluated according to aschedule establishecl by Fig.4. Any defect found torequire repair or removal shall be promptly remediatedby repair or removal unless tlìe operâtìng pressure islowered to mitigate the need to repair or rcmove thedefect.

Morìitorecl inclications are the least severe and willnot require examirìation and evaluation until bhl] nextscheduÌed integrity assessment interval stipulâted bythe integrity manatement plan, provided that they arenot expected to grow to criticaÌ dimensions prior to thenext scheduled assessment,

7.2.2 Ctack Detect¡on Toots fof Stress Corros¡onCrack¡ng, It is Lhe responsibility of the operator todeveìop and document applop¡iâte assessmetìt,response, and repair plans when inJine iirspection (lLI)is used for the detection and sizing of indications ofstress corrosion cracking (SCC).

In lieu of developing assessment, response, and repairplans, an operator may elect to treat all indications ofstfess corfosion cracks as requiring immediâte response,ìlìcludinfl examinâtioll or pressure reduction within a

period nof to exceed 5 ctays following determinatioiì oftlìe condition.

After exâlnination ând evâluation, any defect foundto require repair o¡ removâl slìaÌl be promptly temecìi-ated by repai¡, removal, o¡ lowering the operating pres-sure urìtìl such tirne as ¡emovâl or repai¡ is completed.

7.2.3 Metal Loss and Caliper Tools for Th¡rd-PartyDamage and Mechanical Damage, Indications requirilìgimmediate responsc âre those thât might be expectedto cause immediâte or neaÌ-Lerm leâks or ruptures basedon their known or perceived effects on the sfrength ofthe pipeline.'Ihese could include denß with gouges.Tlìe operafor slìâll exâmirìc these indications within aperiod not to exceed 5 days following determination ofthe conclition.

21

Copyright O 2010 by the American Socicly ofMechânicâl Engineers &rnay be mâde of this mâterìal witllout wntten coDsent ol ASME

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Construction in5peclion

Preservice pressure test

Operâlor (r¿ining

lncrease ma'ker rrequency

5train monfoíng

lncreased wall th¡ckness

CP monitolmainla¡n

L€¿kate conÌrol measulesPig-GP5/strain measurementReduce extemal stress

lnstall heåt tracing

Rehabilitalio¡Coat¡ns repair

lncrease rover d€pth

OpeÉling lemper¿ture reduct¡on

Eiocide/inhib¡ting injectionln5rall themal protertion

ECÀ recoatGrind €pair/ECADirect deposition ¡,r€ld

Prevent¡on, Det€d¡on,

Coros¡on lncorect $leather €nvion-Ihid-Party Damage Relåted Êqu¡pment Operat¡on Rel¿led l¡lânlfactüre Construct¡oî Gfo.ce meñt

Gåsk/ Str¡p/ Conl/ SeaU P¡pê râh

Table 4 Acceptable lhreat Prevent¡on and Repa¡r Methods

ÌPD0É PDP Vand E¡l lnl BP Rel Påck lO Cl{ L HR/f Sêan Pipe Gwêld weld coup lvB/B

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Rèpa¡rs (cont'd)Type 8, pressurized lleeveType A, rêinforcìñg sle€ve

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when welding on pressù¡¡zed ¡ines. Guidance can be found in publications by W-4. Bruce, e\ al-, tPc2oo2-27737, \PC2OO6-10299, and IPC 2008-64113.

sìlio¡s at gidh welds, f¡ttings, ând !o heavy wall pipe require add¡tionâl care to ensure the hoop cafty¡ng câpâc¡ty ¡s efect¡vely €nored.

GENERAL NO-lEr fh€ abbrev¡ations found ìn Tabl€ 4 relale to the 21 rhr€ats discussed in sect¡on 5. úplamtions of the abbl€viaìionç ãre ¿s fotlows:

coníRcl = control/relief eqìrìpm€nt mallunct¡oncoup = couplint failure

CW = cold we¿therDirect deposition weld = a very sp€c¡al¡zed repair tÊchnique lhal rcquìres delåiled materials info¡mat¡on and procedure val¡dation to åvoid possible cracking

on l¡ve linesECA = Eng¡neerint Critical Assessment ¡s an eng¡nee¡¡ng an¿lysis suppoled by tesls lhat estimar€ lhe interu¿l of continued safe

oper¿t¡ons.EM = Eårth mov€nentE¡t = external coúosron

Fab Weld = delective fabícãlion weld includint bBnch and f jo¡nts

Gask/Oing = sasret or O.rinsGweld = detective Þ¡pe sidh weld (circurnf€rential)

H8/r = h€ãvy ra¡ns or floodslnt = internål corosionl0 = incorect operationsL = lighhint

pDp = pr€viousìy dâmaged p¡pe (delãyed railu'€ mod€ such as dents and/or souges) (pr€v¡ously dãmased P¡Pe); see ASME Bl1-8

para. 851.4.2 and Nonmandatory APpÊndix R'2

Pipe = defective pipePipe seam = d€fective PiPe seam

sCC = stress corc5ion cr¿ckintseal/Pack = seal/pump p¿.kins failure

Srrip/BP - st¡ipPed lhreãd/broken Pipe'IPD(IÐ = damase inaitted by first, s€cond, o' thifd parties f¡nst¿nraneous/immedra!€ failu.e)

Vand = vandã¡ismWB/B = ì¡/nnkle bênd or buctle

Table 4 tuceptable Threat Prevent¡on and Repa¡r Methods (Cont'd)

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ASME 831.85-2010

F¡9. 4 T¡m¡ng for Scheduled Responses: Time-Dependent Threats, Prescr¡pt¡velntegr¡ty Management Plan

30% SMYS

Above 30% but notexceeding 50% SMYS

\bove 50%SMYS,/1

0 510 15 20 25

Response Time, yr

G€NERAL NoTE: Predicied iaiìure pressure, P¡ ìs calculated us¡ng a proven engineering method for evaluating the remaining strength ofcoroded pipe. The failure pressure ratio is used to categorize a defect as imr¡ediôte, scheduled, or monitored.

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lndications requiring a scheduled lesponse wouldilrclude any indication on a pipeline ope¡ating at orâbove 30% of specified minimtrm yield strength (SMYS)of a pÌain dent tlìat exceeds 6% of the nominâl pjpecliameter, mechanical damage with or witÌtout concur-rent visible indentation of tlìc pipe, dents with cracks,dents thât affect ductile girth o¡ seam welds if tlìe depthis in excess of 2% of the nominal pipe diaml]ter, anddents of any depth that affect nonductile welds. (Foradditionâl infolmation, see ASME 831.8, pâra.851.4.)'lhe operator shall expeditiously examine these indicâ-tiorìs witlìin a period not to exceed 1 y¡ following deter-milìâtion of tlìe condition. After examilìation atìdcvaluation, any clefect founcl to require repair or temovâlshall be promptly remediated by lepair or removal,unless the operating pressure is lowered to mitigate tlterìccd to rep.ìir or rcmovc thc detcct.

7.2.4 L¡mitat¡ons to Response limes for Prescr¡ptive-Based Program. When time-clependent anomalies sucltas infernâl corrosion, external cotrosion, or stress corro-siolì c¡acking are being evalùâted, an analysis utilizingappropriate âssumptions about growth rates shall I¡eused Lo ensure thât the defect will not attain c¡iticaÌdimensiolìs prior to the scheduled repair o¡ next inspec-tion. GRI-00/0230 (see s(}ction 14) contains additionalguidance for these analyses.

Whel determining repair infervals, the operalorshould conside¡ that cert¿rir-r tlueats to specific pipeline

operaling conditions may require a reduced examinationand evaluation inte¡val, This may include lhird-partydamage or construction threats in pipelines subject topressure cycling or external loâding tlìat may promoteincreâsecl defect growth lates. For p¡escriptive-basedprograms/ the inspection intervals are conservative forpotential defects that could lead to â rr¡ptu¡e; however,this does not aÌleviate operators of the responsibility toevaluate the specific conditions and changcs inoperating conditions to ensure the pipeìine segmerìtdoes not warrant specjal consideration (seeGRI-o1/0085).

If the analysis shows that the time to failure is tooshort in relation to the time scheduled fo¡ the repaittlìe operator shall appÌy lemporary measures/ such âs

pressure rcductioÌr, unlil a pl]rmanent repaìr is com-pleted. In conside¡ing projected repai¡ intervals andmetiìods, the operator should cor-rside¡ potentialdeìaying factors, such as access, envirorìmenlal permitissues, and gas supply ¡equi¡ements.

7.2.5 Extendlng Response T¡mes for Performance-Based Program, An enBineering critical assessment(ECA) of some defects may be performed to extend tlìcrepâir or rejnspection interval for a performânce'bâsedproglam. ECA is a rigorous evaluation of the data dìatleassesses tlìe cdtìcality of the anomaly and âdjusts thcprojected gÌowth rates based on site-specific parameters.

24

Copyrighr O )0t0 by lhe Anrerican Society olMecllanrcal En8jrecrs. fftNu reproduction nray be rnade oflhis r¿lcri¿l willìoul wrirlcrì consc,,t ofASMD. 'lÉ)l

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'llhe operator's integtity managemerìt program shallìnclude documentation tlìat descrìbes grouping of spe-cific defect types and the EC^ methods used for suchânalyses.

7.3 Responses to Pressure Test¡ng

Any defect tlìat fails a pressu¡e test shall be promptlyrenìediated by rcpair or removâI.

7.3.1 External and lnternal Corros¡on Threats. 'theinterval betweclì tests for the cxte¡nalând internaì corro-sion thleats shalÌ be co¡rsistent with lable 3.

7,3.2 Stfess Corros¡on Cfack¡ngThreat. Ihe intervâlbetwr:en pressule tests for stress corrosion cracking shallbe as follows:

(n) If no failures occurred due to SCC, the operato¡shall use one of the folìowing options to address tlìeIong-term mitigation of SCCI

(1) a clocr"rmented hyd¡ostatic retest p¡ogrâm withâ technically jrÌstiliable inte¡val or

(2) alr cngineering ctitical assessmelìt fo evaÌuâtethe risk and ìdentify fu¡ther mitigation methods

(b) If a failure occurred due to SCC, the operator shallperform the following:

(i) implement a documented lìydrostatic retestprogram for the subject segment atìd

(2) technically justify the retest interval in the writ-Len retest program

7.3.3 Manufactur¡ng and Related Defect Threats. Asubsequent p¡essure test for Lhe manufacturing threatis not requi¡ed unlcss the MAOP of the pipeline hasbeen ¡aised or wlìen tÌìe opetating pressure has beenrâised above the historical operating pressure (highestpressure recorded in 5 yr prior to the effective date oftlìis supplement).

7.4 Responses to Direct Assessment lnspect¡ons

7.4.1 ExternaI Corrosion Direct Assessment (ECDA).For the ECDA preçcriptive program for pipelinesoperâtirìg above 30% SMYS, if the operator clÌooses toexamine and evaluafc all the indications four.rd byinspection, and repairs all defects tlìât could grow tofailure in 10 yr, then the ¡einspection inte¡val shall be10 yl. If the operator elects to examine, evâluate, andrepair a smaller set of indicâtions, then the inferval shallbe 5 yr, provided an analysis ìs performe<l to ensu¡e allren,aining clefects will not grow to f¿ìilute in 10 yr.. Their'ìterval between determinâtior'ì and examinati<¡l shallbe corìsistent with Fig. 4.

Fo¡ tlìe ECDA prescriptive p¡ogram for pipeline seg-melìts operating up to but not exceeding 30% SMYS, ifthe ope¡ato¡ chooses to examine and evaluate all theindications found by inspections and rcpair all defectsthat could grow to failure in 20 yr, tlìe reinspectioninterval shaìl be 20 yr. If tlìe operator elects to exâmine,evaluate, and repair a smaller set of indicatiolìs, tlìen

the irìte¡val shall be 10 yt provided àn analysis is per-fo¡med to ensure all remainilìg defects will not grow tofaiÌure in 20 yr (af an 80% confidence level). The intervalbetween determiìation and examination slìall be cor'ì-sistent witlì Fig. 4.

7.4.2 lnternal Corros¡on D:rect Assessment (ICDA).For the ICDA prescriptive program, exâmination andevaluation of all selccted Ìocations must be performedwithin 1 yr ofselection. The interval between subsequelìtexaminàtiolìs slìall be consistent wìth Fig. 4.

7.4.3 Stress Corrosion Cfack¡ng Direct Assessment(SCCDA). l-or the SCCDA prescriptive pÌoBram, e\àmi-nâtion ar'ìd evaluation of all selected locations mLrst beperformed within 1 yr of selection. ILI orpressure testìrìg(hydrotestirìg) rnay rìot be warranted if signilicant andextensive crackirìg is not present on â pipcline system.'lhe inlerval betweer'ì subsequent ex¿ìmirìatiolls shallprovide similar safe interval between periodic integrityassessments corìsistent with Fig.4 and section A-3 ilìNonmandatory Appendix A. Figure 4 ând section 4,3in Nonmandatory Appendix A are applic¿ìble to pre-scriptive-based programs. The intervals may ìreextended for a perfornìance-bâsed progtam as providedin para. 7.2.5.

7.5 T¡m¡ng for Scheduled Responses

Figure 4 contains three plots of tlìe allowed time torespond to an indication, based ()1ì the predictive fâiÌurepressure P¡ divided by the MAOP of tlìe pipeline. Tlìethree plots correspond to

(¿) pipelines operating at pressures above 507. ofSMYS

(b) pipelines ope¡âting at pressures above 30% ofSMYS bnt not exceeding 50% of SMYS

(c,) pipelines ope¡atint at pressures not exceeding30% of SMYS

fhe figLrre is applicable to the prescriptive-based pro-gram. 't'he intervâls may be extended for theperformance-based program as provided in para.7.2.5.

7.6 Repa¡r Methods

Table 4 provides acceptable repair mctlìods fot eachof the 21 threats.

Eâch operâtor's ilìtegtity ma¡ìagement program shâÌlincÌude documcnted repair procedures. AII repair.s shaÌlbe made with matelials and processes tlìat are suitablefor the pipelirìe operating conditioÌls ârìd meetASME 831.8 requircnìents.

7.7 Preventlon Strategy/Methods

PreventioÍì is an irnportânt proactive eÌement of anintegrity management program. Integrity managementprogram prevention strategies shoulcl be based on datagathering, threat ide)ìtification, and rìsk âssessmerìtsconducted per the requirements of sectiols 2,3, 4, and

(10)

(10)

25

Copyright O 2010 by the AnteicaD Society of Mccharìical Èngiûeers. &No be nrâde of this material without writtelì consent of ASME.

ASME 831,8S-20r0

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5. Prevention measlrres slìown to be effective in thepast should l¡e contiuued ilì the irìtcgrity managementprogram. Plevention strategies (including intervals)shorLld also cousider the classifìcâtioll of identifiedthreats as time-clepelìdent, stable, or time-independentin order to ensure lhat effective prevention methods areutiÌized.

Operators who opt for p¡escriptive programs slìoulduse/ at a minimum, the preventior-t metlìods indicatedin Nonmânclâtory Appendix A under "Mitigation."

For operators who choose performance-based pro-g¡ams, both the p¡eventive methods and time intervalsemployed fo¡ each threat/segment should be deter-mined by analysis using systcm attribr¡tes, informationabout cxisting conditions, and industry-proverì riskassessment methods.

7.8 Prevent¡on Opt¡ons

An operator's integrity mânagcmerrt program shallinclude applicable activities to p¡evetìt and minimizethe consequences of unintended releases. Preventionactivjties do not necessarily require justìfication tlìroughâdditional inspection data. Prevention actions cân beìdentified during normal pipeline operafion, tisk asscss-ment, implementation of the inspection plalì, or du¡ingrepair.

TIìe predominant prevention activities presented insection 7 ìncLude informâtion on the lollowing:

(a) preventilìg tlììrd-party damage(D) controllingcorrosion(c) dctccting !¡nintended rellJases(d) minimizing the conscquences of unintended

reìeases(e) operating pressuÌe reductionThere are other prevention activities that the operator

may conside¡. A tâbulation of prevention âctivities ândthei¡ ¡elevance to the threats iclentified in sectiorì 2 ìspresented in lhble 4.

8 INTEGRITY MANAGEMENT PIAN

8.1 General

The integrity ma1ìâgement plan is devebped aftergathering the data (see sectìon 4) and completing therisk assessment (see section 5) for each threat and fo¡each pipeline segmelìt or systcm- Alì appropriate integ-rity assessment metlìod shall be identified for each pipe-line system or segment. Integrity âssessmetìt of eachsystem cân be accomplished tlìrough a pressule test, anirìline iùspection using a vatiety of tools, direct assess-ment, or use of other proven teclìnologies (sec section 6).In some cases, a combjnation of tlìese metlìods may beappropriate. The highest-r'isk segments shaÌl bc givenpriorìty for inlegrity assessment.

Followirìg the integrity assessment, mitigation activities slìâlÌ be undertaken. Mitigation consists of two parts.

The first part is the repair of the pipeline. Repair activi-ties shall be macle in accordance with ASME 831.8and/or otlìer accepted inclust¡y repaìr techniques.Repair may include replacing defectivc piping witlì newpipe, installation of sleeves, coating repair, or otlìer reha-bilitâtion. These activitìes shâ11 be identified, priolitized,ancl scheduled (see section 7).

Once the repair activities are determined, the opet aLorslrall evaluarte prevention [echniques that p¡event futuredeterioration of the pipeline. These techniques mayinclude providin g additional câthoclic protection,injectìng corrosion inhibitors anrl pipeline cleaning, orchanging the ope¡ating conditions. Prevention plays amajor role in reducing or eliminating lhe lhreats fromtlìi¡d-party dama¡¡e, exlernal corrosion, jnternâl cono-sion, stress corrosion cracking, coÌd weather-related fail-ures, eartlì movement failures, probÌems caused bylìeâvy railìs and floods, and failures caused by incorrectoperations.

All tlìreats cânlìot be dealt witlì through inspectionand repair; therefore, preventiorì fo¡ thcse threats is a

key element ilì tlìe plâlì. These actìvìties may include,for example, prevention oftlìird-party damage and mon-itoring for outside force damâge.

A performance-based integrity lnanagement plan,containing the same structu¡e âs tlìe prescriptive-basedplan, requires more detailed analyses based upon morecomplete data or information about the line. Using a

risk assessment model, a pipeline opelator cân exercisea variety of options for integrity assessments and pre-ventiorì ¡cl.ivities, Js well as their timinB.

Prior integrity assessnents and mitigatiolì âctivitiesshoulcl only be incÌuded in tÌìe plan if they were as

rigorous as those identified in this Code.

8.2 Updating the Ptan

Data collected during the inspection and mitìgationactivities shall be anaÌyzed and integrated with pre-viously collected data. This is in addition to other typesof integrity management-related data that is constantlybeing gathered lhrough normal operations alìd mainte-nance activities. Tlìe additionof thisnew data is a contin-uous process that, over time, wiìl improve the accuracyof futurc risk assessments via jts integration (see sec-tion 4), This ongoing data inlegration and periodic riskâssessment will result in colìtinual revision to the integ-rity asscssment and mitigation aspects of the plan. Inâddition, changes to the physical and operating aspectsof the pipeline system o¡ segment shall be properlymanaged (see section 11).

This ongoing p¡ocess will most likely result in a seriesof additionâl integrity assessmenLs or review of previonsintegrity assessments. A series of addìtional mitigationactivilies or follow-up to previous mitigation âctivitiesmay also be required. The plan shallbe updated periodi-cally as additìonal information is acquired anclincorporated.

