ASME B31.8S (2016).pdf

ASME B31.8S-2016 (Revision of ASME B31.8S-2014) Managing System Integrity of Gas Pipelines ASME Code for Pressure Piping, B31 Supplement to ASME B31.8 A N I N T E R N AT I O N A L P I P I N G CO D E ® ASME B31.8S-2016 (Revision of ASME B31.8S-2014) Managing System Integrity of Gas Pipelines ASME Code for Pressure Piping, B31 Supplement to ASME B31.8 AN INTERNATIONAL PIPING CODE® Date of Issuance: October 31, 2016 The next edition of this Code is scheduled for publication in 2018. ASME issues written replies to inquiries concerning interpretations of technical aspects of this Code. Interpretations are published under http://go.asme.org/Interpretations. Periodically certain actions of the B31 Committees may be published as Cases. Cases are published on the ASME Web site under the Committee Pages at http://go.asme.org/B31committee as they are issued. 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Participation by federal agency representative(s) or person(s) affiliated with industry is not to be interpreted as government or industry endorsement of this code or standard. ASME accepts responsibility for only those interpretations of this document issued in accordance with the established ASME procedures and policies, which precludes the issuance of interpretations by individuals. No part of this document may be reproduced in any form, in an electronic retrieval system or otherwise, without the prior written permission of the publisher. The American Society of Mechanical Engineers Two Park Avenue, New York, NY 10016-5990 Copyright © 2016 by THE AMERICAN SOCIETY OF MECHANICAL ENGINEERS All rights reserved Printed in U.S.A. . . . . . . . .1-1 Integrity Management Plan. . . . . . . . . . . . . . vi Summary of Changes . . . 36 14 References and Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Wrinkle Bend or Buckle. . . . . . . .1-1 Integrity Management Plan. . . . . . . . . . . . . . Prescriptive Integrity Management Plan 25 13-1 Hierarchy of Terminology for Integrity Assessment . . . . . . . . . . . . . . . . . .2. . . . . . . . . . . . 9 5 Risk Assessment . . . . . . . . . . . . . .1-2 Integrity Management Plan Process Flow Diagram . . . . . Third-Party Damage Threat [Third-Party Inflicted Damage (Immediate). . . . . . . . . . . . . Stripped Threads/Broken Pipe/Coupling. . . . . . . . . 27 9 Performance Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Internal Corrosion Threat (Simplified Process: Prescriptive) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 7. . . . . . . . . . . . . 21 8 Integrity Management Plan . . . . . . 54 A-7. . . . . . . . . . . . . 45 B Direct Assessment Process . Construction Threat (Pipe Girth Weld. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Simplified Process: Prescriptive) . . . . . . . . . . . . . . . . . . . . . . . . . . . Simplified Process: Prescriptive) . . . . Simplified Process: Prescriptive] . . . . Seal/Pump Packing. 46 A-3. . . Equipment Threat (Gasket and O-Ring. . . . . . . . . . . . . . . . Vandalism. . . . . . . . . . . . . . . . Control/Relief. . . . . . . 7 4 Gathering. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fabrication Weld. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . External Corrosion Threat (Simplified Process: Prescriptive) . . . . . . . . . . . . . . . . . . . . . . . . . . . . x 1 Introduction . . . . . . . . . . . . . . . . . . . . . . . 36 A-2. . . . . . and Acronyms . . . . . . . . . . . . . . . . . . 4 3. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-1 Integrity Management Plan. . . . . . . . . . . . . . . . . . . . . . . . . . Simplified Process: Prescriptive) . . . . . Reviewing. . . . . . . . . . . v Committee Roster . . . . . . . . 17 7 Responses to Integrity Assessments and Mitigation (Repair and Prevention) . . . . . . . . . . . . . . . . . . . . . . . .1-1 Integrity Management Plan. 63 C Preparation of Technical Inquiries . . . . . . . . . . . . . 2 3 Consequences . . . . . . . . . . . . . . .1-1 Integrity Management Plan. . . . . . . . . . . . . . . . . . .4-1 Potential Impact Area . . . . . . . . . . . 52 A-6. . . . . . . . . . . . . . . .1-1 Integrity Management Plan. . . . . . . . . . . . . . . . . . . . . . . CONTENTS Foreword . . . . . . . . . . . . . . . . . . . . . . . . . . 56 A-8. . . . . . . . . . 35 13 Terms. . . 48 A-5. . . . . 64 Figures 2. . . . . . . . . . . . . . 34 12 Quality Control Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Definitions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-1 Timing for Scheduled Responses: Time-Dependent Threats. . . . . Previously Damaged Pipe. . . . . . . . . . . . . . 34 11 Management of Change Plan . . . . . . . . . . . . . . . . . . and Integrating Data . . . . . . . . . . . . . . . . . . Manufacturing Threat (Pipe Seam and Pipe. . . . 29 10 Communications Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 2 Integrity Management Program Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57 iii . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 6 Integrity Assessment . . . . . . . . . . . . . . . . . . . . . . .1-1 Integrity Management Program Elements . . . . . . . . . . . . . . 3 2. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 Nonmandatory Appendices A Threat Process Charts and Prescriptive Integrity Management Plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 4. . . . . . . . . . . . . . . .2. . . . . . . . . . . . . . . . . Weather-Related and Outside Force Threat (Earth Movement. . . . . . . . . . .4-2 Overall Performance Measures . . . . . . . . . . . . . . . . . .6. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-1 Example of Integrity Management Plan for Hypothetical Pipeline Segment (Segment Data: Line 1. . . . . .4. . . . . . 30 9. . . . . . . . . . . . . . . Simplified Process: Prescriptive) . . . . . . . .3. . . . . . . . . . . . . .4-1 Performance Metrics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 8. . . . . 22 8. . . . . . .3-1 Typical Data Sources for Pipeline Integrity Program . . . . . . .1-1 Integrity Management Plan. . . . . . . . . . . . . . . . . . . . .3. . . . . . . . Incorrect Operations Threat (Simplified Process: Prescriptive) . . . . . . . . . . . . . . . . . . . . . . . . .2. . . . . Cold Weather. . . . . . . 50 A-4. . .1-1 Integrity Assessment Intervals: Time-Dependent Threats. . . . . . .3. . . . . . . . . . . . . . . . . . .1-1 Acceptable Threat Prevention and Repair Methods . . . . . . . 29 8. . . . 33 A-4. . . . . . . . 14 7. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prescriptive Integrity Management Plan . . . . . . 32 9. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-1 Integrity Management Plan. . . . . . . . . . . . . Internal and External Corrosion. . . Lightning. .4-2 Example of Integrity Management Plan for Hypothetical Pipeline Segment (Integrity Assessment Plan: Line 1. . Segment 3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Segment 3) . . . . . . . . 51 iv . . Heavy Rains or Floods. . . . . . 10 5. . . .4-3 Example of Integrity Management Plan for Hypothetical Pipeline Segment (Mitigation Plan: Line 1. . .4-1 SCC Crack Severity Criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 9. . . . . .A-9. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 A-10. . . . .1-1 Actions Following Discovery of SCC During Excavation . . Segment 3) . . . . . . . . . 