26

Copyüght O 2010 by the Anìericân Society of lt4echanical Engineers &No rnay be made offhis n)atenal wrthout writteD consent ofASME

ASME 831.8S-2010

Tabte I Performance Measures

Measurement Catêgory Lagging Measures Leading Measures

Process/activìty measures Pipe dam¿ge [ound per locat;o¡excavated

Operationãl measures Number of significant lLl corrosionanomalies

Direct integrity measures Leaks per mile (km) in an integritymanagement pfogram

Number of excavationnotif icatìon requests,number of patrol detects

New rectifiers and ground

beds installed, cP currentdemand change, reduced

CIS fault detects

ch¿nge in leaks per nrile (km)

Table 9 Performance Metrics

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Extetnal cotoslon

lnternal coro5ion

Stress corosion cGcking

l\4¿nufacturing

Consltuclion

Equipment

fhird"pariy damâge

l¡correct operations

Weather related and out5ideiotces

Number of hydrostatic test failures caused by external corrosionNumber of repair actions taken due to in-line inspection resulisNumber of repait actions taken due to direct assessment resultsNumber oi externaì coûosion leaks

Number of hydrostatic test failures caused by ìnternal coÍoslonNumber of repair actions laken due to inline inspectìon resultsNumbet of tepair actions taken due to direct assessment resuìlsNumber of internal corosion leaks

Number of in'selvice leaks or failures due to sccNumber ol repair replacements due to 5ccNumber of hydrostatic test faÍlures due to scc

Number of hydrostatlc test failures caused by manufacturing defectsNumber of leaks due to r¡anufactur¡ng defects

Number of leaks or lailures due to construction defectsNumber ol girth welds/couplings reinlorced/removedNumber of wrinkle bends removedNumber of wrinkle bends inspectedNumber of fabrication welds repaired/removed

Number of regulator valve iailuresNumber of rel¡ef valve failuresNumber ol gasket or 0-ring failuresNumber of leaks due to equipment failures

Number of leaks or failures cãused by third'party d¿mageNumber of leaks or failures caused by previously d¿maged pipe

Number of ìeaks or laìlures caused by vandâlisr¡Number ol repaìrs implemented as a result of third'pa(y dam¿ge prior to a leak or failure

Number of leãks or failures caused by incorrect operationsNumber of audits/reviews conductedNumber of findings per audii/review, classìfied by severityNumber of changes to procedures due to audits/revíews

Number of leak5 that are weather related or due to outside force

Number of repair, replacement, or reìocatÍon actions due to weatherrelated or outside-force threats

30

Copyrìf¡ht O 2010 by the Americân Society of Mechanical Engineers ,G).riõHNo may be tùade of this tnaterial without writte¡ consent of ASMË

ASME 831.8S.2010

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It is recognized tlìa t certain integ¡ity assessment àctiv-ìties may be one-time events and focused on eliminâtionof certain threats, such as manufacturilìg, construction,arìd equipment th¡eats. For other threats, such as time-dcpendent th¡eâts, periodic irìspection will ì:e required.The plan shall remain flexil¡le and itrcorporate any newinformation.

8.3 Plan Framework

Tlìe integrity mânagement pìan shall contaìrì delailedinfo¡mâtion regârding eaclì of tlìe folÌowirìg clemeDtsfor each threat analyzed and each pipelirre segment orsystclì1.

8.3.1 Gather¡ng, Rev¡ew¡ng, and lntegrat¡ng Data.The first step in the integrity management process is tocollect, integrale, orgalìize, and review all pertinent arìdavailable data fer each threat and pìpelir'ìc segment. IhisProcess step is rcpeated aftet integtìty assessment andmitigâtion activities have been implemented, and aslìl]w operation ând malntenance informatiotl about thepipeìine system o¡ scgment is gathered. This informationreview shall be contained in tlte plârì o¡ in a databasethat is part of the plan, All data will be used to supportfuture risk assessments ând integrity evaluâtiorìs. Datagathering is covered in section 4.

8.3,2 Assess R¡sk. Risk assessment shorlld be per-formed periodically to incìude new information, con-sider changes made to the pipeÌirìe system or segment,incorporate âny external cltangcs, and consider new sci-entific techniques that lÌave been developed and coûr-ñercialized since the last assessmclìt. lL is recommendedthat this be performed anlrually but shall be perforrnedafter substantiâl changes to the systcm are made andbefore the end of the currerìt intetval. The results of thisassessmenL are to be reflected ilì the mitigalion arìditìtegrity assessment activities. Char'ìges to the accept-ance crite¡ia wiìl aÌso necessitatc reassessment. Theintegrity manâgement plan slìall contain specifics abouLIìow risks are assessed and the frequency of reassess-ment. The specifics for assessitìg risk âre covered insection 5.

8.3.3 lntegr¡ty Assessment. IJ¿ìsed on the assess-ment of risk, the apptopriate intcgrity assessments shallbe inìplemented. Integrity assl]ssments shâll be con-ducled using inline inspection tools, pressure testing,and/or direct ¡ssessment. Fo¡ certain threats, use ofthese tools mây be inappropriâte, Implementation ofprevention activities or more frequent maintenânceàctivities may provide a more effective solution. lnteg-rity âssessment methocl selection is based on the threatsfor whiclt lhe inspection is being performed. More thanone assessment method or more tlìan one tool nlây berequired to address all the threats. After each integrityassessmerìt, this portiorì of the plan shalÌ be r¡odifiedto reflect âll ncw information obtained and to provicle

for future integrity assessments at the required irìtervâls.The plan shall idertify required integrity assessmentactions and at wlìat estâblished intervals lhe actions willtake place. All i1ìtegrify assessments shall be prioritizedand scheduled.

thble 3 provides tlìl] integrity assessmenL schedulesfo¡ the exte¡nal coÌrosion and internal corrosion time-dependent threafs for prescriptive plans. Tlìe assessmentschedule fo¡ the shess collosiorì crackirìg threat is dis-cussed in Norìmar'ìdâtory Appendix A, para. A-3.4. Theâssesslnent schedules for all other thre¿ìts âre identifiedin approp¡iate chapte¡s of Nonmandatory Appendix Aunder the heading of Assessment lnterval. A currerìtplio¡itizatiol-r listing and schedr¡ìe shall be conLainedin tlìis section of the integrity management plan. Thespecifics for selecting integrity assessment methods âltdperforming the inspections are covered ir scctiolì 6.

A performance-based inte8rity management plalt calìprovide alternative integrity assessment, repair, and pre-venlion metlìods with different implelìrerìtation timesllìan those required undcr thc prcscriptive ptogram.These decisions shall be fully documerted.

8.3.4 Responses to lntegr¡ty Assessment, M¡t¡gat¡on(Repair and Prevention), ând lntervals. The plan shallspecify how and wlìen fhe opcrator wilì respond tointegrity assessments. The responses shall be immediate,scheduled, or monitored. The mitigation element of theplan consists of two parts. The fi¡st part is the repairof the pipelirìe. Based ()1ì tlìc results of the integ¡ìtyâssessments and the threiìtbeing addressed, appropriaterep¿ìir activities shall be determined and conducted.These repairs shall be performed irì accordance withaccepted standards alìd operâtirìg practices. The secondpart of mitigation is prevention. Prevention can stop o¡slow down future deterioration of the pipeline. Preven-tion is also an appropriate activity for tìme-independentthreats. All mìtigation activities shall l¡e prioritized andscheduled. The prioritization and sciìedule shall be mod-ified as new info¡mation is obtained and shall be a real-time aspect of tlìe plan (see sectiorì 7)

Tables 5, 6, and 7 provide an exarnple of an integritymanaBement pÌan in a spreadsheet format for a hypo-tlìeticaÌ pipeline segmerìt (lirìe 1, segment 3). Thìsspreadshect shows tlìe segment data, the ìrìtegrityassessûent plan devised based on Lhe risk assessment,and the mitigation plan tl.rat would be implcmentecl,il'ìcìuding the reassessment interval.

9 PERFORMANCE PLAN

9,1 lntroduct¡on

This section provides the performance plan requi¡e-ments thât apply to both prescriptive- and performance-based integrity management p¡ograms. PIan evaluations

27

( opyright O20lUbylhc^oìcricânSocielyoIMechanicalI-ngrnccrs. fftNo rcproductrorr may be rnådc ofrhis rnarerial willìoutwrillcnconscnlofASME.'(Ðl

asME 831.85-2010

Table 5 Example of lntegrity Management Ptan for Hypothetical P¡pelineSegment (Segment Data¡ L¡ne 1, Segment 3)

Segment Data Type

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Design/construction

Operational

Pipe grade

Sizewall thickness

l1¡anulacturerManufacturet ptocess

Manufacturi¡g dateSeam type

Operating pressure (high/low)0perating stressCoating typeCoating condition

Pipe lnstall dateJoining methodSoil iypeSoìl stabilityHydrostatic test

Comptessor discharge temperâturePipe wall temper¿tureGas quality

Repair methodsLeak/rupture historyPressure cycli¡gCP effectivenessSCC indications

API 5L-X42 (290 /MPa)

NPs 24 (oN 600)0.250 in. (ó.15 mm)

A. O. Smlth

1965Electric resistãnce weld

630/sso psig (4 340/3 79o kPa)72% Sl\,lYS

Coal tartair

1966Submerged ôrc weldclayGoodNone

120.F (49.C)

ó5.F (1S.C)

cood5O i\4MSCFD (1.42 MSms/d)

ReplacementNone

F¿ir

l\,lÌnor cracking

Table 6 Example of lntegr¡ty Management Plan for Hypothet¡cal P¡pel¡ne Segment(lntegrity Assessment Plan: L¡ne 1, Segment 3)

Criter¡a/Risk Assessnent lntegrìty Assessmenl À4it¡gationlnterual,

External colfosion

Intemal cofiosion

scc

11¡anufacturÌng

Construction/fabrication

Equipment

fhird.party dam¿ge

lncorrect operatìons

Weâther ãnd ourside for.e

Some external coÍosion history,no inline inspectlon

No history ol lC issues, no in'line inspectìon

Have found SCC ol near criticald imension

ERW pipe, joint factor <1.0,no hydrostätic test

No construction issues

No equipment issues

No third-party damage issues

No ope¡ations ¡ssues

No Lleather or outside forcerelated issues

Conduct hydrostatic Lest,perlorm in"llne inspec-tlon, or peform directassessment

Conduct hydrostaiic test,perform inline inspec-tion, or perform directassessmenl

Conduct hydrostatic test

Conduct hydrostatic test

None requÌred

None required

None required

None required

None required

Repìãce/repair locationswhere CFP below1.2 5 times the MAOP

Replace/repair locationswhere CFP below1,2 5 times the tllA0P

Repl¿ce pipe at teslfailure locations

Replace plpe at testfaìlure locations

l5

28

Copyrighl O 2010 by the Amencan Society of Mecha icâl Engineers &No be made of lhis material willloüt written consent of ASME

asME B31.aS-2010

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Table 7 Example of lntegr¡ty Management Planfor Hypotheticat Pipeline Segment

(M¡tigation Plan: Line 1,segment 3)

Description

indicators. Change shaÌl be monitored so the measureswill remain effective over lime as the pl¿Ìn mâtures.'l'helime requ;red to obtain sufficient data for analysis shallalso be colsidered when selecting performance mea-sures. Methods shàll be implemented to permìt bothshort- and lonB-term performance measure evâluations.lntegrity mana8ement plogram performance measurescan generally be câtegorized irìto groups.

9.2.1 Pfocess orAct¡v¡ty Measures. Process or activ-ity measures cân be used to evaìuâte prcvcntion or miti-gâtiorì âctivìties. Thesc rneasures dete¡mine how wellarì opc¡âto¡ is ìrnplcmenting various elcments of theinteg¡ity rnâr'ìageñcnt program. Measu¡es relating toprocess or âctivity shall be selected ca¡efully to permitperformance evaluatioû within a realistic time frame.

9.2.2 Operat¡onatMeasures. OpeÌationalmeasurcsinclude operational and maintenance trenc{s lhat mea-sure how well the system is ¡esponding to the integ¡ìtymanatement program. An example of such a meâsuremight be the changes in co¡rosion rates due to tlìe implc-mentation of a more effective CP program. The numbe¡of third-party pipeline hits after the implementation ofprevention âctivities, such as improving the excavatiotìnotification process within the system, is anotherexample.

9.2.3 D¡rect lntegrity Measures. Direct integritymeasures include leaks, ruplures, injuries, and fataÌities,In addition to the above categories, performance mea-sures can also be categorized as leadìng meâsures orlagging measures. Lagging measures are reactive in tlìatthey provide an indication of past ir'ìtegrity mana8ementprogram performance. Leading meâsures are proâctive;they provicle an indication of how the plan may beexpected to perform. Several examples of performancemeasures classified as described above are illustrated inllabÌe 8.

9.3 Performance Measurement Methodotogy

A1ì ope¡âk)r carì evaluate â system's integ¡ity manage-mclìt program performa|rce within theìr own sysLemand also by compa¡ìsorì witlì othe¡ systems on anindustry-widc basìs.

9.4 Performance Measurementr lntrasystem

(n) Performance metrics slìall be selected ancl appliedon a periodic l¡asis for tÌìe evaluation of bothprescriptive- and performance-based integrÌty manage-ment programs. Such metrics shall be suitable for cvalu-ation of local and threat-specific conditions, and Éo¡

evaluation of overall integrity management programperformance.

(û) Fo¡ operalors implemcnting prescriptive p¡o-grâms, pcrformâncc measuremelìt slìall include all of theth¡eaf-specìfic met¡ics for eâch threat in NonmandatoryApperìdix A (see Table 9). Additionally, tlìe following

Any hydrostatic lest iailure will be repairedby replacement of the entire joint of pipe.

Prevention activìties w¡ll ìnclude further moni-toring for SCC ai susceptible locations,rev¡ew of the cathodic prolection designand levels, and nronitoring for selectiveseam corrosion when the plpeline Ísexposed,

lnterual for The ìnterval for reinspection wiìl be 3 yr

reinspection if there was a failure caused by SCC. The

intervalwill be 5 yr if the test wassuccessful.

Data Test failutes for reasons other ihan extemaliñtegratìon or internal corrosion, SCC, or seam delect

must be considered when perlorming riskassessment for the associated threat,

GENERAL NOTE: For thrs pipeline segment, hydrostalic tesllng willbe conducted. Selection of this method is approp¡iate due io itsability to ¿ddress the inlernal and external corrosion threats as wellas the manufacturing threat and the SCC lhreat. The test pressurewill be ¿t 1.19 times the IMAOP

shall be performed at leastannually to provide a continu-ilìg measure ofintegrity management p¡ogram effective-ness over time. Such evaÌuations shoulcl conside¡ boththreat-specific and âggregate improvements. Thteat-specific evaluations may apply to a patticùlar area ofconcern, while overall measu¡es appìy to all pipeÌinesunder the integrity management progtam.

Program evaluatìon will help an ope¡ator answe¡ thefoÌlowing questiorìs:

(n) Were all integrity matìagement progrâÌn objectivesaccomplisÌred?

(D) Were pipeÌine integrity âncl safety cffectivelyimproved tlì¡ough the integrity mânaBement program?

9,2 Performance Measures Charactef¡stics

Performance measures focus attention on the ìntegrifymanagement prog¡am results Lhat demonst¡âteimproved safety lìas been attained. Ihe measures pro-vide an inclication of effectìvelìess, but ate not absoÌute.Performance measure evaluation and trending can alsolead to recognitiorì of ulìexpecled results that mayinclude the recognitiorì of threats not previously identi-fied. All performance measu¡es shâll be simple, measur-able, âttainâble, relevant, and permit tìmely evaluations.Proper selection and evaluaLiolì of performance mea-sures is an essentiaÌ activity in determìning irìtegritym.rn¡Bement progrâm (,f fecliveness.

Performance rneasurcs should be selected carefully k)ensure that they are reasonable program effectiveness

( opynghl O 201 0 by rhc ^mcricen

Socicry of Mcchânic¿l LnBiDecrs. fftNo reÞroducliorì may be nr¿de ofthis materral wilhout wntlen consent ofASMh. '(Od

ASME 831.8S-2010

Table 10 Overall Performance Measures

Miles (km) inspected vs. integrity management program requiremenlJurisdictional reporiable lncidents/safety-related conditions per unlt of tir¡eFraction of system included in the integrlty management progr¿rn

Number of anomalies lound requiring repair or m]tigationNumber of leaks repaÌredNumber of pressure test failures and test pressures [psi (kPa) and %SÀ4YSì

Numbe. of third'party damage events, near misses, damage detectedRisk or probability of failu¡e reduction achieved by integrity managernent programNumber of unauthorized crossings

Number of right'of-way encroachments:Number of pipeline hits by ihi¡d parlies due to ìack of notificatÍon as locate reqirest through the

one-call ptocess

Number of aerial/grou¡d patrol incursion detectionsNumber of excavation notifications received and their dispositionNumber and types of pubìic com¡nunications issued

Integrity ma¡agement program costsUnscheduled outages and impact on cuslomeß

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overâll program measurements shall be deterÌnìned arìddocumented:

(1) numbe¡ of miles (kilometers) of pipelineinspected versus prog¡am requirements

(2) numbe¡ of immediate repairs cornpleted as aresult of the integrity management inspection program

(3) number of schedulecl repairs completed as aresult of the integrity mânagement inspection program

(4) number of leaks, failures, and incidents (classi-fied by cause)

(c) For operators implementing performance-basedp¡ogrâms, the threat-specific metrics slìow1ì illNonmandatory Appendix A shall be considered,altlìough others may be used that are more app¡opriateto tlìe specific performance-based program. [n additionto the four rìleLrics above, tlìe operator slÌould choosethree o¡ four metrics thât measure Lhe effectiveness ofthe performance-based program. Table 10 provÌdes asuggested list; lìowever, the operator may develop their.own set of lnetrìcs. It may be app¡opriate and useful foropelators to norrnalize the findings, events, and occur-rences listed in Tabìe 10 utilizing notmalization factorsmeaningful to thc operator for that event and their sys-tem, and that would help Lhem evaìúate trencls. Suchnormalization factors may inclLrde covered pipelinernileage lenglh, nurnber of customers, time, or a combi-nâtion of these or otlìe¡s. Since performance-basedinspection intervals will be utilized in a perforrnance-based integrily managemenf program, iI is essentiâÌ thatsufficicnt metric data be collccted lo support thoseinspection inteNals. Evalua[ion shall be performed onat leasL an a¡nual basis.

(d) In addition to performânce met¡ic clata collecteddirectly from segmelìts covered by the integrity manage-ment program, ì1ìternal benchmarking can be conducted

that may compare a segment agaiìst another adjacentsegment or those from a different areâ of the same pipe-line system. The information obtained may be used toevaluate the effectiveness of prevention activities, miti-gation teclìniques, or performance validation. Such com-parisons can provide a basis to substantiâte metricanalyses and identify areas for improvernents in theintegrity management program.

(¿) A third technique tlìat will provide effective infor-mation is internal auditing. Operators shall conductperiodic audits to validate the effectiveness of theirirìtegrity mênagement programs and ensure that theyhave been conducted in accordance with tlìe writtenplan, An audit frequency shall be established, consider-ing the established pe¡formance metrics arìd their partic-ular time base in addition to changes or modificationsmade to the integrity mânâgement progrâm as itevolves.Audits may be performed by internal staff, preferablyby personnel r'ìot directly involved in the administrationof tlìe inte8rity mana8ement p¡ogram, or othe¡tcsources, A list of essential audit items is providedbelow as a startìng point indeveloping â company audit

Progrâm.(1) A written integrity mênagement policy ancl pro-

gram for all the elements in Fig. 2 shail be in place.(2) Writtcn integrily management pìan procedures

and task descriptions are up to date atìd readilyavailaìrle.

(3,) Activities are perÉormed i¡ accordance withthe plan.

(4) A responsible individual has been assigncd foreaclì element.

(5) Appropriate references are available to respolt-sible indivicluals.

31

Copyright O 2010 by the Arnerican Sociely ofMecha¡icâl Éngineers. fftNo rcprcductio0 lnay be lnade ofthis mâteriâl without written consetìt ofASME. YÐ{

asME 831.85-2010 õlq

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(6) lndividuals have ¡eceived proper quâlification,which has been documented.

(Z) The integrity mana8ement p¡og¡am meets tlìerequirements of this documenl,

(8) All required activities are documentec{.(9) All ¡ction items or nonconformances are closed

in a timely manne¡.(10) Ihe risk c¡iteria used have been reviewed and

documented.(11) Prevention, mitigâtion, arlcl repaiÌ crite¡ia lìave

been establìshed, met, ând documented.

f) Data developed from program specific perform-ance metrics, results of inte¡nal benchmarking, anclaudits shall be used to provide an effective basis fo¡evaluation of tlìe ìnteg¡ity marìagemenl program.

9.5 Perfofmance Measurement: lndustry Based

In addition to intrasystem compârisons, exterral com-pârisons calì provide a basis for performance measure-mer'ìt of tlìe integrity management program. This canìnclude comparisons with other pipeline operators,industry data sources, and jurisdictiolìaÌ dâta sources.Benchma¡king witlì otÌìe¡ gas pipeline ope¡ators can beuseful; however, any performance measure o¡ evaÌua-tion derived from such sources shall be carefrrlly evalu-ated to ensure thât all comparisons mâcle àre valid.Audits conducted by outside entities can also provideuseful evaluation clâta.

9.6 Performance lmprovement

The resulls of tlre performance meâsurements andâudits shall be utilized to moclify the integrity mânage-ment program as part of â centinuolrs improvementprocess. Inlernal and external audit resr"rlts are perform-ance meâsures that should be used to evaluate effective-ness in addition to other measu¡es stipulated in tlìeintegrity mânagement program. Recommendationsfor cìranges alìd/or improvements to the integritymanagement program shall be based on analysis of theperformance measu¡es ând audits. TÌìe results, recom-mendations, and resulfant changes made lo the integritymanagement program shâll be documented.

1O COMMUNICATIONS PLAN

1O.l General

The operator shall develop and implemerlt a commu-nications plan in order to kcep appropriate companypersonnel, jurisdictìorìal authoritìes, ând the publicinformed about their ìùteg¡ity mâr'Ìagement efforts andthe ¡esults of their integrity management activities. Theinformation may be communicated as part of otherrequired commulìications.

Somc of tlìe informàtion should be communicatedroutinely. Other information may be communicated

upon request. Use of irìdustry jurisdictìonâÌ, arìd company wcbsites rìray be an effectìve way to conduct thesecommùnication efforts.

Communications should be conducted as often as nec-essary to ensure lhat appropriate indìviduals andautlìorities lìave currcnt ìnformatiorì about tlìe ope¡a-tor's system arìd thei¡ jntegrity lnalìagemeùt efforts. Itis ¡ecommended that communìcatìolìs take place peri-odically aùd as often âs rìecessary to coùürìunicate sig-nificânt changes to thc inte¡yity malìâgemer'ìt plan. APIRecommended Prâctrce7762, P blic Aruiretlcss Prograt s

for Pipclítrc Opcrotors, provides additional guìdance.

10.2 External Commun¡cations

Tlìe followirìg items should be considered for commu-lìication to the various intercsted parties, as outlinedbelow:

(n) Iandotoners nncl Tetntlts Aloug the Ríghts-oÍ-Wly(1) company name, location, and contact

informatÌon(2) general location information and wher€ more

specific location informatiolì or maps can be obtained(3) comrnodity transported(4) how to recognize, report, ând respolrd to a leak(5) contâct phonc numbers, both routìne arìd

emcrgcncy(6) general informatiorì âbout the pipeline opera-

tor's prevention, inlegrity measures, arìd cmergency preparedness, and how to obtâin a summary of the integritymanagement plan

(Z) damage prevention informâtion, includingexcavation notification numbe¡s, excavation notilicationcenLer requirements, and who to contact if there is anydamage

(b) Pul:lic Officinls Oflrcr TIn¡t Energettcr¡ llespotders(1,) periodic distributiorì to each municipâlity of

maps and company contâct informâtiolì(2) summary of cmergency preparedncss and

ir'ìtegrity lnanâ¡lcment p¡ogram(c) Locnl øttl Regiotlnl Ë, tergetrcy llespotlders

(1) operator should maintain contìnuing liaisonwith all emergency responders, includirìg local emer-gency planning commissiolìs, regional and area plan-nìng committees, ju¡isdictionâl emergency planningoffices, etc.

(2) company name and contact numbers, both rou-tjne and emergency

(3) Ìocal maps(4) facility description aiìd commodity transported(5) how to recognize, report, and respond to a leak(6) general info¡mation about the operator's pre-

vention and integrity measures, ancl how to obtai¡ a

summary of the integrity manatement plalì(7) statio¡ locatioDs and descriptions(B) summaly of operator's emergency capabilities

32

CoplrightO2ulUb) rhe^mellcallsocrelloIMechanicalEnginee|s. f&No rep¡oductio,ì rnay bc nradc ol-this matcrial wilhour wrirrcn consenl of^SMË. '(Ex

asME Bl1.as-2010

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(9) coordination of operator's emergency prepared-ness witlì locâì officials

(tl) Gener¡l Pul¡líc(1) information regarclilìg ope¡ator's efforts to sup-

port excâvatiorì rìotification and otlìer damâge preven-tion initiatives

(2) company rìame, cor'ìtact, and emergencyreporting information, including general businesscontact

It is expected that some dialogue ûray be uecessarybetyr'een the operato¡ âlìd the public in orcler to conveythe operator's confidence in the integrity of the pipeline,as well as to corìvey the operator's expectaliolìs of thepublic as to wlìere they carì heÌp maintain integrity.Such opportunities should be weÌcomed in order to helpprotect assets, people, and the envitonment.

10.3 lnternal Communications

OPerator management and othe¡ approprìate opeta-tor pe¡sonnel must understatìcl and súpport the integritymanagement program. This should be accomplishedthrough the development and implementation of anirìlernal communications aspecf of fhe plan. Petform-ânce meâsLlres Ìeviewed on a pcriodic basis andresultirìg adjustments to the integrity mânâgement pro-gram should also be part of the inte¡nal communica-tions plan.

11 MANAGEMENT OF CHANGE PLAN

(n) Formal management of clìange procedu¡es sÌrall bcdeveloped i¡:r order to identify and consider the impact ofchanges to pipeline systems ând their integrity. Theseprocedures should be flexible enough to accommodateboth major and minor changes, and must be understoodby the persolìnel that use them. Management of cltangeshall adcl¡ess technical, physical, procedural, and organizâtional changes to tlìe system, whethel permanent or.teùporary. The process should incorporate planning foreach of these situâtions and considel the unique circum-stances of each.

A mânâgement of change process includes thcfollowing:

(1) reason for change(2) authority for approving changes(3) analysis of implicâtions(4) acquisition of required work permits(5) documenl¿rtion(6) communication of change to âffecled parties(7) time limitations(8) qualificâtiolì of staff

(b) The operator shalì recognize lhat system chângescan require changes in the integrity managemetìt pro-gram alìd, conversely, results from the progra¡n cancause system clìânges. Ihe following are examples that

¿ìre Bâs-pipeline specific, brÌt are by no meals all-inclusive.

(1) If a change in lând use would affect eitlìcr thecortsequence of an incident, suclì as increases in popula-tiorì near the pipeline, or a change in likelihood of arìincident, such as subsidence due to unde¡Bround mir'ì-ing, the change must be reflected in the integrity rnalì-âgemenl plan and the threats reevaluated accordingly.

(2) If the results of an integrity maragement pro-g¡arn inspectiolì indicate tlìe lÌeed for ¿ì chânge to tlìesysteln, such as changes to lhe CP progrâm or, otlìerthan temporary, reductions irÌ operating pressu¡e, tlìeseshall be communicaled to operators and ¡eflectecl in anupdated integrity mana8ement pro8ram.

(3) lf an oper.rtor decides to increasu pressure inthe system from its lìistorical operating pressure to, otcloser to, the aÌlowable MAOB that clìange slìall bereflected ìn tlìe integrity plan and the threats shall bereevaluated accordingly.

(4) lf a line has been operatirìg ì1ì a steady-stâtemode and â ne\4 load on tlìe line clìangcs the mode ofoperatiolì to â more cycÌìcal load (c.g., daily changes inope¡atìlìg prcssure), fatigue shaìÌ be consideted in eacllof the threals where it applies as an âdclitional stressfactor'.

(c) Along with management, the review procedureshould require involvement of staff that can assess safetyimpâct ând, if necessary, suggest controls or modifica-tions. The operator slìall have the flexibility to mair'ìtaincontinuity of operation within established safeoperating limits.

(d) Malìagement of change ensures that the integritymanagemclìt process ¡emains viable and effeclive asclìalìges to the system occu¡ and/or new, revised, orcorrected data becomes available. Any change to equip-ment or procedures has the potentiaì to affect pipelilìeintegrity. Most chânges, however small, will have â cor'ì-sequent effecton a\otlìeraspect of the system. Forexam-ple, many equipment changes will requi¡e acorresponding technicaÌ or procedural change. Allchanges shall be ìdentifiecl and revicwed before impte-mentatiorì. Malìâgement of change procedures providesa meâns of maintairìing order during periods of changein the system and helps to p¡eserve confidence in theintegrity of tlìe pipeline.

(c) In order to ensu¡e the integrity of a system, a

documented reco¡d of changes should be developed andmâintained. This information will p¡ovide â betterunderstandi¡g of the system and possible threats toits integrity, It should include the process and designinformatiorì both before and after the cÌìanges we¡e putinto pÌace.

(, CorÌlmunìcatìon of tlìe clìârìges câr¡ied out in tlìepipeline system to any affected parties is imperative totlìe safety of tlìe system. As providcd in section 10,communicâtions rega¡ding the ir'ìtegrity of the pipeline

33

Copyright O 201 0 by the ^m€rican

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(,9) System clìânges, particularly in equipmelìt, mayrequire qualìficafion of personnel for the correct opera-tion of the new equiprnent. ln addition, Ìefresher train-ing should be providcd to elìsute that facility personneluncle¡stand and adhe¡c to the fâcility's current operati¡gP¡ocedlr¡es.

(û) Ihe application of new rech¡ologies in the integ-rity management program and thc resuìts of such appli-câtìons should be clocumented and cornmunicated toâpp¡opriale staff ancl stakeholders.

12 QUALITY CONTROL PLAN

Tlìis sectiorì describes the quâlìty colìtrol activitiesthat shall be part of an acceptable integrity managementProgram.

12.1 General

Quolitr¡ cottttol as defined for this Code is tlìe "docu-lnented proof that tlìe operator meets all tlìe require-ments of thei¡ integrity management program."

Pipeline operators tlìat hâve a quality control p¡ogrâmthat meets or exceeds the requirements in this sectiorìcan incorpo¡ate the inlegrity mânagement programactivities withilì their existing plân. For those operatorswho do not have a quality program, this section outlinesthe basic requiremelts of such a program.

12.2 Quality Management Control(d) Requirements of a quality control program include

documenlation, implementation, and mairìtenance. fhefollowing s¡x activities are usually required:

(1) ictentify tlìe processes thât will be ilcluded inthe quaÌily program

(2) determine the sequence alìd interaction of these

Processes(3) determine the c¡iterìa and methocls needed to

ensure that both tlìc operation ancl control of these pro-cesses âre effcafivê

(4) provide the resources and info¡mation neces-saly to support the operatiolì and monitorirìg of these

Processes(5) morìitot measure, and analyze tlìese processes(6) implement actiotìs necessaty to âchieve planned

¡esuÌts and contilìued improvement of these processes(û) Specifically, activities that shouÌd be incÌuded in

the quÂlity control program are as follows:(1) dctermine the documentatíon required and

include ìt ¡r the quaìity program. "fhese documents shâllbe cont¡olled and maintaiÌted at appì.opriate locâtiolìsfoì the duratior'ì of tlre prograrn. Examples of docu-mented activities ilìcludc risk assessnents, tlìe integrity

management pLan, integrity maragement reports, andclata documents.

(2) the responsibiÌilies ancl authorities uncler thisprogram shall be cÌearly and folmally defined.

(3) ¡esults of the integrity management programând the quality control program shall be reviewed âtpredelermined intervals, making recornmendations folimpÍovemelìt.

(4) the personneÌ involved in the integrity manage-ment progrâm slìall be competent, aware of the programancl all of its âctivities, and be quaìilied to execute tlìeactivities witlìin the program. I)ocumentation of suchcompetence, âwaleness, and qualificatìon, and the pro-cesses for their achìevement, slìall be pâ¡t of tlìe qualitycontrol plan.

(5) the operator shall determine how to monitorthe inteBrity management pÌogram to show tlìat it isbeing implernented accordìng to plan and docunentthese steps. Thcse control points, criteria, and/or per-formance metrics shall be definecl.

(6) periodic internal audits of tlìe ilìtegrity mânage-ment p¡ogrâm ârìd its quality plan are recommended.An indeperìdent thi¡d-party ¡eview of the entire pro-Brâm may also be useful.

(7) correclive actions to inìprcve the integrity man-agement program or quaÌity plan shall be documerìtedând tlìe effectiveness of thei¡ implemerìtâtionmonitorecl.

(c) When an operator clìooses k) use outsicle resourcesto coùduct any process (forexample, pigging) thatâffectstlìe quality of the i1ìtegrity malìâgement program, theopC]rafor shall ensure control of such processes and docu-ment theDì within the quality prograrn.

13 TERMs, DEFINITIONS, AND ACRONYMS

See Fig.5 for the hierarchy of terminology for integrityassessmenl.

ncLio nble nllotlrily: anomalies that may exceed acceptablelimits bâsed on the operatorb anomaly and pipelir'ìeclata analysis.

nctiae corrosíor1: corlosiorì thât is corìtirìuing or notarrested.

ntttulnr fùlcd snddle: an external steel fabrication, similarto a sleeve, except one half is pierced and forged toprovide a cìose fit around a hot tâp "T." Thc other halfaway from thc "T" is joìrìcd with seam welds like a

type A sleeve. The annular space between the pressurecontainin8 pipes ancl the sadclle is filled with an incom-pressible material to provide mechanical support to thewelded "l'."

ollomIly: at\ uncxâmined deviation from the norm inpipe material, coatings, or welds.

34

Copyright O 2010 by the Àmericân Society o f Mechanical Engineers &No nlay be rnâde ofthis rnaterial without written conscnt ofASME.

ASME 831.85^2010

Fig. 5 H¡erarchy of Terminology for lntegr¡ty Assessment

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ntlot nlll ¡t1d pípelù1e dati ¿,?nlysisr the process throughwhich anomaly and pipelir'ìe data are integ¡ated andanalyzed lo further cÌassify and characte¡ize anomalies.

nrc ueltling ar nrc zoeld: group of welding processes thatproduces coalesccnce by heatjng them with an arc. Thep¡ocesses are used with or without the application ofpressure and with or wìtlìout filler metal.

lsnckfíll: matetial placed in a hole or trench to fill exca-vated space around a pìpeÌine or other âppu¡tenances.

Dntc,û; a volume of liquid that flows ell masse in a pipelincphysically scparated from adjacent volume(s) of liquidor gas. [Sealing (batching) pigs are typically used fo¡separation.]

Del/,f¡ol¿: excavation that minimizes surface distu¡banceyet provides sufficient room foÌ examinatiorì o¡ repairof buried fâcilities.

¿ruckl¿r condition in which the pipeline has undetgolìesufficient plastic deformation k) cause permanent wrin-kling in the pipe wall or excessive ctoss-sectional defo¡-mation causcd by bending, axial, impact, and/or

torsional loads acting alone or in combination withlìydlostalic pressure.

cnlìl¡rntion dE: exploratory excavation lo vaÌidate find-ìngs of an in-line ilìspection tool witlì the purpose ofìlnproving data interpretation.

caliper tool or geoüteLry fool; an instrumenled irì-lineinspection tool designed to record conditions, such as

dents, wrinkles, ovâlity, bend râdius, ând angle, by sens-in8 the shâpe of the internal surfâce of the pipe.

anbotl tlioxide: a heavy, colorless gas that does not sup-port combustion, clissolves in water to form carbonicâcid, and is fi¡und in some natural gas stleams.

cds¡ llorii unqualified term "câst iron" shaÌl âpply to g¡âycast iron, wlìich is a cast fe¡rous material in whiclì amajor part of the carbolr contelìt occu¡s âs free ca¡bonin tlìc fo¡m of flakes inlerspersecl throughout tlìc metal.

citllotlic ptotcctio| (CP)j techr'ììque to reduce lhe corrosionof a metal surface by mâkin8 tlìat surfâce tlìe cathodeof an elect¡omechanical cell.

ccrtificatiotl: written testimor'ìy of qualification.

35

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chnlIcterize: to qualify the type, size, slìape, o¡ientation,ând location of ârì anomaly.

close ítltetanl sutaelJ (CIS): inspection technique thatìncludes a series of abovegrour'ìcl pipeto-soiÌ potentialùìeasurements taken at predetermilìed increments of afew to several feet (meters) along rhe pipeline and usedto p¡ovide info¡mation on flìe effectiveness of thecatlìodic protection system.

contùl4: liqvrd, Iiquefiable, or mastic compositìon that,after applicatiorì to a su¡face, ìs converted into a solidprotective, clecorative, or fulrctional aclherent film. Coal-ing also includcs tape wrap.

contiùg sysfem: complete number and types of coatsapplied to a substrate in a predctermined order. (Wlìenused ilì a broader sense, surface preparation, pretrcat-merìts, dry film tlìickness, and manner of applicationare included.)

conlpotletll or pipelitle co lponent) ân individual item orelement fittecì in liûe with pipe in a pipeline system,such as, but not limited to, valves, elbows, tees, flanges,and closures.

cotnposite repnif s/¿¿¡)¿i permanent repâir method usingcomposite sleeve mâteriaì, which ìs applied with anadhesive.

collsequetlce: \mpact thât a pipeline failure coulcl have onthe public, empìoyees, property, and tlìe environment.co¡'rosro,li deterioration of a material, usually ¿.r ÌÌetal,tlìat results from an electroclìemical ¡eaction with itselìvironmelìt.

co1'tosiotl iullil)ifor: chemical substânce or combìnation ofsubstaiìces that, wlìetì present in the environment or 01ìâ surfâcc, prevents or roduces corro,ìi(ìn.

corrosiotl rate: rate ât which corrosìon proceeds.

c¡?c&i very narrow elongated defect caused by meclìân!cal splitting into two parts.

ctîrent: flow of electric charge.

dntl lnlysís: tlìe evalu¿ttion process through whichinspection indicatiorìs are classifiecl and cha¡acterized.

.lefect: a pl\ysicãlly examined a1ìomâly with dimensionsor clìarâcteristics that exceed acceptable limits.dcnf; permanent deformation of the circular cross-scctionof the pipe tlìat produces a decrease in tlìe cliameter andis concave inward.

d¿f¿c¡r Lo senseor obtain measurable wallloss indicationsfrom an anomaly in â sfeel pipeline using inline jnspec-tion or otlìer technoìogies.

clinntetet or tominal oufside dinnrefer as-produced or as-specified outside diameter of the pipe, not tobeconfusedwitlì lhe dim'rnsionless NPS (DN). lìor example, NPS 12(DN 300) pipe has a specified ou tside diameter of12.750 in. (323.85 mm), NPS 8 (DN 200) pipe has a speci-fied outside diâmeter of 8.625 in. (219.08 mm), and

NPS 24 pipe has a specified outside dìâmeter of 24.000 in.(609.90 mm).

dilecl cruletlt aoltngc gndient (DCVG)] inspection fech-nique flìaf includes aboveground elect¡ical measure-ments takerì ât predetermined increments along thepipelìr're and is used to provide infotmâtion on the effec-tiverìess of the coating system.

docut etltctl: condition of being in written form.

double subutrged-øc ueldecl pipe (DS.4W pipc)r pipe thatl-ras a strai8ht longitudinal or helicaÌ seam containìrìgfiile¡ metal deposited o¡ both sides of the joint by tlìesubmerged-arc welded process.

drc¡i¡rfyi ùìeâsure of the capability of a materiâl lo bedefolmed plasticalLy before fracturing.

ÈC,4i en8ineering ânalysis supported by tests that esti-mâte tlìe interval of contir'ìued safe operations. EC^ isoften used to evaluate defects as it is less consetvativethan traditional criteria and supports an extension ofthe repair or replace interval. ECA offers const¡uctiveguida|ce for automâtic (ltrasonìc testing qualificationssuch as flaw type, equipmenf typc, flaw detection uncer-tainties, and flaw sizing.

electric resistntrce uekled pipe (ËIlW pipe)r pipe that has âstraight ìorìgitudinal seam produced without the additiorì of fiÌle¡ metalby the application ofpressure and heâtobtained from electrical resistance. EIìW pipe forming isdistinct from flâslì welded pipe and furnace butt-weldedpipe as a result of being produced in a continuous form-ing process frorn coìls of flat plate.

elec!tulyle: meclium containing ions that migrate in aneìectric field.

etloirolnlenl: surroundings or conditions (physical,chemical, mechanical) in whìch a mate¡ial exists.

¿po.yyi type of resin formed by the reaction of aliphatic oraromatic polyols (like bisphenol) with epichlorol.rydrilìand characterized by tlìe presence of reactive oxiratìeend groups.

eualuntiolL a tevrew, following the characteÌizâtion of anâctionable anomal, to determine whether the ar'ìomalymeets specified acceptÂnce crite¡ia.

cxÌu1i1lûtio\: drrect plìysical ilìspection of â pipeline thatmay include tlÌe use of nondesf¡uctive examination(NDE) techniques or methods.

expeticûce: work actjvities accomplishecl in a specifìcNDI rnethod under the direction of qualificcl supervisior.r including fhe performance of the NDT method andrelated activities but not includi[g time spenf in orga-nìzed training pro8râms.

fnilure: general term used to imply that a part in servicehas become completely inope¡âble; is still operable butis incapâble of satisfactolily performing its i¡ìtenclediunction; or lìas deteriorated seriousÌy, to the point thatis has become unrelìable or unsafe for contitìued use.