61 Tables 4. .1-1 Data Elements for Prescriptive Pipeline Integrity Program . . . . . . . . . . . . .3-1 Performance Measures . . . . . . . Some of the international standards issued on this subject were utilized as resources for writing this Code. The gas pipeline industry needed to address many technical concerns before an integrity management standard could be written. The task force that developed this Code hopes that it has achieved that intent.8. which was used as a model for the format of this Code. This Code becomes mandatory if and when pipeline regulators include it as a requirement in their regulations. Particular recognition is given to API and their liquids integrity management standard. It also provides two approaches for developing an integrity management program: a prescriptive approach and a performance. The 2012 Edition of the Supplement was a compilation of the 2010 Edition and the revisions that occurred following the issuance of the 2010 Edition. This Code is a process code that describes the process an operator may use to develop an integrity management program. 2016. FOREWORD Pipeline system operators continuously work to improve the safety of their systems and operations. In the United States. A number of initiatives were undertaken by the industry to answer these questions. API Std 1160. Pipeline operators in a number of countries are currently utilizing risk-based or risk-management principles to improve the safety of their systems. and is designed to supplement B31. The 2010 Supplement was approved by the B31 Standards Committee and by the ASME Board on Pressure Technology Codes and Standards. both liquid and gas pipeline operators have been working with their regulators for several years to develop a more systematic approach to pipeline safety integrity management. comprehensive. The 2004 Supplement was approved by the B31 Standards Committee and by the ASME Board on Pressure Technology Codes and Standards. and integrated approach to managing the safety and integrity of pipeline systems. The 2016 Edition of the Supplement is a compilation of the 2014 Edition and the revisions that have occurred since the issuance of the 2014 Edition. The intent of this Code is to provide a systematic. 20 reports were issued that provided the responses required to complete the 2001 edition of this Code. The 2014 Edition of the Supplement was a compilation of the 2012 Edition and the revisions that occurred since the issuance of the 2012 Edition. ASME Code for Pressure Piping. (The list of these reports is included in the reference section of this Code.) This Code is nonmandatory. Not all operators or countries will decide to implement this Code.or risk-based approach. as a result of two years of intensive work by a number of technical experts in their fields. This Edition was approved by ANSI on August 26. Gas Transmission and Distribution Piping Systems. v . J. J. Chair J. B. Moore. R. Chair. E. ExxonMobil Production Co. R. ONEOK Partners. Chin. T. J. Frikken. W. Turner Industries Group. Rosenfeld. Newton. Southwest Gas Corp. Leewis and Associates. Inc. ExxonMobil Pipeline Co. J. J. Livingston. Inc. Jr. Air Liquide D. Anderson. Hovis. Leewis. The American Society of Mechanical R. Energy Transfer J. Meyer. P.8 EXECUTIVE COMMITTEE A. A. Columbia Pipeline Group M. Maslowski. Huston. W. ExxonMobil Research and Engineering Co. D. D. Tatar. C. FM Global R. Hayden. L. C. American Electric Power B31. Fee. Dickinson. T. Frehse. Secretary. Sperko Engineering Services. Ex-Officio Member. Becken. K. Kiefner/Applus — RTD C. Becht IV. Fronek Power Systems. L. D. K. Mechlowicz. Christian. Huriaux. BP Exploration (Alaska). Columbia Pipeline Group M. Consultant R. Stress Engineering Services. DOT — PHMSA C. Pressure Piping Engineering Associates. Rosen USA D. Monday. Vilminot. Flenner Engineering Services