36

Copyright O 20t0 by the Anìerican Society ofMechanical Ënginecrs. ÁùNo reDroduction mav be ¡nade ofthis nìâterial w¡thout writtcn consÃt ofASME. qðÈ

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fafigue: process of development of or enla¡gemenl of acrack as a result oi repeated cycles of stress.

JenLtre: any p\ysical object detected by an inline inspec-tion syslem. Features mây l:e anomalies, components,nearby metallic objects, welds, or some other item.

filtn: t6in, not necessarily visible layer of material.

gnlunnic corrosio : accele¡ated cor¡osion of â metalbecause of an electrical contact with â mo¡e r'ìoble metaland/or a more noble localized section of the metal ornonmetâllic conductor i1ì a corrosìve electrolyte.

gnsr as used iÌr this Code, any gas or mixture of gâsessuitable for domestic or industrial fuel and trâ1ìsrnittedor dist¡ibuted to the user through a piping system. 'Ihecommon Lypes are natural gas, manufactured gas, andIiqttefied petroleüm gâs distrìbuted as a vapor, with orwithout the admixtüre of âirgns processitlg plnnt: facility used fo¡ exttacting comme¡-ciaÌ products from gas.

gntlrcríttg systen: one o¡ rnore segments of pipeline, usu-âlly interconnected to form a netwotk, that ttanspo¡tsgas from one or more production fâcilities to the inletof a gas processìng plant. If rlo gas processing plantexists, the gas is tlanspo¡ted to the most downstreamof eitlìer of the following:

(a) the point of custocly transfer of gâs suitable fordeÌivery to a clistribution system

(lt) the poirìt where accumulation alìd p¡epâratìon ofgas from sepârate geographic production fields in rea-sonable proximity has been completed

geographic irrÍornatiotl systenl (GIS): system of computersoftware, hardware, data, ¿ìnd personnel to help manipu-late, alìalyze, and present information that is tied to ageographic location.

girth weld: compìete circumferential butf weld joiningpipe or components.

globIl positioniilg slsten (GPS): system used to identifythe latitude and lolìgitude of locatìoûs using GPSsatellites.

gonl¡e: mechanically indr.rced metal-ìoss, whìch causeslocalized eÌongated grooves or cavities ìn a rnetalpipeÌiûe.

higlt-prcssu'e distributiotl s:lste t: gas distributioÌr pipingsystem that operâtes at â pressure higher than tlte stan-dard service pressure delive¡ecl to the customer. hì suclìa systcm, a service regulator is required on each serviceline to control the pressure delivered to tlìe customer.

hydragen-ittclucecl clntlnqe: form of clegradation of metalscaused by exposure to environments (lìquid or gas) thatallows absorption of lìydrogen iltto the material. Exam-ples of hydrogen induced damage are formation ofinterlìal cracks, blisters, or voids in steels; embrittlemetìt(i.c., loss of ductility); and high-temperature hydrogen

attack (i.e., surface decarburization and chemical reâc-tion with lìydrogen).

hydragen sulficle (HzS): toxic gaseor¡s impurity found insome welÌ gas streams. It also can be gene¡âted in situas a result of microbiologic activity,

IlytltosliLic lest or hlldralesL: a p¡essure test using wateras the test medium.

iltlpetfcctiotl: aî a\onaly with characteristics tlìat clo notexceed acceptabìe limits.

ir?cirl¿¡rfl unintentioiìal rcleâse of gas duc to the failureof a pipeline.

l¡rcfuslol: nonmetallic phase such as an oxide, sulfide,or silicate particle in a metal pipeline.

i11¿licnlioll: f\r.dr g of â rìondest¡uctive testing techniqlreor mcthod that deviâtes from the expected. It may ormay not be â defcct.

Ìtt-litrc ittspection (ll,l)i steel pipeline inspection techniquethat uses devices known in the jndustry as intelligentor smart pigs. "Ihese devices run insÌde the pipe ândprovide indications ofmetal loss, deformatiolì, ând otlìerdefects.

itrscro ice p ipeline: clefined here as a pipeline lhat contaitìsnatural gas Lo be transpoÌted. The gas may or may noLbe flowing.

inspecLí11l: use of a nondestructive testing technique ormethod.

i¡?f¿Sr.lfy: defìned lìere as the capability of the pipelineto withstarìd âll anticìpated loads (including hoop stressdue to operating pressure) pltts the mârgin of safetyestablished by tlìis section.

itltegrîly issess teut: pÌocess that includes inspection ofpipeline lacililies, evaluating the indications resultingfrom the inspections, examining the pipe using a va¡ietyof techniques, evaluatilìg the results of the examinations,charâcte¡izing theevaluationby defect type and severity,ând determining the resulfing integrity of the pipelinethrough ânâÌysis.

Iautcher: pipeline facility used to insert â pig into a pres-surized pipeline, sometimes referrcd to as a "pig trap."

/¿øk: unintentional escape of gas from the pipeline. Thesource of tlìe leak rnay be holes, c¡acks (include propa-gatilìg and norìpropagating, longitudìnal, ârìd circum-fererìtiâì), separation or pullout, ând loose connections.

Ieüg t: a piece of pipe of the length delivered from themill. Each piece is called a lengtlr, regardless of its actualdimension.'1'his is sometimes caÌled a "joint," but"lengtlì" is preferrcd.

liquefied peholeunr gns(es) (LPC): liquid petrolcum gasescomposed predominantly of the following hydlocar-bons, eilher by themselves or as mixtures: butâne (nor-rnâl butar'ìe or isobutane), butylcne (including isomers),proparre, propylene, ând ethânc. LPG can be stored as

37

Copyright O 2010 by the Aùrerlcân Socìety of Mechanical Engileers &No be made ofthis rnaterial without writlen conse'ìt of ASMIT.

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liquids under' ¡noderate pressures (approximately80 psig [550 kPa] to 250 psig [l 720 kPa]) ât ambienttemperatures.

lotu-pt esvu e clístributioú systenl: gas distribution pipingsystem in which the gas pressu¡e in the mâins ând ser-vice lines is substantially the same âs that deliveted tothe customer's appliances. In rìuch a system, a setvice¡cgulator is not required on tlìe individual service lines.

lou sttcss pipelù1e: pipeline lhat ìs operat(rd in its entiretyat a hoop stress level of 20% or less of the specifiedmirìimum yield strentsth ol (he lirìe pipc.

t1i0g'teL¡c flur lcoknge (MFL): ân in-line inspectiorì tech-nique that incluces a magnetic field in a pipe wallbctween two poles of a m¿ìgnet. Serìsol.s record statusin leakage in this magnetic fÌux (flow) outside the pipewall, which cân be correì¿ìted to metal loss.

nlngtlctic pitticle hlspcctioil (MPI): â nondest¡uctive testmethod utilizing magnetic leâkage fields ând suitableindicÂting materiaÌs to clisclose surface and nea¡-surfacediscontinuity indications.

latingetle\t of cln,tger process tlìat systemalically recog-nìzes and communicates to tlìe necessary pâttieschanges of a technìcal, physical, proccdural, or organiza-tional nature lhat can impact system ìnfegrity.

ûtlxit n 0Ilollûb\e opernting ptesuu,e (MAOP): maximumpressure at which a pipeline system may be operatcdin accordancc with the provisions of the ASME 831.8Code.

ntrclnüicol dntuoRt: Lypc of met.tl d¿m,ìgc in .r pipe orpipe coatinB causecl by tlìe applicâtion of an extetnalfo¡ce. Mechanical darnage can jnclude clentirì¡j, coating¡emoval, metal removal, metal movement, cold workingof the underlying metaÌ, punc[uring, alld tesidual

rl?¿lnl /ossj types of anomalies ilì pipe in which metaÌ hasbeen removed from the pipe surface, usually due tocorrosion or gouging,

nic robìologicall y i nflwtcerl corrosíot.r (MIC): cor¡osion ordeterioration of mefâls resulting ftom the metabolicactivity of microorgânisms. Such cottosìon may be initi-ated or âccclcrated by microbìal activity.

lltitigatian: limitation or reductiorì of the probability ofoccurrelìce or expected consequence for a particulaaevent,

ü1unic¡pnliLy: city, courìtt or âny othe¡ political subdivi-sion of â State.

notldcsh uct ioe exntlli nnLion (N D F-) or nondcstruct iae testi t1 g(NDT)r testing method, sucÌr as ladiography, ultrasonic,magnetìc testing, Ìiquid penetrant, visual, lcak testing,eddy current, and acoustic emission, or a testing teclì-¡ique, such as mâgnetic flux leakage, magnctic pârticleinspection, shear-wave ultrasonic, and contactcompression-wave ult¡asonic.

operatiûg strcss: strl]ss in a pipc or structural memberunder norlÌìal operating colìditions.

oper1tor or operntitlg co 1pa11y: ìrìdìvidual, pa¡tnership,corporatiorì, public agelìcy, owlìe¡, agent, or other entitycurrently responsible fo¡ tlìe desiglì, consLtuction,inspection, testing, operation, and mâirìtenârìce of thepipeline facilities.

pctfannatrce-bnsed íütcgrity tüIiiogeùie l prog,'rÌ17r ir'ìtegritymanagement process tlìat utilizes risk managemer'ìt prin-ciples and risk assessmerìts to determine prevelìtion,detection, and mitigation acLions and tlìei¡ timing.

pþ: device run iiìside a pipeline to clean or inspect thepipeline, or to batch fluids.

pig.gi¡gr usc of any independent, self-contained device,tool, or vehicle tlìat moves through tlìe interior of tlìepipeline for inspecting, d imensioning, cìeaning, or'clrying.

pipe: a tubular product, irìclucìing tubing, made for sâìeas a pìoduction item, used primarìly for conveying â

fÌuid and sometimes for storage. Cylinclers formed fromplate during the fabrication of auxilìary equipment â¡enot pipe as defined helein.

pÌpe grcde: potlio of the material specification for pipe,which includes specifiecl minimum yield strength.

pip¿lirr¿: all parts of physical facilities through which gasmoves in trâlìsportâtion, incìuding: pipe, valves, fittings,flanges (inclucling bolting ând Baskets), reguÌators, p¡es-surc vessels, pulsation dampeners, relief valves, appur-terìances attached to pipe, compressor units, meteringfacilities, prcssure regulating stations, pressure ¡elief sta-tiorN, and fabricated assemblies. Included within thisdefirìition a¡c gas transmission and gathering Ìines,which transportgas from production facìlities toonshoreIocations, ând gas storage equipment of the cÌosed-pipetype, which is fabricated oÌ forged from pipe or fabri-cated from pipe a1ìd fittings.

pipelille ficilit!!: new and existirìg pipelines, rights of-way, and any equipment, facility, or buildirìg used inthe transportation of Bas or in the treatmer'ìt ofgas duril-rgthe course of transportalion.

pipelitß sectioll: cot'tfinuous run of pipe between adjaccntcompressor stations, between a compressor station atìda block valve, or between adjâcent block valves.

pipc-to-Êoil potctrti0l: electric potential differencc betweentlìe sûrface oÉ â buried or strbmerged metaÌlic structureând th(] electrolyte that is measured with ¡eference toân electrode in contact with tlìe electrolyte.

pípitrg otrtl instr nletlldt¡ot1 diagrnm (PùlD): drawingshowing the piping and irìstrumentation for â pipeiineor pipelirre facility.

pittilry: Io. Iized co¡¡osion of a metal surface tlìat isconfined to â small area and takes the form of caviticscaìl(¡d pits.

38

Copyright O 2010 by tbe Arnerican Society of N4echanical Engilìeers. f"qNo repmduction

'Ìay be rüadc oflhis material wtlhout writteu cousent of,4SMB. "ú!X

ASME 831.85-2010 õ

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prcdicted fûilurc prcssut?, Pt: an internâl pressure that isused to prioritize a defect âs immediate, scheduled, ormonitorecl. See the detaiÌ explanation with Fig. 4. thefailure pressure is calculâted utiliziùg 831G or simila¡method when tlìe design factor, ¿ is set to unity.

prcsctipliprÌ illtegri¡y i0n0:!e tenf prcg1.nflrr integrity man-agemenL process thal Éollows p¡eset conditions thâtresult in fixecl irìspectiol-t ând mitigatiolì âctivities andtimelines.

pr'¿ssr/r"r u1ìless olherwise stated, pressure ìs (]xpressed inpounds pcr square inch (kilopascals) above atmosphericpressure (i.e., Bage pressure), and is abbreviated as psig(kPa).

ptcssure test: mcans by which the itìtegrity of a piece ofequipmelìt (pipe) is assessed, in wlìich the item is filledwith a fluid, sealed, and subjecled to pressure. It is usedto validâte integrity and detect construction defects anddefective ûateriâls

probnbility: likelihood of ¡,ì evenf {ìccurrirìg.

quilficntiotl: cìemonstration and documented knowÌ-edge, skills, and abilities, along with documented train-irìg ard/or experience required for personnel toproperly perform the duties of a specific ¡)b or task.

l?c¿i?,¿,'j pipcline facility used for removing a pig froma pressurized pipelinej sometimes referred to as a "pigtrap."

rcsid nl shess: stress presetìt in an object in tl.ìe absenceof any exlernal loading, typicâlly resulting from marru-facturing o¡ constructiotì processes.

rcsistiaitll:(n) resistance per unit length of a substance wi[lì unì-

form cross-section(ú) measure of the ability of alì elect¡olyte (e.g., soil) to

resist the flow of electric charge (e.g., catlìodic protectioncu¡rent)

Resistivity data are used to design a groundbed fora cathodic prolection system.

t'iclt gns: gas that contaiÌls significant àmounts of hyd¡o-carbons o¡ components thât are heavier than meLlìaneancl ethane. Ilich gascs decompress in a differ.ent fashiolthan pure methane or ethane.

tight-of-wny (llOW): strip of lalrd on wlrich pipelines,railroads, power lines, roads, highways, and other simi-Iar facilities are const¡ucted. The ROW agreementsecures tlìe right to pass througlì property owned byothers. ROW agreements generally allow the right ofingress and egress for the ope¡ation and mailìtenarìceof the facility, and tlìe instâllâtion of the facility.'IheROW widtlì can vâry with the construction ând mainte-nance requirements of the facilityt operak)r and is usu-ally deter¡nincd based on negotiation witlì the afiectedlandowner, by legâl action, or by permittirìg authority.

rtsk: measure of potentiâl loss irì terms of botlì tlte inci-der'ìt probability (likelihood) of occurrence arrd the mag-r'ìitude of the consequences.

risk nsscsstltcil!: systematic process itì whiclì potentialhaza¡ds f¡orn fâcility operation a¡e identifiecl, atìd thelikelihood and col'ìsequences of potential âdverse everìts¿re estim¿tcd. RisL âcscsbmcnls c¡n Iì¡ve v.rryirrg scopos,and cân bc performed at varying leveÌ of cletaìldepending on the operator's objectives (see section 5).

tisk nllqgenterf: overall program colìsistilìg of identi-fying potential threats to an area or equipment; ¿ìssessi¡ìgtlìe risk associated with those tlì¡eats ir'ì terms of incidentÌikelihood and consequencesi mitigâting risk by ¡educ-ing the likeÌihood, the consequences, or both; and mea-surìng the risk reduction results achìeved.

toot c0 se nllolysis: family of processes implemented todetermirìe the primary cause of an everìt. These p¡o-cesses all seek to exâmine a cause-and-effect relâtionshipthrough the organizâtion and analysis of data. Srrch pro-cesses are often used in failurc anaÌyses.

rupturc: complete failure of any portion of the pip(]linethât âllows the p¡oduct Lo escape to the envirorìment.

¡'llsfj corrosion p¡oduct consisting of various iron oxidesand hydrated iron oxides. (This term properÌy appliesonly to iron and ferrous aìloys.)

senltt weld: longitudinal o¡ helical seam in pipe, whichis made in tlìe pipe mill for the purpose of rnaking acomplete circular cross-section.

s¿g¡rl¿rfr length of pipeline or part of the system that hâsunique cha¡acteristics in a specific geograpltic location.

ssllsotir clevices that receive a response to a stimulus(e.g., an ultrasoiric sensor detects uÌtrasound).

shall: "sl¡all" or "shalÌ not" are used to indicate thât aprovision is mandatory.

s/rielr/i¡?.gr prevelìfing o¡ diverting tlìe flow of catlìodicprotection currcnt from its natural path.

sfto¿rld: "should," "should nof," or "it is recommcnded"are used to indicate that a provision is not mandatorybut ¡ecommended as good practice.

sizing nccurocy: give¡ì by tlìe interval within which afixed percentage of all metal-loss featu¡es wilÌ be sized.'I'he fixed percentage is stated as the confidence level.

sl]7rilf prg; industry term fo¡ â type of ILI device.

soil IiL¡ucfncliou: soil condition, typically causecl bydynamic cyclic loading (e.g., earthquake, waves) wheretlìe effectivc slìear strength of tlre soil is ¡cduced suclìthat tlìe soil exhibits the properties of â liquid.

specified nittùnut yield sttetlgth (SMYS): expressed ir.r

pounds per square inch (MPa), r¡irimum yieìd st¡engthprescribed by the specificatiorì under whìch pipe is pur-chased from the manrrfacturer

39

Copyright O 2010 by the Amcrican Society of Mecha ical Engineers &No reproduction mây be made of this material without written consent oÊ ASME

ASME 831,85-2010

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s!otßge field: geographic field corìtaining a weÌi or wellsfhat âre completed for and dedicated to subsurface stor-agc of large quantities of gâs for later recovery trânsnìis-sion, ând end use.

sf¡ai?i clìan8c ilì length of a materiâl in response to anapplied force, expressecl on a unit length basis (e.g.,inches per inclì or millimetets per millìmeter),

s¡r¿ssr ilìternal resistalce of a body to an external appliedforce, expressed ìn units of force per ùnit area (psi or.MPa). It may also be Lermed "urìit sLress."

sfress cortosía1r crnck¡tlg (SCC): fo¡¡r of environmentalattack of the metal involvilìg an ìnte¡âctiotì oi a localcor¡osive environment and tensile stresscs in tlìe metal,resulting in fo¡ mation and growth of cracks.

strcss leucl: level of tangential or lìoop stress, usuallyexpressed âs â perc(]ntage of specified Dìilìimum yieldstreDgth.

subject tltottet expctts; individuals tlìat have expertise ilì,r spc(ific ¡re¡ of oper.ìtion or cnBincerinB.

sul)nrctgcd nlc ruelr/ing; alc welding process that uses anarc or arcs between a ba¡e metal electrode or electrodesand the weld pool. The a¡c and molLen metalare shieldedby a ìrlanket of granular flux on the workpieces. Thcprocess is used without pressure and with fille¡ metalfrom the elect¡ode ar'ìd sometimes from a supplementalsource (n'elding rod, flux, or metal granules).

s¡//?¿V. measurements, irì¡ìpections, or observationsintended to discove¡ and identily everìts or conditionsthat indicate a deparlure from no¡mal ope¡ation orundâmagecl condition of the pipelilìe.

sllstetn at pipelille sys¡crlr either the operatot's etìtire pipe-ljne infrastructure or large po¡tions of that infrastructutethat have definable starting and stoppirìg poirìts.

tcl11pcnturc: expressed in degrees Farenheit ('F) [degreesCeÌsius ('C)1.

tensilc stress: applied pulling force divided by the o¡iBi-nal cross-sectional area.

tltid-pnrty dnnnge: dâmâge to a gas pipeÌine fâcility byan outside party othcr tharì those perfo|ming work forthe operator. For the pu¡poscs of this Code, this alsoilrcludes clamage caused by the opcrator's personnel orthe operatort contractors.

fool; Beneric tcrm signifying any type of instrumentedtool or pig.

ltoittittg: organized program developed to impart tlìekrrowledge and skilÌs necessary for qualification.

tnfilsütissiott l¡|rc: segment of pipeline installed in a tralìs-mission system or betweerì storage fields.

hitrsttliss¡on sys¡sr?r olìe or more segmenls of pipeline,usuâlly interconnected to fo¡m a netwotk, tha[ tt¿ìns-ports Bas from a gathering system, the outlet of â gas

processing pÌâr'ìt, o¡ a storage fieÌd to â higÌì- or low-pressure distrìbutiorì system, â large-volumc custometor anotlìer storage fieÌd.

h ntßpoÍt0tio11 af gos: gatheting, trânsmission, or distribu-tion of gas by pipeline or the storâge of gas.

ultrnsottic: \tgh-frequency sound. Ultrasonic examina-tioÌì is used to determir'ìe wall thickness âr'ìd to detectthe pre¡ìence of defects.