W. B. Consultant M. Bojarczuk. Inc. Resolute Energy Corp. Ltd. Engineers B. D. W. A. J. R. J. Fluor Enterprises. Powell. Consultant R. Acapella Engineering Services. W. Becht Engineering Co. Louis Perry Group C. J. Page Southerland Page. Inc. Bodenhamer. Willbros Professional Services.S. Jolly. ArcelorMittal Global R&D K. E. PE LLC Engineers M. Flenner. Jacobs Engineering J. D. B31. Inc. Manegold. Kiefner/Applus — RTD R. Meyer. L. E. Vice Chair A. Inc. CCM 2000 J. Black & Veatch R. H. A. D. Christensen. Leewis. Frey. Southern California Gas Co. Schmitz. Chin. Richard D. Fetzner. J. LLC D. Pacific Gas and Electric Co. Inc. Mauro. Eskridge. Ex-Officio Member. Victaulic E. KBR J. Petru. J. Southwest Gas Corp. NICE R. J. W. K. Dominion Resources. Vice Chair. Flowserve/Gestra USA A. ASME B31 COMMITTEE Code for Pressure Piping (The following is the roster of the Committee at the time of approval of this Code. K. Clarke. Inc. TransCanada Pipelines Ltd. J. A. W. The American Society of Mechanical Engineers J. G. Becht Engineering Co. J. D.) STANDARDS COMMITTEE OFFICERS J. Kivela. Swezy. Inc. S&B Infrastructure Private. Boiler Code Tech. Maslowski. D. Kaplan.. Lucius Pitkin. A. Secretary STANDARDS COMMITTEE PERSONNEL R. M. ExxonMobil Pipeline Co. S. LP R. Secretary. G. W. Willis. Maslowski. W. Maslowski. Rosenfeld. Appleby. BP Exploration (Alaska). M. TransCanada Pipelines U. Jr. W. Consultant G. Lamontagne Pipeline Assessment Corp. KBR S. D. Appleby. J. K. Grichuk. P. Walsh. K. J.S. Engineering M. E. M. TransCanada Pipelines U. Inc. Anderson. Inc. Ltd. D. J. Leewis and Associates. J. S. Israni. Jr. Inc. D. D. S. Integrity Solutions. Huriaux. K. Haupt. Appleby. LLC D. Kinder Morgan A. Inc. Frey. Sinha. Sperko. Rahoi. Energy Transfer A. Reamey.. R. G. Deubler. Fetzner. NiSource. U. W. W.. D. Southern California Gas Co. J. W. Rinaca. F.S. Team Industries. Haim. Energy Experts International M. LLC M. Consultant vi . Gragg. C. LLC C. Nayyar. Johnson. H. Campbell. Zhou. The American Society of Mechanical E. P. Spectra Energy A. Kaplan.8 GAS TRANSMISSION AND DISTRIBUTION PIPING SYSTEMS SECTION COMMITTEE R. Bullock. K. P. Ex-Officio Member. S. M. ExxonMobil Pipeline Co. S. Lamontagne. J. Lewis. Southern California Gas Co. Southern California Gas Co. E. Inc. D. A. Leewis. J. ArcelorMittal Global R&D R. Process Performance Improvement Consultants M. Emeaba. Southern California Gas Co. Zhou. FMC Technologies. Zerella. Canadoil D. Resolute Energy Corp. A. Huriaux. Atmos Energy S. Volgstadt and Associates. Appleby. Delegate. ExxonMobil Pipeline Co.8 SUBGROUP ON DESIGN. M.S.S. C. J. P.E. E. A. D. Zurcher. TransCanada Corp. E. Walsh. FMC Technologies. D. J. Johnson. B31. Becken. Gailing. Williamson. Mechlowicz. Consultant D. Vice Chair. Al-Muslim. B. B. Contributing Member. Contributing Member. Chair. Southwest Gas Corp. ExxonMobil Production Co. Whitley. J. Tansey. Barry. Whitley. EDG Consulting Engineering G. B. E. Hovis. Ortega. Robichaux II. PE LLC D. K. V. Canadoil A. Raymundo Engineering P. Ltd. Inc. Boring. D. Vaughan. B. P.8 SUBGROUP ON DISTRIBUTION E. DOT — PHMSA F. Southern California Gas Co. Energy Transfer C. BP Exploration (Alaska). Hudson. H. Delegate. B. B31. DOT — PHMSA M. K. R. J. Robichaux. Newton. Southern California Gas Co. Newton. E. Integrity Solutions. M. M. ExxonMobil Pipeline Co. Nguyen. W. NiSource. J. LP R. BMT Fleet Technology. Southern California Gas Co. American Gas Association M. J. Nguyen. G. Chair. J. Southern California Gas Co. TransCanada Pipelines Ltd. Haim. Atmos Energy J. M. Israni. Kivela. Spectra B31. K. Kaplan. EN Engineering M. Schmidt.S. Huriaux. Clarke. W. Mechlowicz. W. Robichaux. American Gas Association vii . Powell. Dickinson. Groot. Vaughan. Chin. E. J. M. R. G. H. S. TransCanada