¿tprnfil?gj quaÌifying of an existing pipelìne or maìn fora higher maxìmum allowable operating prcssuLe.

zoeld: localtzed coalescence of mefals or nonmetaìs pto-duced by hl]âtilìg the materials to tlìc weldilìg temperâ-ture, witlì or without tlìe âpplicâtion of pressure, or bythe applìcâtion of pressurc âìolìe arìd with or withouttlìe usc of filler mâterial.

taelclitrg procedu'esj detailed methods and pÌacticesinvolved in the production of a welclment.

ttu inkla l¡cttd: pipr: bcnd produccd by field maclìine orcontrolìed process tlìât lnây rcsult ir'ì prominent contourdiscorìtirìuitìes orì the inlìer radius. The wrirìkle is delib-erâtely ilìtroduced as â meâns of slìortcning the insidemeridian of the benc{. Note that this defìnìtìon does notapply to a pipeÌine bend in whiclì incidental minor,smooth ripples are presenL.

14 REFERENCES AND STANDARDS

'lÏe following is a list of publications tlìat suppo¡t orare ¡cferenced in this Code.

ANSI/lSO/ASQ Q9004-2000, Quality Ma1ìagementSyslems (Spanish Language Version): Guidelincs forPerf ormance Improvements

Publisher: American Society for Quality (ASQ), PO. Box3005, Milwaukee, WI 53201

,API 1160, Managing System Integrity fo¡ HazardousLiquid Pipelines

API 1162, Recommendecl Prâctice, Public AwarenessPrograms for Pipeline C)perators

API 1163, In-Line lnspection Systems QualificationsPublisher: American Pctroleum Instit{ìte (API), 1220 L

Street, NW Waslìingbn, DC 20005

^SME 831.8, Gas Transmissiorì and Distribution Piping

Systems

^SME ll31G, Manual for Determining the Remaiùing

Strength of Corroded Pipelines: A Supplement k)ASME 83l Codc for Prcs'urc Pipirrg

ASME CRTD-VoI. 40-1, Risk-Based In-Service Testing -Developmerìt of Guìdelines, Volume 1: GeneralDocument

ASME Research Report, History of Liùc PipeManufacturing ilì North America

ASME STP-PT-O11, Integrity Management of StressCor¡osion Crackilrg in Gas Pipeline HighConsequence Areas, October 31, 2008

40

Copynghl O l0l0 by rhc Arncfic¿n Socrcty ofMccharical Erìgineers. fjgbNo rcproducrion nìay bc rnade ofllìis rnaleflal $ilhout wrilrcn conscnt olr\SME. '(Ðr

ASME 83l.85-2010

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IPC2002-27131, Qlualification of P¡ocedures for WeìdingOnto In-Service Pipelines

IPC2006-10163, Method fo¡ Estâblishing I{ydrostaticlle-Test hìtervâls for Pipelines With Stress CorrosionClacking

IPC2006-10299, Comparison of Methods for PredictingSafe Parametcrs for WeldingOnto In-Service Pipelines

IPC2008-64353, lmproved Burnthrough PredictionMoclel for In-Se¡vice Welding Applications

Publisher: The Americatì Society of MechalìicâlEngineers (ASME), Three Pa¡k Avenue, New YorþNY 100i6'5990; Order Dept.: 22 l-aw Drive, Box 2300,Fairf ield, NJ 07 007 -2300

Common Ground I Study of One-CalÌ Systems andD.ìm¡ge Prcvcntion lJest Pr¿ctices

Publisher: C)ffice of Pipeline Safety (OPS), Research andSpecial Programs Administrâtion, U.S. Department ofTrânsportaLion, 400 Seventh Street, SW Waslìirìgton,DC 20590

GPTC 2000-19, Iechnical Report- Review of IntegrityMâr'ìâgement for Natural Gas Trarìsmission Pipelines

Publisher: Gas t)iping Technology Committee (GPIC) ofthe American Gas Association (AGA),400 N. CapitolStrcet, NW, Washilìgfon, DC 20001

Glll-00/0076, Evaluatior of Pìpelinc Design ¡-actorsGRI-00 / 0077, Safety Performance of Nâ tural Gas

'hansmìssion and Gathering Systems Regulated byOffice of Pipeline Safety

GRI-00/0189, Model for Sizing High Consequence A¡easAssociaLed With Natural Gas Pipelines

GRI-00/0192, GRI Guide for Locating and UsingPipeline Industry Research

GRI-00/0193, Natural Gas Transmission lripelines:Pìpcline lnte8rity - Prevention, f)etectior'ì, &Mìtigation Practices

Gl{l-00/0228, Cost of Pe¡iodically Assuring Pipelinelnte8rity in High Consequerrce Areas by In-LineInspection, Pressure Testing and Direct Assessment

GRI-00/0230, Periodic Re-Verification Intervals forHigl-r-Consequence Areas

GRI-00/0231, Di¡ect Assessment and ValidatìorìCRI 00/0232, Leak Versus Rupture Considerations for

Steel Low-Stress PipelincsGRI-00,/0233, Quantifying Pipeline Design ât 72% SMYS

as a P¡ecursor to Increasing the DesiBn Stress LevelCRI-00/0246, Implementation Plan for Periodic

Re-Verification Intervals for High-Consequetìce A¡casGRI-00 /0247,Introduction to Smart Pigging in Natural

Gas PipelinesGRI-01/0027, Pìpr:line Open Data Stândard (PODS)Gl{l-o1l0083, Review of Pressure Retestirìg for Gas

Trarìslnission PipelinesGRI-01/0084, Proposed New cuidelines for ASME 831.8

on Assessment of Dents and Mechanìcal Dama¡¡c

GRI-O1/0085, Schedule of l{esponses to Corrosion-Caused Metal Loss Revealed by Integrity-AssessmentResulfs

GRf-01/0111, Dctcrmining the Full Cost of a PipelûreIncidenl

GRf-01/0154, Nâtural Gas Pipeline IntegrityMânagement Committee Process Ove¡view Report

GRI-04/0178, Effecr of Pressure Cycles on Gas PipelinesGRI-95/0228.1, Natural Câs Pipclirìe Risk Managenìent,

Volume I: Selecred lechnical lerminologyCRI-95/0228.2, Natural Gas PipeÌine Risk Management,

Volume Il: Seâ¡ch of Literature Wo¡ldwide orr RìskAssessment/ Risk Management for Loss ofContainment

GRI-95/0228.3, Natúral Gas Pipelir'ìe Risk Management,Volume III: hìdustry Practices

^nalysisGltl-95/0228.4, Natu¡âl Gas Pipeline Risk Marìagement,Volume IV: Identìfication of Risk ManaBementMethodologies

Irublishe¡: Gas Teclìnology Llstitute (GTI), 1700 SoùthMoulìt Prospect Road, Des Plaines, IL 60018

Guidelines for'lþchnical Management of ChemicalProcess Safety

ì'ublisher: Center for Clremical Process Sâfety (CCPS)of tlìe Aml:rican Institute of Chemical Engineet s(AIChF), 3 l'ark Avenue, New Yo¡k, NY 10016

Integrity Clìaracleristics of Vintage Pipelines

Publisher: The INGAA Foundâtion, Inc., 10 G Street,NE, Suite 700, Washington, DC 20002

Juran's Quality Control Handbook (4th Edition)

I'ublisher': McGraw-Hill Book Company, 1221 Avenueof the Americas, New York, NY 10020

NACE RP0169, Conlrol of Exteìnal Cor¡osion onUnderground or SubmeÌged Metallic Pipirìg Systems

NACE RP0204, Stress Co¡rosion C¡acking Di¡ect.Assessmerìt (SCCDA) Methodology

NACIì SP0106-2006, Control of Internal Corrosion inSteel Pipelines and Piping Systems

N^CE SP0206-2006, Intelnal Corrosion DirectAssessment Metlìodology for Pipelines CarryingNormally Dry Natu¡al Gas (DGJCDA)

Publishe¡: National Association of Corrosion Engineers(NACFI) fÍìternational, 1440 South C¡eek Drive,Houston, TX 77084

Pipeline Risk Management Manual (2ncl Edition)Publishc¡: Gulf Publishing Company, I,.O. Box 2608,

llouston, TX 77252

PR-218-9801, Analysis of DOt ReportabÌe Incìdents forGas l'rarìsmission and Gathering System Pipelines,1985-1997

4Ì

Copyright O 20 10 by the A'¡erica society of Mechanrcal Engineers &No may be made ofthrs material without written collseut ofASMË

ASME 831.8S-2010

l:'R 268-9823, Guidelines for the Seismic Design arìd

^ssessment of Natural Gas and Liquid Hycltocarbon

Pipelines

Publisher: Pipeline Research Council Itìte ìational, lnc.(PRCD, 1401 Wilson Boulevard, Arlingtorì, VA 22209

42

CopyriglÌr O 20 t 0 by lhr ^

merican Socict y of Mcchalical Fngrrìeers. ffr\o reproduction nlay be made ofthis nralcrial without wflrten conscnl ofAS\4ù. YgX

ASME 831.8S.2010

NONMANDATORY APPENDIX ATHREAT PROCESS CHARTS AND PRESCRIPTIVE INTEGRITY

MANAGEMENT PLANS

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'l'his Nonmalrdatory Appendix provides processcharts and the esscrìtials of a prescriptive inteBrity man-âgement plan for tlìe nìne categories of threats Ìisted inthe main body of this Codc. The required ¿ìctivities andintervals are not applicablc for severe conditions thaftlìe operator may encountc¡. In tlìose instances, morerigorous analysis and morc frcquent inspection may benecessary.

A-1 EXTERNAI CORROSION THREAT

A-1.1 Scope

Scction A-1 provides an integrity management planto add¡ess the threât, and methods of integrity assess-ment and miti8ation, of external corrosion (see Fig. .A-1).External co¡rosion is defined in this context to incluclcgalvarìic corrosionâùd microbiologically influelìced cor-rosion (MlC).

This section outÌines the integrity management pro-cess for extelnâl co¡¡osion in general and also cove¡ssome specific issues. Pipeline incidenl analysis has iden-tified external corrosion among tlÌe causes of pastincidents.

A-1.2 Gathering, Rev¡ewing, and lntegrating Data'['he following minimal data sets should be collected

for each segment and leviewed before a risk assessmentcan be conducted, This clata is collected ìn support ofpelforming risk assessment and for special considera-tions, suclì as identifying severe sìtuatiorìs requiringmore or additional activities.

(a) year of installation(ú) coatirìg type(c) coating condition(d) years wirh âdequate cathodic protection(s) years with questiorìable cathodic plotection

f) years witlìout cathodic protection(.9 soìl characteristics(ir) pipe inspeclion reports (bell hole)(l) MIC detected (yes, no, or unknown)

f) leak history(k) walì thickness(/) diamete¡(n¡) operating stress level fl, SMYS)l¡¡) pâst hydrostJtic test information

For this tlìreat, the data is used primarily for prìoriti-zation of integrity assessment and/or mitigatior'ì âctivi-ties. Where the operator ìs missing data, conservativcassumptions shall be usecl when performing tììe riskassessment or, alternatively, the segment shall be priori-tized higher'.

A-1.3 Cr¡ter¡a and R¡sk Assessment

For new pipelines or pipeline segments, the operâtormay wish to use the originâl mâteriâl selectiolì, desiglìconclitions, and construction inspections, as well as tlìecurrent operating lìisbry to estâblish the conclition ofthe pipe. For this situation, the operâtor must determinethat the construction inspections lìave an equal orgreater rigor thân that provided by the prescribed integ-rity assessment in this Code.

In no case shall the interval between const¡uction andthe first requi¡ed reâssessment of integrity exceed I0 yrfor pipe operâting âbove 60% SMYS, 13 yr for pipeoperâting above 50% SMYS ârd at or below 60% SMYS,15 yr for pipe operating at or above 30% SMYS and ator below 50% SMYS, and 20 yr for pipe operating below30% SMYS.

r-or all pipeline segments older than lhose statedabove, ilìtegrity âssessment shall be conducted using ametlìoclology, within the specified response interval, asprovided in pâra. A-1.5.

P¡evious irìtegrity assessments calì bc colìsideted as

meeting tlìese requirements, provided tÌre inspectiorìshave equal or g¡eater rigor LIìân tllat provided by theprescribed ìnspections ilì this Codl]. Tlìe intervâÌbetween the previous integrity assessment and fhc nextintegrity assessment cannot exceed the interval statedin this Code.

A-1.4 lntegf¡ty Assessment

The operator has a choice of tlì¡ec integrity assessmentmethodsr ilì-line irìspeclion with a tool capable ofdetecting wall loss, such as an MFL tool; performing a

presslrre testi or conductilìg direct assessment.(n) Itt-l-itrc lnspection. The operator shall consult sec-

tìorì 6 of this Code, whicLr clefines the capability of vari-ous ILI devices and provides criteria fol running of thetool. The operâtor selects the approp¡iate tools andhe/she or his/her represenlative perfor¡ns theinspection.

43

Copyrighr O 2010 by llre Arnerican Sociely ofMcch¿nical Ëngitlcers. fglNo rc¡rorJuerron may be nìade ofrhis nìarcri¿l wilhoulr!'illenconscnlofASM[.'ldy

F¡g. A-1 lntegr¡ty Management Ptan, External Corros¡on Threat (S¡mpt¡fied Process: Prescriptive)

44

Copyright O 2010 by tlìe ArneÍican Sociely ofMcchânical Engineers. ffrNoreproduction¡naybe ìâdeofthisnìateriâlwjthoutwr¡ttenconsentofASME.'(dy

Gather¡ng, reviewing,and integratìng data

Criteria andrisk assessmenl

Determineassessment

interval

lntegrity assessmenl(lLl, DA, hydrotest,

or other)

Responses andmitigation

(repa¡r and/or Drevent)

Other ¡nformationto other threats

Performancemetrics

ASME 831,85.2010

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(b) Ptcsstuc Test. 'lhe operator shalÌ consult section 6of tìÌis Code, which defines how tc¡ cc¡nduct tests forbothpost-constructìon and in-ser!ice pipclines.'l'he operatorselects tlìe appropriate test and he/she o¡ lìis/her repre-sentative performs the test.

(c) Dircct Assess lenf. Tlìe ope¡ato¡ shall consult section 6 of this Code, which defines the process, tools, andinspections. The operator selects the appropriate tooìsand he/she o¡ his/her representaLive performs theinspections.

A-1,5 Responses ând M¡t¡gat¡on

Responses to integrity assessments are detailed below(n) ln-Line lnspectioll. The response is dependent orì

the severity of corrosion âs determined by câlculatingcritical faiÌure pressure of indications (see ASME B31Gor equivalent) and a reasolably anticipated o¡ scientifi-cally proven rate of corrosion. Refer to section 7 fo¡responses to integrity assessment.

(b) Direct Assessfictr¡. The response is dependent oÌrthe number of indicatìons exaûrined, evaluated, andrepaired. Refcr to section 7 for responses to integrityassessll1elìt,

(c) Prcssure T¿sli?.g, Ihe interval is dependent on tlìetesl pressure. lf the test pressure was al least 1.39 timesMAOP, the interval shall be 10 yr. If tììe test pressurewas ât least 1.25 times MAOP, the interval shâll be 5 yr(see section 7).

If the actual operating pressure is less thatì MAC)qthe factors shown above can be applied to tlte actualope¡ating pressure in lieu ol MAOP for ensu¡irìg integ-rity at the reduced pressu:e only.

TÌre operator shall selecb the appropriate repâir meth-ods as outlined ìn section 7

The operator shall select the appropriate prevetìtionpractices as outlined in sectìon 7,

A-1.6 Other Data

A-1.7 Assessment lntervat

The operator is required to assess itìtegrity periodi,caìly. TIìe ìnterval for assessments is dependent on theresponses tâken as outlined in para. A-1.5.

'Ihese intervâls are mâxirÌtum ìntervaÌs. Tlìe operatol.must incorporate new data into the assessment as databecc¡mes available ând that may requi¡e mote frequentintegrity assessments. For exâmple, a leak on the seg-ment that may be caused by external corrosion shouÌdrìecessitùtc immediate reasçessmcnl

Changes to tlìe scgment may also require reassess-ment. Chânge malìâgernerìt is âddressed in this Code ilrsection 11.

A-1.8 Performance Measures

The following performance measures shall be docu-rnentecl for the external corrosion tlìreat, ir'ì order toestâbÌish the effectiveness of the ptogram a¡d for corrfi¡-mation of the integrity âssessment irìterval:

(a) number of hydlostatic lest fâilures caused byexternal corrosion

(ü) numbe¡ of repair actiorìs taken due to in-lineinspection ¡esults, immediate ând scheduled

(c) number of repair ¿ìctions taken clue to direct assess-ment results, immecìiate and scheduled

(d) numbcr of external corrosion leaks (for low-stresspipeliÌìes it rnay be beleficial to compile leaks by leakclassificatìc)lì)

A-2 INTERNAL CORROSION ÏHREAT

A-2.1 Scope

Section A-2 provides an inte8rity mânagement planto address the threât, and methods of integrity assess-ment ând mitigalion, of internal corrosion. Internal cor-¡osìon is defined ilì this context to include chemicalco¡rosion ând intcrnal microbiologically influenced cor.-rosion (MIC, see Fig, A-2).

Section ,{-2 provides a general ove¡view of the integ-rity marìâgement process for internaÌ cotrosion in gen-eral and aìso covers some spccific issues. Pipelineincident analysìs has iderìtifìed ìnternal corrosion arìongthe causes of pâst incidents.

A-2.2 Gathering, Reviewing, and lntegrat¡ng Data'Ihe following minimal data sets should be collected

for each segment and reviewed before a ¡isk assessment

(, p¿ìst hydrostâtic test informatìon(.9) gas, liquid, or solid analysis (particularly hydro-

gen sulfide, carbon dioxide, oxygen, free wâte¡, andchlolides)

(/¡) bacteria cuÌture test results(i) corrosion delection devices (coupons, probes, etc.)(7) operating parameters (particularly p¡essuÌe alìcl

flow velocity arìd especially periods where there is noflow)

(k) operating stress level (% SMYS)

During tlìe inspection ¿rctivities, the openìtor m.ìy dis- canrb-e conducted rhis datâ is collected in suPPort of

cover orher dara rhar srìould b" r."J;"h;;;;;;äì;; perlorminl¡ risk assessment ¡nd nor special considera-

rr¡r ¡ssessments tor other threats. Ë.t "-",i.ì.. *rr"i tions, such iìs identifying severc :'ituations

'equiringconducting an ILI with ". Ir,lrr- t..r,-J""ì'"-á"f ú" more orrdditionâl â'tivities'

detected oñthe rop hatf of rhe pipe. inis ;"; h^;;í; (c) year of instaìlation

caused by third'pårry da-ug". Ii i" uppr.,pJ;ate then io (¡') PiPe,inspection rePorts (bell hole)

use this informaìion wÌren ionrluctirie risk asscssment {') leâk history

for the thircl-party clamage threat. " {¡/) wall thicknessl¿) diat¡ete¡

45

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socicty of Mcchanical E ginecrs. fgàNo rcproducrron nray be nradc ofthis nìatcrial withour wrillen col.ent of^SME. '(Sl

Fig. 4"2 lntegr¡ty Management Ptan, lnternal Corros¡on Threat (Simpt¡fied Process: Prescript¡ve)

Gather¡ng, reviewìng,and integrating data

Crìterìa andrisk assessment

Determìneassessment

interval

lntegr¡ty assessment(lLl, DA, hydrotest,

or other)

Other informationto other threats

46

ASME 811.8S-2010

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Fo¡ this tlì¡cât, the data is used primarily foÌ prioriti-zation of intcgrity assessment and/or mitigation activi-ties. Where thc operator is missing data, conservativeassumptior'ìs shall be used wheir performing the r.iskassessmerìt or, âlternâtiveÌy, the segment shall be priori-tizecì lìi8her.

A-2.3 Cr¡teria and R¡sk Assessment

For 1ìew pipelines or pipeline segments, tlÌe operatormay wish to use tlìe originâl material selection, desiglìcorìditions, ând constnrction inspections, as well as thecur¡ent operating histort to cstablish the condition ofthe pipe. For this situâtioir, the operator must determineflìat the construction inspections have an equal orgreater rigor tlìân that provided by the prescribed integ-rity assessments in this Code. [n addition, the operatorslìall determilìe tlìat a cortosive envitonùìelìt does )ìotexist.

In 1ìo case may the inte¡val between construction andthe first required reassessment of integrity exceed l0 yrfor pipe ope¡ating above 60% SMYS, 13 yr for pipeoperatirìg above 50% SMYS and at or below 60% SMYS,and 15 yr for pipe operating at or below 50% SMYS.

For all pipeline segments older than those statedabove, i[tegrity assessment shâll be conducted using amelhodoÌogy wifhirì the specified response interval, asprovided in para. A-2.5.

Previous irìtegrity assessments can be considered asmeetilìg these requirements, provided the jrìspectionshave equal o¡ greater rigor than that provicled by theprescribed irìspectiolìs in this Code. The intervalbetween tlìe previous integrity assessûlenI and the nextintetrity assessment cannot exceed the interval statedin this Code.

A-2,4 lntegrity Assessment

The operator has a choice of three integrity assessmentmethodsr in-line inspection with a tool capable ofdetccting wall loss, such as an MFL tool; perfotming â

Prcssure test; or conducting direct assess¡nent.(0) It1-LitE lfispectìon. For in-line inspection, the oper-

ator must consult section 6 of this Cocle, wlìich definestlìe capability of various ILI devices and provides criteriafor rumring of the tool. The operator selects the appro-priate tools and he/she or his/lìer representâtive peÌ-forms tlìe inspection.

(b) Pressure Test. The operator shall consult section 6of this Code, whiclì defines how to cc¡nduct tests forbotl-tpost-construction and in-service pipelines. Tlìe operâtorselccts tlìe appropriâte test and he/slìe or lìis/her rep¡e-serìtative performs the test,

(c) Ditcct Assessr¡¡etif. The operator slÌall consult sec-tion 6 of this Code, which defines the process, tools, andinspections. The operator selects tlìe appropriate toolsand he/she or his/her representative pe¡forms tlìeinspections.

A-2.5 Responses and Mit¡gat¡on

Rcspoùses to intcgrity assessmcr'ìts are detailed below,(n) In-Line Inspectioll. lhe response is deper'ìdent on

the severity of corrosiolì, as determined by calcuÌâtingcritical failure pressure of indications (see ASME 831Gor equivalent) arìd a rcasonably arìticipated or scientifi-cally proven rate of corrosior. Refer to section 7 forresponses to integrity assessments.

(lt) I)irect Assessnte¡rf. The response is dependent onthe number of indications examined, evaluated, andrepaired. llefer to section 7 Éor responses to integrityassessment. An acceptable method to address dly gasinternal corrosiorì is NACE SP0206.

(c) Pressure'festing. The inteNal is dependent on thehydrostatic test pressure. If the test pressure wâs at least1.39 times MAOP, the interval is 10 yr If the test pressurewas at least 1.25 times MAOP, the interval is 5 yr (seesectÌo¡ 7).

If the actual operating pressure is less than MAOP,the factors shown above can be applied to the âctuâloperating pressure in Ìieu of MAOP for the purposes ofinsurin¡l integrity at the ¡educed pressure only.

The operator shaÌl select the app¡opriate repair metlì-ods as outlired in section 7.

The operatoÌ shalÌ select the appropriate prever'ìtìonprâctices âs outlined in section 7. D¿ìta corìfirming tl-tat¿ì corrosive envi¡onment exists should proûrpt the designof a mitigâtion plân of action and immediate implemen-tâtion slìouÌd occu¡. Datâ suggesting thât â corrosiveenvironment may exist should prompt ân immediatereevâluafion. If tlìe dâta shows that no cor¡osive corìdi-tion o¡ environment exists, tl-ìen the operator shouldidentify lhe conditions that would prompt reevâluation.

A-2.6 Other Data

During the inspection âctivities, tlìe operalor mây dis-cover otlìer data that should be used when performingrisk assessments for otlìe¡ tlìreâts. For example, ra,hcncorìducting an ILI with an MFL tool, dents may be câlledout on the top half of the pipe. This may have beencaused by tlìird-party damage. It is app¡opriâte then k)use this data wlìen conducting intcgrity assessnìent forthe third-party damage tlìreat.

A-2,7 Assessment lnterval

Tlìe ope¡ato¡ is requìred to assess integrity periocli-cally. TIìe intervâl for assessment is dependenl on theresponses tâken, as outlined in para. A-2.5.

These intervals are mâximum interuals. Thc operatorshalì incorporâte new data into tlìe assessmenl âs databecomes available, and that may Ìequire more frequcnlintegrity assessments. For example, a leak on tlìe seg-ment that may be caused by inte¡nâl corrosion wouldno.c5sìlàtc i mmccì i,ìtc redssessmcnl..

Changes to the segment mây also drive reassessmeltt.This change mânagement is addressed in section 11.

47

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A-2.8 Pefformance Metr¡cs

l'he following performance met¡ics shall be docù-mented for the internal corrosion tlì¡eat, in order toestablish tlìe effectiveness of the program and for confir-mation of the integrity âssessment intervall

(n) numbe¡ of hydrostatic test failures caused byinte¡nâl corrosi)n

(ú) r'rumber of repair âctions taken due to in-lineinspection results, immediate and scheduled

(c) number of repair actions taken due to di¡ect assess-ment results, im¡nediâte and schedulec{

(d) number of inte¡nâl co¡¡osion leaks (for low stresspipeÌines, it may be bereficial lo compile leaks by leakgrade)

A-3 STRESS CORROSION CRACKING THREAT

A-3.1 Scope

Section A-3 provides alì integrity managemenl planto address the threat, ¿Ìnd metlìods of integrity assess-rnent arìd mitigation, for st¡ess col¡osion cracking (SCC)ol gas line pipe (sce Fig. A-3). Ihis plân is âpplicableto botlì Ìrear neutral pH and high plI SCC. Integrityâssessment and mitigation plans for both phenomenâare dìscussed in published researclì literature. This sec^

tiorì does ûot âdd¡ess all possible means of ìlìspectingfor mitigatiorì of SCC. As new tools and technologiesare developed, they caìÌ be assessed and be avaìlable foruse by the operator. Addìtiolìal guidance for manage-ment of SCC can be fou¡rd in ASME STP-PT-011,Integrity Management of Stress Cor¡osion Cracking inGas Pipelinc High Consequence A¡eas.

A-3,2 Gather¡ng, Review¡ng, and lntegrat¡ng Data

Thc foìlowìng minimâl data sets should be collectedfor each segment and reviewed before a risk assessmentcarì be conducted. This data is collected for performilrgrisk assessment and for special consideratiorls, such asidentifying severe situations requiring more or addi-tional activities.

(n) age of pipe

NOI Er ABe of pipe coatiÌ1g m¿ry be used if the pipeline se8merthas l¡een assessed f<¡r SCC.

(ú) operating stress level (% SMYS)(c) operating temperature(d) clistârìce of the segment downstream from a com-

prl]ssor station(¿) coating type

f) past Iìydrolest informâtionWhere the ope¡ator is missing dâfa, conservalive

assumptions shall be used when performing the riskanalysis o¡, âlternatively, llìe segment shall bc prioritizedhigher.

A-3.3 Cr¡ter¡a and Risk Assessment

4.3.3.1 Poss¡bte Threat of SCC. Each segmcntshould be assessed for risk for the possible tlìreât o(SCC if all of the folbwing criteriâ âre present:

(n) opcrating stress level >60% SMYS(¡') â8e of PiPe >10 Yr

NOTE: Age of prpe coatrng may be used if tlìe pipelinc se8rnenthas been assessed for SCC.

(c) All co¡r'osion coating systems otlìer tlìan plantapplied ol field applied fusion bonded epoxy (FBE) orliquid epoxy (when abrasive surface prepaÌàtion wasused during field coatinB applicatìon). Field joirìt coatirìgsystems should also bc considerecl Ior their susceptibil-ity using the criteria in this section.

A-3.3.2 Poss¡bte Threat of High pH SCC. Each seg-ment should be assessed for lisk for the possibìe threatof high pH SCC if the above criteria are present and alìof the following criteria are presentl

(n) operating tcmperature >100"F (38"C)(b) distance from compresso¡ stâtion <20 mi (32 km)In addition, eâch scgmer'ìt in which one or more set-

vice ir'ìcidents or one or more lìyd¡ostatic test breaks orleaks has bce¡ caused by onc of the two types of SCCshall be cvaluated, unless the corìditions that led to theSCC have been cor¡ected. WIìen a servicc ir'ìcident o¡hyd¡ostatic test break ìs att¡ibutable to lìear-ncutral pHSCC, or when conditiorÌs conducive to near-lìeLrtraÌ pHSCC are tlìought to exist, llìe 20 mi (32 km) criterion fordistance from compressor station slìall be disregardedfor the pipe segment as a criterion to defineSCC susceptiblity.

For this threat, thc risk âssessment consists of compar-ing the data elements to lhe crileria. lf lhe conditionsof the criteria are met or if the segment has a previousSCC history (i.e., bell hole inspection indicâting SCC,hyclrotest failures caused by SCC, in-service failurescaused by SCC, o¡ leaks car.rsed by SCC), the pipe isconsidered tobe at risk for tlìe occurrence ofSCC. Othc¡-wise, if olìe of the conclitions of the criteria is rìot metand if the segment does not lìave a history of SCC, noâction is requi¡ed.

A-3.4 lntegr¡ty Assessment

If conditions for SCC are present (j.e., meet the criteriain pala. A-3,3), a written inspection, examination, ârìdevaluation plan shall be prepared. The plan should giveconsideration to integrity assessment fo¡ other threatsand p¡io¡itìzatìorì âmong otlìe¡ segmelìts thât are at riskfor SCC.

lf the pipeline experjences an in-service leak or rup-ture that is attribLrted to SCC, the pârticLllar segmentshall be subjected to a hydrostatic test (as describedbelow) within 12 mo. A documented hydrostatic retestprogram shall be developed for {hìs segment. Note tlÌat

48

Copyrighr O lUltJ by rhe Anrenc¿n Socicry ofMcchanical Engincc's. f&No reproduclion rnay bc rnadc oflhis rnalcrial wrthoul wrirlen conselll olASMF. '(gy

F¡g. A-3 lntegrity Management Program, Stress Corros¡on Crack¡ng threat(S¡mpt¡f¡ed Process: Prescr¡pt¡ve)

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Fail para. A-3.3 criteria

ln-servìce leak orfailure occurrence

due to SCC

ASi\4E Br1.8S-2010

Tabte A-1 sCC Crack Severity Criteria

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Crack Sever¡ty Remain¡ng Life

Crack of any length having depth <10% Wl or crack wÌth2 in. (51 mm) m¿ximum length ând depth less than30% wl

Predicted failure pressure >110% Slt¡YS110% SMYS > predicted failure p¡essu¡e >125ol. lvlAoP125% i\440P > predicted failure pressure >110o/o MAOPPredicted failure pressure <110% IMAOP

Exceeds 15 yr

Exceeds 10 yrExceeds 5 yr

Exceeds 2 yr

Less than 2 yr

hydrostatic pressure testiÍrg is required. Use of othertest mecliuùls ìs lìot permitted.

Acceptable inspection and mitigation activities {oraddressing pipe segments at risk for SCC are cove¡edin parâs. A-3.4.1 arìd A-3.4.2.

A-3.4.1 Bett Hole Exam¡nât¡on and Evaluat¡onMethod. MÂgnetic particle inspection methods (MPt),or other cquivalent nondestructive evaluâtion methods,shall be used when disbo¡ded coatirìg or bare pipe isencountered during integrity-¡elated excavation of pipe-line segmeiìts susceptiblc to SCC. Excavations where thepipe is 1ìot completely cxposed (e.g., erìcroachments,exotlìermically weldecl attaclÌments and foreign linecrossings wherc the ope¡ator may need only to removesoil from the top portion of the pipe) are not subject tothe MPI requiremclt as described unless tlìere is a priorhistory of SCC in the segment. Coating condition shouldbe assessed and documented. All SCC inspection acfivi-ties shalÌ be conducted using documented procedures.Any indications of SCC shall be addressecl using guid-ance f¡om TabÌes A-1 and A-2.

St¡ess collosion cracking direct âssessment (SCCDA)is a formaÌ process to assess a pipe segment for tlìepresence of SCC primarily by examìning with MPl, orequivâlenl teclìnology, selected joints of pipe within thatsegment afler systematically gathe ng and analyzìngdata for pipe having similar operationâl characteristicsand residing i¡r a similar plìysical envi¡onment. lheSCCDA process provides guidance for operators toselect appropriate sites to conduct excâvations for thepurposes of conducfirìg SCC integrify assessment.Detailed guidance for this process is provided inNACII RP0204, Stress Cor¡osion Cracking Direct

^sscssment (SCCDA I Metlìodology.

Tlìe severity of SCC indications is characterized byTable A-1. Several altetnative fracture mechanicsapproaches exist for operators to use for cr¿ìck sevcrityassessmenL. The values in Table A-1 have been devel-oped for typical pipeline attributes and representativeSCC growth rates, using widely accepted fracturemechanìcs analysis methods,

'lhe respolrse requirements applicabÌe to the SCCcrack severity categories ate provided in Table A-2. I'he¡csponse requìrements in Table A-2 incorporate conser-vâtive assumptions regarding remaining flaw sizcs.

An engirìeering critical assessment may be concluctedto evaluate thc rìsk and identify alternative methodolo-gies. {See para. A-3.4.2(dX3).1

A-3.4.2 Hydrostat¡c fest¡ng for SCC. Hyclrostatictestirìg conditions for SCC mitigation have been devel-oped through industry research to optimize the removaÌof c¡itical-sized flaws whìle mìnimizing growth of sub-critical-sized flaws. Hydrostâtìc testilìg utiÌizjng tlìe cri-teria in this sectiolì is corìsiclered ân irìtegrity assessmentfo¡ SCC, Recommelìded hydrostatic test criteria are asfollows:

(a) lìigh-point test pressure equivâlent to â minimumof 100% SMYS.

(¡r) target test pressu¡e shall be maintained for a mini-mum period of 10 min.

(c) upon returning the pìpelilìe to gas service, âninstrumented leak survey (e.9., a flarne ionization su¡-vey) shall ì:e performed. (Alternativcs may be consid-ered for lìydrostatic test fâilu¡e cvcnts due to causesother thân SCC.)

(d) Rcsulls(1) No SCC llydtostntic Test Lenk or lluptrLre. lf io

leaks or ruptures due to SCC occurred, the operator shalluse one of the following two options to address long-term mitigation of SCC:

(n) implement a written hydrostalic retest pro-grâm with a technically justifiable interval o¡

(D) perform engineering critical assessment toevâluatc the Ìisk and identify furtlìer mitigation meth-ocls [see para, A-3.4.2(dX3)]

(2) SCC Hvdtostafic TesÍ Leak oï Rupt rc. 11 a \eakor rupture clue to SCC occurred, the operator shaÌl estâb-lish a written hydlostatic retest progrâm and proceciutewith justification for the retest intc¡val. An example ofan SCC hydrostatic retest approach is founcl inIPC2006-10163, Method fo¡ Establishing HydrostâticRe-Test [ntervals for Pipelines With Stress CorrosionCrackilg.

(3) [,tlgit.¿ctitrg Ctiticol Assess rcnt, TIìisisawrittendocument llìat evaluates the risks of SCC arìd providesa technically deferìsible plan that demonstrates satisfac-tory pipeline sâfety performalìce. Ì'he document slìallconsider tlìe deiect growth mechanisms of the SCCProcess.

50

Copyright O 2010 by the Arùerican Society of Meclìarìical Erìgineers. rlelNo rcproduction may be made ofthis mateflal without writtlrn consent ofASME. \OF

ASME Bl1,85-2010

Tabte 4.2 Response to Bett Hote sCC lndications

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No SCC or Category 0

Category 1

Category 2

Category 3

Category 4

Schedule SCCOA as appropriale. A single excâvation for SCC ls adequ¿te.

Conduct a minimum of two additional exc¿vations.1f the largest flaw is Category 1, conduct next assessment in 3 yr.

lf the largest flâw is Calegory 2, 3, or 4, lollow the response requirementappìicable to that category.

Consider temporary pressure reductìon unlil hydrotest, lLl, or lMPl completedAssess the segment using hydrotest, lLl, or 100% [,1P] examìnation, or

equivalent, within 2 yr. lhe type and iimlng of furiher assessment(s)depend on the results of hyd¡otest, lLl, or lMPl.

lmmediate pressure reduction and assessment ol the segment using one oithe followingl(d) hydrostatic test(b) tL1

(c) 100% NlPl, or equiv¿lent, examination

lmmediate pressure reduction and assessment of the segment using one ofthe loìlowing:(a) hydrostatic test(b) tLl(a) 100% MPl, or equivalent, exar¡ination

4"3.4.3 ln-L¡ne Inspection for sCC. Recent ìndust¡yexperience has indicated some successful use of in-lìneinspection (lLI) for SCC in gas pipelines. No specificguidance is offered in this document until greater indus-try expe¡ience is eslabÌished. It is the resporìsibility ofthe operator Lo develop appropriate assessment andresponse plans when ILI is used fol SCC.

A-3.5 Other Data

Durir'ìg the integrity âssessment and mìtìgation activi-tìes, the operator may discover other data that may bepe¡tinent lo olher lhreats. This data shoulcl be usedwherc appropriate for performing risk assessments forother fhreats.

A-3.6 Performancê Measures

The following performance measures slrall be docu-mented for tlìe SCC tlìrcât, in o¡der to estabìislì theeffectiveness of tlìe program and for confirmation of theinspection intervali

(n) number of in-service leaks/failures due to SCC(b) number of repair or replacements due to SCC(c) number of hydros[âtic test failures due lo SCC

A-4 MANUFACTURING THREAT (PIPE SEAM ANDPIPE)

A-4.1 Scope

Section A-4 provides an iÍrtegrity mâr'ìâgemenl planto address the threal, and methods of integrity assess-ment and mitigation, for manufacturing concerns. Mân-ufacturing is defincd in this context as pipe seâm ândpipe (see l¡ig. A'4).

TIìis section outlines the integrity mânagemcnt p¡o-ccss for manufacturilìg concerns in general and alsocove¡s sorne specific issues. Pipeline inciderìt analysishas identìfied marìufacturing among tlìe câuses of pastilìcidents.

A-4,2 Gather¡ng, Reviewing, ând Intêgrating Data

The following minimal data sets should be collectcdfor each segment and reviewed before a risk assessmerìtcan be conducted. This data is collected for perfolmingrisk assessment and for special considerations such asidenlifying severe situations requiring more or addi-tional activities.

(d) pipe material(ú) year of installation(c) manufacturing process (age of manufacture âs

alternative; see note below)(d) seam type(c) joint factor

f) operaling pressure historyWhele the operator is nìissing clata, corìservative

assumptions shall be used when pelforming the riskassessment or, alternâtively, the segment shall be pliori-tized higher.

NOTD| When pipe data is L¡nknowû, the operator may refer toHrstory of l-ine Pjpe MarìLrf;tcturirìg irì North America byl. l] KieÂìer ând E. Il. ClÂrk, 1996,

^SM[.A-4.3 CÌ¡ter¡a and R¡sk Assessment

Fo¡ cast iron pipe, steel pipe greater thân 50 yr old,mechanically coupled pipelines, or pipelines joined bymeans of âcetylene girth welds, where low temperatû¡es

51

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F¡9. A-4 lntegrity Management Ptan, Manufactur¡ng Threat(Pipe Seam and P¡pe; 5imptified Process: Prescriptive)

Gather¡ng, reviewing,and integrating data

Cr¡ter¡a andr¡sk assessment

Responses andmit¡gat¡on

Determineassessment

¡nterval

52

ASME 831.8S-2010

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are experienced or wlìere the pipe is exposed to move-ment such as land movement or removal of supportingbackfill, examination of the terrain is required. If ìandmoverrrerìt is observed or can reasonably be anticipated,a pipeline moveùtent rnonitoring program should beestablished and appropriate intervention actìvitiesun.lertaken.

lf the pipe has a joint factor of less than 1.0 (such âslap-welded pipe, hamrner-wclded pipe, and butt-weldecl pipe) or if the pipeline is composed of low-frequency-welded ERW pipe or flash-welded pipe, amanufâctu¡ing threat is corìsidcred to exist.

A-4.4 lntegr¡ty Assessment

For câst iron pipe, the assessment sltorrld include eval-uatìon as to wlìether or not the pipe is subject to lândmovement or subject to removal of support.

For steel pipe seam concerns, when raising tlìe MAOPof a pipeline or when ¡aising the operatirìg pressureabove the lìistorical operating pressure (highest pressu¡ereco¡ded in the past 5 yr), pressure testing nìust beperformed to address the seâm issue. Pressure testingshall be in accordance with ASME 831.8; to at least1.25 times the MAOP. ASME 831.8 defines how to con-duct tests fo¡ both post-construction and in-selvicepipelines.