Pipelines U. R. Frehse. J. T. E. Frehse. Soni. Ltd. LP R. Inc. KBR R. BP Exploration (Alaska). R. Volgstadt and Associates. Ltd. Vice Chair. Southwest Gas Corp. Kaplan. W. J. S&B Engineers and Constructors K. A. H. Energy Experts International R. Moore. Lewis. Inc. Reed. F. Tiwari. Appleby. D. M. Wright. J. Becken. Chevron R. J. R. Gupta. Inc. Columbia Pipeline Group J. S. Energy Transfer L. Ltd. S&B Engineers and Constructors J. W. L. S&B Infrastructure Private. Schmidt. Emeaba. Energy Experts International E. National Grid B31. NiSource. Pacific Gas and Electric Co. BG Group D. Kostelka. A. D. Chair. Zerella. Raymundo. Anderson. National Transportation Safety Board E. W.8 SUBGROUP ON OPERATION AND MAINTENANCE D. Ltd. U. Kiefner/Applus — RTD S. Enable Midstream Partners J. Leewis and Associates. Bullock. Inc. Bingham. M.S. K. Ortega. Inc. R. Richard D. Volgstadt. S. U. Consultant R. J. K. Zhou. M. Mojica. W. W. Powell. F. K. Huyse. Rosen USA R. Consultant W. MATERIALS. Kiefner/Applus — RTD M.8 SUBGROUP ON EDITORIAL REVIEW K. Gragg. BG Group A. Inc. Groot. KBR H. C. Ltd. W. ONEOK Partners. KBR M. ONEOK Partners. M. Tiwari. M. National Transportation Safety Board H. E. ONEOK Partners. S&B Infrastructure Private. K. B. National Grid M. ArcelorMittal Global R&D M. Spectra Energy K. P. TransCanada Pipelines Ltd. Wright Tech Services. W. Kaplan. Southern California Gas Co. S&B Engineers and Constructors D. U. W. R. D. Gailing. Chair. Romero. Inc. Fee. Inc. EDG Consulting Engineering M. D. Saudi Aramco M. BMT Fleet Technology. Ltd. Engineers India Ltd.8 SUBGROUP ON OFFSHORE PIPELINES K. P. Gailing. J. DOT — PHMSA J. Rosenfeld. LLC B. L. K. R. BMT Fleet Technology. Atmos Energy J. B31. Kieba. Haim. Kieba. Rosenfeld. C. Inc. Nguyen. Pacific Gas and Electric R. Volgstadt and Associates. Contributing Member. Huston. J. Newton. LP J. Kiefner and Associates. J. Manegold. J. A. Kurilla. Chair. Walsh. K. R. Bharat Petroleum Corp. Volgstadt. Fetzner. T. L. M. Brandt. Contributing Member. W. L. J. C. Wilson. ENSTAR Natural Gas Co. Inc. AND CONSTRUCTION M. Volgstadt. Campbell. Bell. Mullaney. K. The American Society of Mechanical V. Babu. Ltd. J. R. Zerella. Keifner and Associates. Kinder Morgan R. Oil Industry Safety Directorate V. A. Vice Chair. Marini. Engineers India Ltd. Flenner Engineering Services K. Contributing Member. Nayyar. M. Consultant J. Inc. TransCanada Corp. J. D. Leewis and Associates. Columbia Pipeline Group B. E. George. Sinha. Leewis. Vice Chair. British Columbia Boiler and Pressure Vessel Safety R.8 GAS TRANSMISSION AND DISTRIBUTION PIPING SYSTEMS. DNV GL D.M. Boiler Code Tech. Ferguson. S. Adler. K. Sivaraman. Ltd. Stursma. Reliance Gas Transportation Infrastructure Ltd. M. S. Sharma. The Equity Engineering Group R. Ltd. Coomes. Inc. A. Secretary. Nguyen. P. Victaulic J. Bonneville Power Administration R. Wright. R. E. J. D. Consultant U. Yu. Meiring. Mauro. Sahani. Gail India Ltd. Page Southerland Page. ONEOK Partners. Chair. Chair. Lau. K. Rhode Island Department of Labor B31 EXECUTIVE COMMITTEE J. J. A. Feng. Vaughan. Uprety. West. B31. R. Ohio Department of Commerce R. E. E. Iowa Utilities Board D. Petroleum and Natural Gas Regulatory Board R. GSPL India Transco. F. B. Stellar Energy Systems S. NiSource. T. Antaki. Swezy. Electric Power Research Institute W. Saudi Aramco W. Grichuk. Spectra C. Thornton. NICE R. Maier. INDIA IWG N. Mittal. Silvia. Inc. Lamontagne. J. T. K. J. Lucius Pitkin. A. AECOM viii . J. TDW India Ltd. Gujarat State Petronet Ltd. Powell. D. K. E. B31 CONFERENCE GROUP A. Pacific Gas and Electric Co. Frey. Hanrath. Alabama Public Service Commission D. Moore. Jagger. T. Metallurgist P. Al-Muslim. Reed. Inc. Q. J. Alberta Boilers Safety Association Inspectors R. Department of Housing/Boiler Branch Section P. M. Hainsworth. R. Gujarat State Petronet Ltd. Radhakrishnan. Manitoba Department of Labour Inspections A. W. Inc. Jr. Meyer. Flenner. Prakash. ASME India PVT. J. Appleby. W. D. R. R. Maslowski. The American Society of Mechanical Engineers A. Frikken. The American Society of Mechanical W. A. Inc. National Grid D. Inc. Jr. Gingrich. Nebraska Department of Labor C. Rosen USA J. Willlis. J. American Electric Power D. Chair. Livingston. R. A. Maslowski. Engineers Z. Division of Labor/State of Colorado Boiler I. W. Fluor Enterprises. Inc. Inc. Becht Engineering Co. LP P. Stress Engineering Services. Karnatak. F. L. Sullivan. Chair. Petrofac Onshore Engineering and Construction A. Louis Perry Group D.. Wilson. Sperko. Inc. Starr. H. Bechtel Corp. A. State of Kentucky. Consultant D. Sher. S. Lighthouse Assistance. Becht Engineering Co. M. T. D. Engineers S. Hayden. New Hampshire Public Utilities Commission J. S&B Engineers and Constructors D. J. L.8 INTERNATIONAL REVIEW GROUP R. D. Johnson Controls Corp. Wickham. State of Connecticut D. Zurcher. H. Inc. Kutz. Manegold. P. W.. A. Consultant J. Wu. D. The National Board of Boiler and Pressure Vessel K. Process Engineers and Constructors. LLC J. Sperko Engineering Services. Contributing Member. Gujarat Gas Co. Kolovich. Harvey. C. Feng. Process Performance Improvement Consultants M. ExxonMobil Pipeline Co. H. China Petroleum Pipeline Engineering Corp. ExxonMobil Pipeline Co. W. J. J. Thielsch Engineering. Secretary. Fire and Building Safety Division/Indiana W. A. M. Lewis. G. Appleby. Meghani. Couch. China Petroleum Pipeline Engineering Corp. PetroChina Pipeline Co. Mault. PetroChina Pipeline Co. P. Christian. B31 FABRICATION AND EXAMINATION COMMITTEE J. B31. D’Urso. L. Wu. G. LLC W. G. Randeria. Nalbandian. Wright Tech Services. S. Troppman. Lamontagne Pipeline Assessment Corp. Secretary. T. A. Bounds. J. Alion Science and Technology R. Canadoil C. D. Leishear. Meyer. P. W. Smith. Consultant J. W. J. Arnett. A. TQM Engineering PC N. Mayers. Hassan. Sato. Minichiello. G.. P. W. A. Deubler. Cakir-Kavcar. Pickell. SSD. Chair. Haupt. Jr. Hart. Paulin. Grichuk. BP Exploration (Alaska). Chevron ETC R. A. Eskridge. J. B. Pressure Piping Engineering Associates. LLC D. L. T. Inc. M. Vice Chair. Engelkemier. Rodabaugh. E. Secretary. Bechtel Corp. General Dynamics Electric Boat P. Collins. O’Brien. Louis Perry Group B. Holbrook. Contributing Member. Becht Engineering Co. P. D. Rosenfeld. Bechtel National. Graziano. J. A. — Oil. CCM 2000 R. Antaki. Inc. Inc. Paulin Research Group M. J. F. Inc. Robleto. Jacobs Engineering J. Secretary. Melo. Fronek Power Systems. WPC Solutions. Consumo. Huntington Ingalls Industries. Fluor Enterprises. J. Rahoi. Newport News Shipbuilding J. R. Sr.. F. KBR D. G. Ellenberger. Kiefner/Applus — RTD D. The American Society of Mechanical C. E. J. Engineers M. Inc. Babcock Power. McCawley. D. Bechtel Corp. Lucas. Becht Engineering Co. A. Willbros Engineers. Sonatrach B31 MECHANICAL DESIGN TECHNICAL COMMITTEE G. Bethea. Inc. L. Honorary Member. Consultant G. A. J. NICE B. PGESCo Z. Fraser. Q. M. Leishear Engineering. Inc. The American Society of Mechanical Engineers W. B31 MATERIALS TECHNICAL COMMITTEE R. Inc. Consultant A. LLC C. H. McCabe. Gas and Chemicals T. Djilali. NASA Ames Research Center T. Jolly. Schmidt. A. Japan Power Engineering and Inspection Corp. Inc. Stanley Consultants. R. Koves. LLC R. Nayyar. Inc. Technip USA. Consultant ix . E. Berkeley Engineering and Research. Becht IV. P. R. Inc. A. Pi Engineering Software. Consultant A. C. Stevick. Flowserve/Gestra USA C. Chair. Fetzner. 