A-4.5 Responses ând M¡tigationFor câst iron pipe, mitigâtion options include replace-

ment of pipe or stabilization of pipe.For sfeel pipe, any sectiorì that fails the ptessure test

must be replaced.'l'he operator shall select tlte appropriate prevention

praclices. For tlìis threat, tlìe opcrâtor should developpipe specifications to be used wlìcrì orclering pipe thâtmeets or exceeds the requi¡ements of ASME 831.8.

A-4.6 Other Data

Durirìg the inspection activities, tlìe operator may dis-cover otlìer data that slìouÌd be used when performingrisk assessments for other threats. For exarnplc, certainseam types may be more susceptible to accelcrated cor-rosiorì. It is approptiate to use this info¡matìon whenconductìng risk assessments for external ol ìnterrìalcorrosiolt.

A-4.7 Assessment lnterval

Periodic integrity assessment is not requircd, Changesto the segment mây clrive reâssessment, such as upratingthe pipeline's operâting pressure, or chânBes inoperating conditions, such as significant pressurecycling. Change managemenf is addressecl in section 11.

A-4,8 Performance Measures

The following performânce measures shall be docu-mented for the manufacturing threat, in order to cstab-Iish the effectiveness of tlìe program and forconfirmation of the inspection intervalÌ

(n) number of hydrostatic test failures câused by man-ufacturilìg defects

(l¡) number of leaks due to manufactu¡ir'ìg defects

A-5 CONSTRUCTION THREAT (PIPE GIRTH WELD,FABRICATION WEtD, WRINKLE BEND ORBUCKLE, STRIPPÊD THREADS/BROKEN PIPE/couPLrNG)

A-5.1 Scope

Section A-5 provides an integrity managemelìt plânto address the threat, and methods of integrity assess-ment âlìd mitigation, for construcLion concerns. Cotì-structioù is defined in this context as pipe girfh weld,fab¡ication weld, wrinkle bend or buckle, strippedtlìreâds, brokerì pipe, or coupling (see Fig. A-5).

Tlìis section outli[es the integrity manâgement pro-cess for construction concerns in generâ1, and also coverssome specific issues. Pipeline incident analysis has iden-tifìecl consfruction among the causes of past inciclents.

A-5.2 Gather¡ng, Rev¡ew¡ng, and lntegratíng Data

The folìowing minimal data sets shc¡ulcl be collectedfor each segmenl arìd reviewed before a risk assessmentcan be conducted. This data is collected to support per-formirìg risk assessment ând for speciâl considerations,such as identifying severe situ¡tions roquiring more orâdditional activities.

(n) pipe material(ú) wtinkle bend identification(c) coupling identificâtion(d) post-construction coupling reinforcement(r) welding procedures

f) post-corÌstruction girth weld ¡einforcement(,9 NDT information on welds(ir) hydrostatic test information(i) pipe inspection reports (bell Ìrole)

0) potentiaì for outside forces (see section A-9)(k) soil properties and depth of cove¡ fo¡ wrinkle

bendsll) maximum temperâture ranges for wrinkle beuds(¡¡) berrd radii and degrees of angle change for wrin-

kle belds(,r) operating pressure hìstory and expecLecl opcra-

tion, including significant pressure cycÌing and fatiguemecha¡ism

Whe¡e the operâtor is missilìg data, conservativeassumptiorìs shall be used when performing the riskassessment or, alternativel, the segment shall be priori-tized hìgher.

A-5.3 Cr¡ter¡a and R¡sk Assessment

For girth weÌds, a ¡eview of tlìe weidilìg proceduresand NDT irìforñation is lequired to asce¡tain that thewelds â¡e adequate.

53

('opy right O 201 0 by rhe A rììerican Socicty of M cchanrcal Erìgi'ìccrs. f¿QhNo rcproducrion nìay be nrade ofrhis rn¿rcrial wilhoutwri encorsenlof^SME.'(¡)d

F¡g. A-5 lntegr¡ty Management Plan, Construction Threat(P¡pe G¡rth Wetd, Fabrication Wetd, Wrinkte Bend or Buckte, Stripped Threads/Broken Pipe/Coupting;

Simpt¡f¡ed Process: Prescript¡ve)

54

Copyright O 20l0 by lhc Anìerican soci(ly of MeclraIìical Fnginerrs. ffrNo reproducrion m¿y be made ofthis material wirhour wrillcr conserìt of ASMll. '(4)d

Criter¡a andrìsk âssêssmenl

Determineassessment

interval

Responses andmit¡gation

Other informat¡onto other threats

ASME 831.8S"2010

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For fabrication weìds, a review of the welding proce-dures and NDT information, as well âs a review of forcesdue to Brourìd settlement or other outsicle loads, isrequired to âsccrtâirì that the welds ¿ìte âdequate.

For w¡inkle bends and buckles as well âs couplings,leports of visual inspection should be reviewecl kt ascer-tain tlìei¡ continued integrjty. Potential movement ofthe pipeline may câuse âdditionaÌ lateral and/or axialshesses. Information reÌative to pipe movement slìouldbe reviewed, such as temperature range, bend radius,deglee ofbend, depth ofcover, and soil properties. Theseare important factors in determining whether or notbends aIe being subjected to injurious s[resses or strains.

The cxistence of tlìese construction-related threatsalone does not pose an integrity issue. The presence offhese threats in conjunction with the potentiêl for out-si<le fo¡ces significantly increases the likelihood of anevent. The data must be ir'ìtegratecl and evaluated todetermine where these c01ìstruction charactcristics coex-ist with external or or¡tside force poterìtial.

A-5.4 lntegr¡ty Assessment

For construction threats, the inspectiotì should be bydatâ integration, exâminâtion, and evaluation fot tlìreatstlìat are coincident witlì the potential for ground move-ment o¡ outside forces that will impact the pipe.

A-5.5 Responses and M¡tigat¡on

TIìe operator shall select tlìe apptopriate preventionpractices. For tlììs fhreât, the operator should developexcavation protocols to ensu¡e the pipe is noL moved andadditiolìal stresses introduced. In addition, the operâtorshould conduct examinatior'ìs and evaluations everytime the pipe is exposed. Potential threats should bemitigated by proactive p¡ocedures that require inspec-tion, repait replacerÌent, or reilìforcement when theneed to inspect the pipelilìe fo¡ other maintenance rea-sons occurs,

A-5.6 Other Data

During the inspection activities, the operator may dis-cover other data that sììoulcl be used when performingrisk assessments fo¡ other th¡eâts. For example, certainseam types may be more susceptible to acceleraLed cor-rosion. It is appropriate to use this information whenconductilìg risk assessments for external o¡ inte¡nal

A-5.7 Assessment lnterval

Pe¡irdic assessment is not requi¡ed. Clìanges to thesegment or chalìges in land use may drive reassessment.Change management is addressed in section 11.

A-5.8 Performance Measures

The folÌowing performance measures shall be docu-mented for the constìuction threat, ilì order to establishlhe effectiveness of the program:

(n) number of leaks or failures due k) constÌuctiondefects

(ú) nu¡nber of girtlì welds/couplings reinforced/removed

(c) number of w¡inkle l¡ends removed(d) nunber of wrinkle bend inspections(e) numbe¡ of fabrication wclds repaired/removed

A-6 EQUIPMENT THREAT (GASKETS AND O-RINGs,CONTROL/REtIEF, SEAL/PUMP PACKING)

A-6.1 Scope

Section A-6 provides an integrity management plânto âdd¡ess the threat, ¿rnd methods of integrity assess-nìent ànd mitigation, for pipeline equipment failurc.Equipment is definecl in tlìis context as pipeline fâcilitiesother thân pipe and pipe components. Meter/reguìatorand compressor stalior'ìs a¡e typical equipmerìt locations(see Fig. A-(r.

This sectien outlines the iiìtegrity manâgement pro-cess for equipment in general and also covers somespecific issues. Pipeline incident analysis has identifiedpressure control and relief equipment, Baskets andO-rings, alrd seal/pump packing arnong tlìe câuses ofpast incidents.

A-6.2 Gather¡ng, Rev¡ew¡ng, and lntegrat¡ng Data

'The following minimêl dafâ sets should be collectedfor each segment and reviewed befo¡e a Ìisk assessmentcan be conducted. 'l'his data is collected in support ofperforming risk âssessment alìd fo¡ special considera-tions, such âs identifyilìg severe situatiolrs requi¡ingmore or additional actìvities.

(/r) year of installation of failed equipment(¿t) regulâtor valve failu¡e ilìformation(c) r'elief valve failure info¡mation(r?) flange gasket failure information(¿) regulator set point drift (outside of manufacturer's

tolerances)

f) relief set point ctrift(g) O-ring failure irìformatìorì(/t) seal/packing informaliorìWhere the opelator is missing datâ, conscrvative

assumptions shall be used when performing the riskassessment ot altelnâtively, the segment shall be priori-tized higher.

A-6,3 Criteria and Risk Assessment

Certain relief and regulato¡ valves are known to haveLheir set points drift. These equipment types mây requireextra scrutiny.

Certain gasket types are prone to premature degrada-tion. These equipment types may require more^frequentleak checks.

55

Copyright O 2010 by lhe Americân Sociefy of Mecharìical Engineers r&'(qxNo be nrade of this rnaterial wrthout written consent of ASl\48

F¡g. A-6 lntesrity Management Plan, Equipment Threat(Gasket and O-R¡ng, ControURetiel Seat/Pump Packing; 5imptified Process: Prescriptive)

56

copyriÊhr O 2r,10 by rhe Arnerican Society ofMechanical EnBincers. r&No Ìeproduclion may bc rnadc of rlìis mârcrial wirhout \ rittcn conscnl of ASN4E. "@X

Integrity assessment{O&M procedures)

Determineassessment

interval

Responses andmitigat¡on

Other ¡nformat¡onto other threats

a5¡¡E 831.85-2010

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A-6.4 lntegrity Assessment

The inspections for this tìÌreat are normâlly conductedper the requirements of the O&M procedures. Thescproceclures delail when inspections and maìr'ìtelìance ofequipment shall be perlormed and wlìat specific actìonis requirecl. Additional or more-frequenL inspectionsmay be necessâry if the equipment has a leak and failu¡ehisto¡y.

A-ó.5 Responses and Mit¡gat¡on

Replâccmerìt or repair of the equipment mây berequircd.

A-ó.6 Other Data

During lhe inspection activities, the operator may dis-cover other data that sl-ìorrld be used wììelì performiùgrisk âssessments for other threats. For example, wheninspecting gaskets at aboveground facilities, it is cliscov-ered that there has been a lightnirìg strike. It is appro-priate to use this i¡ìformatior-r wlìen conductilìg rìskassessments for tlìe weather-ÌeÌated and outside forcethreat.

A-6.7 Assessment lnterva(

TIìe inte¡val for assessme[t is contained witlìin theoperation and maintenance procedure fo¡ the specifictypes of equipment.

Chânges to the segment may drive reassessment. Thischange management is addressed ìn section 11.

A-6.8 Performance Measures

The foÌlowjrìg performance measures shall be docu-meùted for the equipment threat, in orde¡ to establìslìthe effectiveness of the program and fo¡ confirmationof the inspection interval:

(¿) rrumber of regulalor valve failures(l¡) number of relicf valvc f¿ilurcs(c) number of gasket or O-r'ing failures(¿/) r'rumber of leaks due to equipment fâilures

A-7 THIRD.PARTY DAMAGE THREAT ITHIRD-PARTYINFLICTED DAMAGE (IMMEDIATÐ,VANDALISM, PREVIOUSLY DAMAGED PIPE]

A-7.1 Scope

Section A-7 provides an integrity marìâgement planfo address the th¡eat, arìd methods of integrity assess-ment and mitigation, for third-party dâmâge. Third-pârty damage is defined in thìs context âs third-partyinflicted damage witlì immediâte failure, vandalism,and previously damaged pipe (see Fig. A-7).

'I'his section outÌilìes tlìe integrity managemerìt pro-cess fo¡ tlìird-party damage in general and also coverssome specific issues. Pipeline incident analysis has iden-tìfied tlìird-party damage arnong the causes of pastincidents.

A-7.2 Gather¡ng, Revlewing, and lntegrating Data

lhe folÌowing minimaÌ data scts should be collecteclfor each segment and reviewed before a risk assessmentcan be conclucted. l'his data is collected in support ofperforming risk assessment and for special considerâ-tions, such as iderìtifyir'ìg scverc situâtions requiringmore or additional activities.

(d) vandalism incidents(ú) pipe inspection reports (bell hole) where tlìe pipe

has been lìit(c) leak reports resulting frorn immediale damaBe(d) incidents involvirg previous damage(¿) inline ilìspection results for dents alìcl gouges al

top half of pipe

f) one-call records(g) encroaclìment reco¡ds

A-7.3 Cr¡ter¡a and Risk Assessment

Review of clata may show susceptibility to certaintypes of third-party inflicted dama8e. Deficiencìes inthese areas require mitiga tion as ou tlined below Becausetlìird-pârty clamage is a time ¡nclependent tlìreat, evenwitlì the absence of àny of these indicators, thi¡d-partydamage can occur ât ârìy time and strong preventionmeasures are necessa¡t especially in areas of concern.

Specific land uses, such as agricultural lands witl-rshallow deptlì ofcover, may bc moresusceptible to third-party damage.

A-7.4 lntegrity Assessment

Observance of erìc¡oaclìments or third-party damageis âccomplished during pâtrols ancl leak surveys conclucted as required by the operations and maintelìânceprocedures. However, in the case of incidents ilìvolvingpreviously darnaged pipe, it is frequently found afte¡tlìe fact tlìat tlìe defect was levealed indirectÌy eventlìough it may have l¡een adequalely described by a

previous inspection such as an inline inspectiolì. Tlìere-fore, tlìe operator should investigate suspicious indica-tions discovered by inspections thal cannot be directlyirterpreted, but may be correìaled with known excava-tion activities revealed by one-call ¡ecords or otherencroachment records,

A-7.5 Responses and M¡t¡gation

Mitigation of third-pâ¡fy dama8e is tlìrough preven-tive âctions or repair of damage found as a ¡esult ofinspectioûs, examinations, or lests performed. Thc oper-ato¡ shall ensure tlìat third-party damage preventionprograms are in pìace and functioning. Additional pre-vention âctivities may be warranted as provided in scc-tion 7, such as deveìopment of a damage preventionplan.

A-7.6 Other Data

During the inspection and examination activities, tlìeoperator may discover other data that should be usecl

57

Cop) r i8b{ O 201 U by lhe Arnerican Society of Mechalical Engi eero. f&No rcprocluctrorr rnay bc rnadc oIrhis rnaterial wilhoul \rrirren conscnt ofASN4E. '(qX

Gathering, review¡ng,and ¡ntegrating data

Cr¡ter¡a andrisk assessment

lntegr¡ty assessment{O&M Drocedures)

Responses andmit¡gat¡on

Determineassessmenl

¡ntervEl

Fig. A-7 lntegr¡ty Management Ptan, Third-Party Damage Threat [Third-Party lnfticted Damage (lmmediâte),Vandât¡sm, Prev¡ousty Damaged Pipe; Simptified Process: Prescript¡vel

58

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wlìelì performing risk assessments for othe¡ threats. Forexample, wheû monitoring ân encroachment, exposedpipe may indicate active exfernal cortosion. It is appr.o-priate to use this i¡ìfornìatiorì wlìen conductiltg riskassessùrents for extetnal cortosion.

A-7.7 Assessment lnterval

Assessment shall be performed periodically. It is rec-c¡lnmended that it be performed annualÌy. Changes tothe segment may drive rcassessment, Change manage-ment is add¡essed in section 11.

A-7.8 Performance Measures

Tlìe folìowing performance measures shall be docu-mer'ìted for the third-pârty threat in order to establishLhe effectiveness of the program and for confi¡mationof thc inspection intervâl:

(n) numbel of leaks or failu¡es caused by third-partydamage

(ú) numbe¡ of leaks o¡ failures caused by previouslydamaged pipe

(c) number of leaks or faiÌures caused by vandalism(d) nurnber of repairs implemenfed âs â result of

third-parfy damage prior to a leak o¡ faìh.r¡e

4.8 INCORRECT OPERATIONS THREAT

A-8.1 Scope

Section A-8 provides an integrity mânagement planto address the threat, and methods of integrity assess-menl ând mitigation, Éor inco¡rect operatìons. Incorrectoperations â¡e defined in tlìis context as incor¡ectope¡atirìg procedures or failure to follow a procedure(see Fig. A'8).

Tlìis sectiorì outlines the ¡ntegrity mânagement pro-cess for irìcorrect opl]¡ations itì general ancl also coverssome specific issucs. Pipeline ¡ncident analysis has iden-tified incorrect operations amorìg the causes of pastincidents.

A-8.2 Gathering, Reviewing, and lntegrat¡ng Data

The following minimaì data se ts should be collectedfor each segment and reviewed before a risk assessmentcân be conducted. This clata is collecled in support ofperforming nsk assessment alìd for special considera'tions, such as identifying severe situations requiringmore or additional activities.

(n) proccdure review info¡mation(ú) audit information(c) faiÌures caused by incorrect operation

A-8.3 Cr¡teria and R¡sk Assessment

If the data shows thl] operation and mainter'ìânce areperformed in accordance with operation and mainte-nance procedures, the procedu¡es are correct, and tl-ìatoperating personnel are adeqLratcly qualified to fulfill

the reqLLirenìents of the procedure, no additional assess-ment is reqr¡ired. Deficierìcies ¡n these areas rcquirc miti.gation as outlined below.

A-8.4 lntegrity Assessment

Thc audits and reviews are normally conducted onarì ongoilìg basis. These inspections are condLrcted bycorì1pany personnel and/or by third-party experts.

A-8.5 Responses and Mitigation

Mitigâtion in this instance is prevention. The operatorshall ensu¡e thât procedures a¡e current, the persor'rnelare adequâtely quâlified, and that the following of proce-du¡es is enfo¡ced.

The operator should have a program to qualify opera-tion and maintenance personnel for each Âctivìty thatthey perform. This program should include initial quali-fication and periodic reassessment of qualification. Cer-tification by recognized orgânizâtions may be includedin this progrâm.

In addition, a strong internal review or audit programby inhouse experts or third-party experts is neccssâry.

A-8,ó Other Data

During tlìe inspection activities, llìe operator may dis-cover oLher data that should be used when performingrisk assessnents for other threats. For exarnple, whenreviewing records required by procedures, it is discov-ered that there have l¡een several unreported elìcroach-ments by third parties. lt is appropriate to use thisinformation whcn conducting risk assessmelìts fo¡third-party damage.

A-8.7 Assessment lnterval

Assessment shall be performed periodically and isrecommended to be performed annually.

Changcs to the segment may drive revision of proce-du¡es and additional training of personnel. Changemanâgcmcrìt is addressed in section 11.

A-8,8 Performance Measures

'I'he following performance measures shall be docu-mented fo¡ the incorrec[ operations thrcat, in order tocstablìslì the effcctiveness of tÌrc program and for confir-mation of tlìe inspection ìr'ìte¡val:

(n) numbe¡ ol leaks or failures caused by ir'ìcorrectoperations

lD) number of auclits/reviews conducted(c) numbe¡ of findings per audit/review, classified

by severity(d) number of changes to pÌocedures due to audits/

59

Copyri8hr O 201 0 by lhe American Socicry o f Mcchânicâl UngiDccrs. ffr\o reprcrluclron nìay be rìrade ofrhis nìâlcrial uithoul \lriltcn conscnr ofASVE. '(Qy

Fig. A-8 lntegr¡ty Management Ptan, lncorrect Operations Threat (S¡mptified Process: Prescript¡ve)

Criteria andrisk assessment

lntegrity assessment(O&M procedures,

aud¡ts/reviews)

Determineassessment

intervâl

Responses andmitigation

(personnel qualif¡cationand procedures)

Other ¡nformationto other threats

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ASME 831.8S.2010

A-9 WEATHER-RELATED AND OUTSIDE FORCETHREAT (EARTH MOVEMENI, HEAVY RAINSOR FLOODS, COLD WEATHER, LIGHTNING)

A-9.1 Scope

Section A-9 provides an integrjty managemcnt planto address the tlì¡eaf, and methods of integrity assess-merìt âncl mitigatìon, for weâthe¡-related and outsideforce concerns. Weatl'rer-¡el¿rted and oulside force isdefinecl in this cor'ìtext as earlh movement, heavy rairìsor floocls, cold weathcr, and lighhìin¡l (see Fig. A-9).

'fhis section outlines the integtity managemelìt p¡o-cess for weather-relâted and outside fotce tlìreâts ìr'ì gen-eral, alld also covets somc specific issues. t-or seismicthreats, PR 268-9823, Gr-Lidelines for the Seismic Designand Assessment of Nâtural Gas arrd LiquidHydrocarbon Pipelines, or si¡¡ilar rrretlìodologies maybe used. PipeÌine incident analysis has identifiedweather-related and outsidc force damage among tlìecauses of past incidents.