1-1 Designator editorially revised 48 Figure A-3.2 Subparagraph (b) revised 7 3.1-1 Designator editorially revised 60 A-10.4-1 Designator editorially revised 51 Table A-4.2.1-1 Designator editorially revised 57 Figure A-8.6 Revised 56 Figure A-7.1 Second paragraph revised 19 6.8S-2016 was approved by the American National Standards Institute on August 26.1-1 Designator editorially revised 55 A-6. and subsequent paragraphs redesignated 46 Figure A-2.1-1 Designator editorially revised 54 Figure A-6. ASME B31.1-1 Designator editorially revised 50 Table A-4.3 Subparagraph (i) added 61 Figure A-10.3 Second paragraph revised 27 7.1 Revised 8 Figure 3. ASME B31.4.1-1 Designator editorially revised 52 Figure A-5.7 Revised 36 13 Definition of resident threat added 36 Figure 13-1 Revised 42 14 Updated 45 A-1 Designator added.8S-2016 SUMMARY OF CHANGES Following approval by the ASME B31 Committee and ASME.4 Third paragraph revised 17 6.2. 2016. (16).1-1 Designator editorially revised 63 B-1 Designator added. and after public review. and subsequent paragraphs redesignated x .1-1 Designator editorially revised 59 Figure A-9. ASME B31.4-1 Revised 10 4. Page Location Change 3 2.8S-2016 includes the following changes identified by a margin note. 8. processes. and construction of the pipe- improved safety and a reduction in the number of line. which integrity shall be an integral and continuing part of A comprehensive. technicians. constructed with ferrous materials and that transport The requirements for prescriptive-based and perfor- gas. the public.1 Scope mance-based program or an alternative international standard must meet or exceed that of a prescriptive This Code applies to onshore pipeline systems program. and construc- tively allocate resources for appropriate prevention. Complete records of material. The processes and approaches described This Code is intended for use by individuals and teams within this Code are applicable to the entire pipeline. ASME B31. There are also a number of consensus stan- This Code describes a process that an operator of a pipe- dards that may be used. ASME B31. detection. mitigation activities. The principles and processes embodied in integrity mance-based integrity management programs are management are applicable to all pipeline systems. customers. Such an integrity management shall be engineered into new pipeline systems from program provides the information for an operator to effec- initial planning. tion. Integrity management of a pipeline starts with sound detection. which enables the operator to achieve a ment program. design. design. the functional require- It covers both a prescriptive-based and a performance- ments for the line. and miti- and construction for the pipeline are essential for the gation activities necessary to produce a satisfactory integ- initiation of a good integrity management program. personnel using comprehensive. and processes. integrity management program. and mitigation want to continue providing safe and reliable delivery of activities. This does not preclude System integrity requires commitment by all operating conformance with the requirements of ASME B31. They are enumerated here so that the as a supplement to the ASME B31.8 Code will allow pipe- user of this Code can understand the breadth and depth to line operators to move closer to that goal. material selection. and/or specialists with specific primary goal of every pipeline system operator. material selection. management program provides the means to improve the Functional requirements for integrity management safety of pipeline systems. detection. and the physical system. shall be considered in order to The prescriptive process. or the environment. natural gas to their customers without adverse effects on employees. Typically. In addition. and based integrity