4"9.2 Gathering, Reviewing, and lntegrãting Data

The following minimâl data sets should be coÌlecteclfor eaclì segment and reviewed before a risk assessmentcan be conductecl. This datâ ìs collected in support ofperfo¡rning risk assessment and for special considera-tions, such as identifying sevete situations ¡equiringmore or aclditional activities.

(û) joirìt method (rnechanical couplì¡g, acetyleneweld, arc weld)

(/') topography and soil conditions (unstabÌe slopes,wâter crossings, wate¡ proximity, soiÌ liquefactionssusceptibility)

(c) eârthquake fâûÌt(d) profile of ground accelerâtion near fault zones

(greater than 0.29 acceleration)(¿) depth of frost linef) yeâr of installation(g) pipe grade, diameter, and waÌl thickness (inte¡naÌ

st¡ess calculation added to external loading; total stressnot to exceed 100% SMYS)

Where the operaLor is missing d¿rL¿t. conservativeassumptions shall be used when performing the riskassessment or, alternativel, the segment shall be priori-tizcd in a higher category based on the expectcd worstcase of the missing data.

A-9.3 Criter¡a and Risk Assessment

Pipe may be susccptible to extreme loading at thefollowing locatiotìs:

(n) where the pipeline crosses a fault lirre(ú) whe¡e the pipeline traverses steep slopes(c) where the pipeline crosses wateÌ or is acljacent to

wJter, r)r where tlìc rìvcr bottom is m,rving(d) where the pipeline is äubject to extreme surface

loâcls lhat cause settlement to underlying soils

(c) where blasting neâr tlìe pìpelirìe is occurringf) wìre¡ the pipe is at or above tlìe frost lìne(,9) wlìere tlìe soil is subject to liquefaction(/¡) where grourìd accelerâtio1ì exceeds 0.29At locations meetirìg any of the abovc, the tlìreat shall

be evaÌuatecl. At locations wlìere facilities are prone toliglìtning strikes, the threat slìall be evaluated.

4"9.4 lntegrity Assessment

Fo¡ weather-related and outside force fh¡eats, infeg-rity ¿ìssessments, includilìg irìspectior'ìs, cxaminâtions,and evaluations, aIe normally conducted per the rcqui¡e-ments of tlìe O&M procedures. Additional or mor.e-frequent inspections may be necessary, depending otrleak and faiìure information.

A-9.5 Responses and M¡tigat¡on

Repairs or replacernent of pipe shall be in acco¡dance1¡/itlì th'r ASMII 831.8 Code ând other applicable irrdus-try standârds. Other methods of mitìgation may ilìcludestabilizâtioù of the soil, stâbilization of the pipe or pipejoints, ¡elocatio¡ì of the pipeline, lowering of the pipelìrìebelow tlì(] frosl line fo¡ cold-weather situations, and pro-tection of âboveground facilities from lightning.

Preventiorì activities are most app¡op¡iate for tltisthreat. Ifa pipeline fâlls within the listed susceptibilities,line patrolling should be used to perform su¡face assess-ments. ln certain locations, such as known slide areasor areas of ongoing subsidence, the proBress of themovement should be monitored.

A-9.6 Other Data

During tlìe irìspection activities, the operator may clis-cover oLheÌ data tlìât slìould be used when performing¡isk assessmelts for other threâts. For example, when apipe¡ine is patrolled, evidcnce of third-party encroach-ment may be discovered. It is appropriate to use thisinformation when conducting risk assessments for lhethird-party damage threat.

A-9.7 Assessment lntervat

Changes to the segment, or bhe land use around thesegment, may drive reassessment if thc changes âffectpipeline integrity. If no changes are experienced, reas-sessment is not required. Change marìagement isadd¡essed in section 11.

A-9.8 Pefformance Measures

The foÌlowing performance measures shall be docu-mented for the weather-related and outside fo¡ce threat,irì order to estâblish the effectiveness of the programalìd for confirmation of the inspectìolì intelvalÌ

(¿) number of leaks tlìat are weathe¡-related or dueto outside force

(b) number of repair, replacement, or relocâtionactiolìs due to weatlìer-related or outside force tlìreats

61

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Fig. A-9 lntegr¡ty Management Plan, Weather-Related and Outs¡de Force Threat(Earth Movement, Heavy Rains or Floods, Cotd Weather, Lightn¡ng; S¡mptified Process¡ Prescr¡pt¡ve)

Responses andmitigation

Other ¡nformat¡onto other threêts

Determ¡neassessmenl

interval

62

À5ME 831.85-2010

NONMANDATORY APPENDIX B

DIRECT ASSESSMENT PROCESS

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This Nonmandatory Appendix provides informâtionabout the direct assessment process. Direct assessmentis one integrity assessDlent methodology that can beused withi¡r the integ¡ity management program.

B-1 EXTERNAL CORROSION DIRECT ASSESSMENT

ExternaÌ corrosion direct assessment (ECDA) is âstructlìred process that is a methoc{ for establislììng tlìeintegrity of underground pipelines. Às described herein,it applies to extenìal cor¡osion on pipeline segments.The process integratcs facilities data, and cu¡rent andlÌisto¡ical fieÌd inspections and tests, with the plìysicalcharacte¡istics of a pipeline. Nonintrusive (typicallyaboveground or indi¡ect) examin.ltions are used to esti-maLe the success of the coffosiolì protection. The ECDAprocess requires that some excavatiolìs be made. Excava-tions confirm tlìe abjlily of the indirect examìnâtions tolocâte active and pasLcorrosion Iocâtions on tlìe pipelirìe,as well as areas of significânt coâting dâmage at whichcorrosion could occur. In thc overall ECDA process, suchevaluations a¡c defined as direc[ exâminâtions. Post-assessrÌrelìt is ¡equired to de[ermine a co¡rosion rate toset the reinspectiorì intervâI, ¡eâssess tlìe performancemeasu¡es and their current applicability, plus etìsute theâssumptions made in the previous steps remain correct.

The ECDA process, therefore, has rhe following fourcomporìents:

(n) pre-âssessment(D) indirect examinations(c) direct exâminations(d) post-assessmenf'lhe focus of the ECDA approach described in this

Standa¡cl is to identify locations where external corro-sion defects may have fo¡med. It is ¡ecognized that evi-dence of other threats, suclì as mechanical damage andstress corrosion crâcking (SCC), may be detected dutingthe ECDA process. While implementing ECDA, theoperator is advised to conduct examinations that willalso dctect nonexternal corrosion Lh¡eâts.

The prescriptive ECDA process requires the use ofât least two indirect examìnatìon methods, verificationchecks by excavation and direct examir'ìâtion, and post-assessment vaìidatìon (sorne indirect examination toolscan be used to defect corrosion on unco¿ìted pipe; fu¡therwork is being pursued on tlìis issue). 'Ihe process hasbeen designed to allow it to be used as an initial baselirìe

inspection of a pipeìine segment. In addition, it cân bemodified for a performance-based plan.

B-1.1 Pre-Assessment'Ihe pre-assessment step p¡ovides guidance for selec-

tion of each pipeline segment beilg considered and thenthe appropriate indirect examinatiorì method. Data inte-gration and analyses arc also uscd to identify or defineECDA regions alon8 tlìe pipeline being

'rvaluâted. An

ECD^ region ìs âr'ì area witlìilì a pipeÌilìe segment(s)that th(¡ dafâ ilìdicates ìs suitâble for thc sâme indirectexarnilìatiorì methods. Dìfferent ECDA regions carì useclifferent sets of complementaly indirect exârninationmetlìods.

An operator rìust begirì by ilìtegrating the lìistoricalknowledge of lhe pipeline, including facilities informa-tion, operating history, and the results of p¡ioraboveground indirect examinations and direct examina-tions of the pipe, to assess the integrity of the pipe.Norìmandatory Appendix A lisls the minimum set ofpipelilìe data that shalÌ be reviewed for external corro-sion tlì¡eats, but additional dâta may be collected toimprove effectiveness. Tlìese clata should be analyzedto estimate the extent and likelihoocl of priol corrosion.Other lactors, such as adjacent pipelines, encroachingstluctures, oI significant operational chantes that mâyimpede ECDA, should also be considered.

This pre-assessment step estimates locations of priorand active corlosion, The operator must deternine ifthe ECDA processes can be used in these locations.

After ECDA regions are defined, the operato¡ is toselect at least two indirect examination methods: oneprimary and a second complementaly examinationmethod. Two tools are required, because no one metlìodreliably locates indications of defects unde¡ all condi-tions. The secondary (complementâry) mefhod is to beselected based on the expectation that it should validatelhe first and possibly identify a¡eas that ¡nay lìave beenmissed by the p¡imary method. A te¡tiâ¡y methodshoulcl be conside¡ed for a¡e¿ìs wlìere the first two meth-ocls provide conflicting results.

B-1,2 lndirect Exam¡nat¡ons

The primary and complemeÌìtary indi¡ect examilìa-tions are used to detect coatir'ìg defects. FiÌst tlìe operatorpelforms the primary examinâtion of the regions identified abt¡ve. The secend step is examination of the sameregion with the complementary method. Locâtions for

63

Copyright O 2010 by lhe ArÌericân Society ofMechanical Ëngiueers -aí!ræNo rndy bc rnade of lhrs malerial r\ ilhoul wrillerì conse¡r of AS\41-

ASME 831.85-2010

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complcmerìtary examinâtion should include tlìose thatmay lìave preserìted some difficulty clurìng primaryexaminafion, âll areas ofspecial conce¡n, or wlìere recentchanges (as indicated by historicâl data) have occurred.This secondary metlìod must evaluate at least 25% ofeach ËCDA region.

Primary and complementary examination results a¡ecompared to dete¡mine if new [aults have been identi-fied. lf new coating fault locations a¡e identified durirìgtlìe complemenfary exâmination, the operator nìustexplâirì the cause of tlìe cliscrepalcy and/or conductaddifional (tertiary) indirect examinations. If adclitionalcoating fauJts are identified by the terliary examinationand/or the additional corrosion faults identified duringcomplemenfary examinâtion are not readily explained,the operator must return to the pre-assessment stagearìd select âlì alternative assessment method.

Within each ECDA region, tlìe coâting faults shouldbe characterized (e,g., as isolated or contilìuous) andprioritized based on expected co¡¡osion severity fromthe indirect examinafion data. Ëor exarnple, based onpipeline history, thc operator may use the corrosion sfate(e.9., anodic/anodic, anodic/cathodic, or cathodic/cathodic) to determine which coating fâults are mostlikely to correspond to the sevetely cotroded areas.Those.rre.rs wherc the potelt(ial lor sevele corrosion ishighest should receive excavation priority.

Evaluations of alÌ wall losses found are to be usedto establish appropriate reinspection ând/o¡ retcstingirìtervals. The same indirect exâmination methods maynot be âppropriate for eve¡y pipeline or segment beingevaluated. Clìânges to lhe metlìodologies nìây be wa¡-ranted, depending on lhe inspection results.

B-1.3 D¡rect Exam¡nat¡ons

This stage requires excavations to expose the pipesurface for metal-loss measurements, estimated corro-sion growtlì ¡ates, and measurements of cor¡osion mot-phology estimated during indirect exâmination. Thegoal of these excavalions is to coÌlect enough ìnformationto characterize lhe co¡¡osion defects that may be presenton the pipeline segment being assessed and validate tlìeindirect examinâtion methods.

Direct examilìatiolìs are to be made aL one o¡ moreIocations from eaclì ECDA regioù inwhich coating faullshave been found and one o¡ more locatiotìs where para.B-1.2 found no anomalies. AlÌ co¡rosion defects foundduring each direct examination should be measured,documented, and remediated as required.

At each excavation, the operator should measure andlecord Berìeric elìvironmental characteristics (such as

soil resìstivit, hydrology, drainage, etc.). This data canbe used to estimate corrosien ¡ates. Average corrosionrates reìâted to soil resistivity are provided in lable B-1,

If tlìe operatol can provide a souÌrd fechnical bâsisfor using other corrosiolì ¡ates or estimates based on

Tabte B-1 Corrosion Rates Related to So¡lResist¡vity

Coros¡on Rate,

mils/yr Soit Resistiv¡ty, ohm-cm

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r2

>15 000 and no active corrosion1000-15 000 and/or active co(osion<1 000 (worst case)

dircct cxâminatiolì ÌÌreâsuremelìts, the actuâì râte canbe used in lieu of those shown in the above table.

The seve¡ity of all coûosion clefects at the excavatedcoating fault areas should tlìen be determirìed usingASME B31G or a similar method. The maximum dìmen-sions of possible corlosion at unexamined coating defcctlocâtions must be estimâted as follows:

(n) if no othe¡ data âre available, it must be assumedthât the mâximum defect dimensions are twice thât ofthe largest defect depth and length measured duringdirecl examination.

(D) altematively, statistical arìalysis results of defectseverity from tlìe corlosion measuremelìts performedduring direct examination can be used to eslimale thedefect severity at otlìer coating faults, h this case, theoperator must excavate and perform direct examirìationson â lârge enough sample of coating faults to make a

stâtistical estimâte of tlìe st¡ucturâl inteBrity of¡emaìning corrosion clefects at an 807o confidence level.

The operator is k) continue excavations, measuÌe-ments, categorizâtion, and repairs untiÌ the remainingdefects with their associated growth rates â¡e such tÌìatthere will be rìo structu¡âlly significânt defects in thepipeÌine segment before the next integrity assessment isperformecl.

B-1.4 Post-Assessment

Post-âssessment sets reìnspection inte¡vals, providesa vâlidation clìeck où the overall ECDA process, andprovìdes performance measures for integ¡ìfy manage-ment programs. The reinspectiolì ilìte¡val is a functionof the validâtion and repâir activity.

For tlìc ECD^ prescriptive prograrn, if tlìe operatorchooses to excavate all tlìe indications found by indirectexamination and repairs âll defects that could grow tofailure in 10 yr, then the reinspection inte¡val shall be10 yr. lf tlìe operator elects to excavate a smaller set ofindicatiorìs, then tlìe inte¡val shall be 5 yr, provided arrevaluatiorì is performed to ensu¡e all defects that couldgrow to failure in 10 yr (at an 80% confidence level) arerepaired,

In the ECDA prescriptive program for pipelìne seg-ments operating at or below 30% SMYS, the reinspectioninterval is also determined by the level of repair andcorrespondiìg interval, and the rnuch thicker pipe wâll,as follows. lf the operator chooses to excavâte all theindications found by indirect exarninâtion and repairs

64

Copyright O 2010 by the A,¡erican Society ofMcchanical Engiùecrs &No ron rnay bc rn¿dc oflhis rndrcrial \lilhout wntten co'ìscrìl of ASMI_

ASME 831,aS-2010

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all defects tlìât could grow to failure in 20 yr, the rein-spection ilìtelvâl shall be 20 yr. If the operator eÌects toexcavate a smaller set of inclications, then the intervalslìalÌ be 10 yr, provided arì evaluâtion is performecl toensure aìl defects thât couìd grow to failure in 20 yr (atan 80o/o conficlence level) are repaired.

Tlìe validation check on tlìe overall ECDA processconsists ofperforming ât least one additional excavation.Tììis excavation is lo be pe¡formed ât the coating defectIocation that was esLimated to coûtain the next mostseve¡e defcct not previously subjected to a direct exami-nation. Cor¡osion severity at this location should bedetermìned and compared wi[lì the maximum severitypredicted du¡ing the direct examinations.

(n) If the actuaÌ corrosiorì defect severìty is less thânhalf of the maximum p¡êdìctcd sevcrit, validâtion iscomplete.

(b) If the actual cor¡osiorÌ severity is between the max-imum p¡edicted severity and oneìalf of the r¡aximumpredicted severity, double tlìe preclicted maximumseverity and do a second recaliblatÌon dig. If the actualcorrosion is âgâin less than the maximum predictedseverity, then validation is complete. Il nol, the ECDAprocess may not be appropriate alrd the operator must

reevaluate and rcset the Browth rate prediction. Theoperator must tlìen perfo¡m additional diÌect exanina-tiorrs as required and repeât the post-assessmerìtevaluation.

(c) If the actual corrosiorì severity is greater thân themaximum predicted severity, tlìe ECDA process maynot be appropriate and the operator must reevaluatea¡ìd reset the g¡owth Ìâte predictìon. The opl]rator mustperform additional direct cxâminations as rcquired andrepeat the post-assessment cvaluatiolì.

ECDA. validatiorì rnay also be performcd usjng histoli-cal data from prior excavâtions on fhc same pipeline.Prior excêvation locations must be assessed to determinetlìat tlìey are equivalent to the ECDA region bcing con-side¡ed and such a comparison is valicl. If validity isestablislìed, then maxìmum co¡rosion depths may beestimated from tlìe p¡ìor data.

B-2 INTERNAI. CORROSION DIRECT ASSESSMENT

Tlìis section has been rcmovecl with publicatìorì ofNACE SP0206 DCICDA. Operators are encourâgcd touse the appropriate NACE standard practice or an alter-nate and teclìnically justified lnethodology.

65

Copyright O 2010 by the Amencan Soci€ty of Mechanical Engineers.@No ay bc rìradc of rhis rnarcrial wirlìout wriltcn conscnr of

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ASME 831.8S.2010

NONMAN DATORY APPENDIX C

PREPARATION OF TECHNICAL INQUIRIES

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C-1 INTRODUCTION

Tlìe ASME 831 Committee, Code fo¡ Prcssure Pipin¡1,will consider written lequests fo¡ interpretafions andrcvisions of lhe Code rules, and develop new rules ifdictated by teclìnoÌogical developùent. Th': Commit-tee's activities i¡ this regard are limited strictly to inter-pretations of the rules or to the consideration ofrevisionsto the present rules on the basis of new data or teclìnol-ogy. As a matter oÉ published policy, ASME does notàpprove, certify, rate, or endorse any item/ construction/proprietâry device, or activity, and, accordingly, inquir-ies reqrtirirìg such consideration will be returned. More-over, ASME does not âct as a cotìsultarìt on specificen8ineering problems or on the general applicatiorì orunde$tânding oi llìe Code ruÌes. lf, based orì the ìnquiryinformation submitted, it is the opìnìon of tlìcCommittee tl-ìat the ir'ìquìrcr should seek professionalassistance, the inquiry will be returned with the recom-mendation that such assistance be obtained.

Inquiries that do not p¡ovide the info¡mation neectedfor the Commjttee's full understandìr'rg will be ¡eturlìed.

C-2 REQUIREMENTS

hquiries shall be limited stÌictly to interpretations ofthe rules or to the consideration of ¡evisions to the pres-ent rules on tlìe bâsisofnew data or technology. lnquiriesshall meet the following requirements:

(n) Scopc. Involve a single rule or closely related rulesìn the scope of the Code. An inquiry letter concerningun¡elatcd subjects wiÌl be returnecl.

(b) Bockgrourtd. State the purpose of llìe inquiry,which would be eilher to obtain an ir'ìterprelation ofCode rules or lo propose considerâtion of a revisionto the present rules. Provide concisely the informationneeded for the Commitlee's understanding of theìnquiry, being sure to include reference to the applicableCode Section, Edition, Addenda, paragraphs, figures,and lables. If skefcÌìes are provìcled, they shall be limitedto the scopc of the inquiry.

(c) lnqtity ShttcLwe('I) Propose.l Queslion(s). The inquily shaÌl be stâted

in a co¡densed and precise question format, omittingsuperfluous background informatio[, ancl, whereâppropriâte, composed in such a way that "yes" or "no"(perhaps wilh provisos) would be an acceptable reply.Thc inquiry statement should be technically and editori-ally correct.

(2) Proposed Replll(ies). Provide a proposed replystâting wlìat it is believed tlìat the Code requires. If, inthe inqui¡er's opinion, a revision to the Code is needed,recommended wording shall be proviclecl in addition toinformation justifyir'ìg the chânge.

C-3 SUBMITTAL

Inquiries should be submitted in typewritten form;however, legible handw¡itten inqui¡ies will be consid-ered. They shall include the name and mailing addressof the inquiret and be mailed to the following address:

Secreta¡yASME 831 CommitteeThree Park AvenueNew York, NY 100i6-5990

Copyrighr @ 2010 by rhc Arncrican Sociely ofMcclìanical Lnginccrs. f&No rcproduclio[ ûìay be rnade oltlris rnâleflal wilhoul lrritlen conserìr of AS\.4E. 'fgx

I NTENTIONALLY LEFI BLANK

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