management program. prevention. and mitigation activities that will result in design. and mitigation techni- ving and must be flexible. Operators expertise in prevention. operating Managing the integrity of a gas pipeline system is the personnel. engineers. detection. and integrated integrity the safe operation of a pipeline system. tools used. the program shall address the operator’s greater degree of flexibility in order to meet or exceed organization. An operator cannot proceed with the program should be customized to meet each operator’s performance-based integrity program until adequate unique conditions. This Code is specifically designed to provide the Nonmandatory Appendix A provides specific activities by operator (as defined in section 13) with the information threat categories that an operator shall follow in order to necessary to develop and implement an effective integrity produce a satisfactory prescriptive integrity management management program utilizing proven industry practices program. The level of assurance of a perfor- 1.8S-2016 MANAGING SYSTEM INTEGRITY OF GAS PIPELINES 1 INTRODUCTION on the pipeline condition required by the prescriptive- based program. rity management program. systematic. provide all the inspection. when followed explicitly. An integrity management ques employed. If a new line is to become a part of an reduce both the likelihood and consequences of incidents. Guidance for these activities is primarily provided in incidents. In order to have an effective integrity manage- analyses. including prevention.8. The program shall be periodically inspections are performed that provide the information 1 . 1. and improving a 1. The use of this Code details of this Code. as well as pipeline jurisdictional line system can use to assess and mitigate risks in order to safety regulations. systematic. a team will include managers. implementing. the requirements of this Code specifically in the areas An integrity management program is continuously evol- of inspection intervals. and inte- The performance-based integrity management program grated processes to safely operate and maintain pipeline alternative utilizes more data and more extensive risk systems.3 Integrity Management Principles Incident-free operation has been and continues to be A set of principles is the basis for the intent and specific the gas pipeline industry’s goal.2 Purpose and Objectives pipeline integrity management program. will meet this Code. provided in each of the sections in this Code. charged with planning. more effectively. These program elements variety of sources. The process shown in Figure 2. This Code requires that the operator document how its Risk assessment is an analytical process by which an integrity management program will address the key operator determines the types of adverse events or condi. This analytical process involves operator-specific program. or improve the mitigation of risks. The program elements depicted in Figure the risks of an incident are the greatest. events or conditions that will lead to a loss of integrity. In developing the program. This Code details two approaches to integrity vary in scope or complexity and use different methods management: a prescriptive method and a perfor- or techniques. and other information about a integrity management goals and objectives.8S-2016 evaluated and modified to accommodate changes in pipe. gather and analyze this information. the effectiveness opportunity to participate in the risk assessment of the activities shall be reassessed and modified to ensure process and that the results are communicated effectively. as the integrity ensure that all appropriate stakeholders are given the management program is implemented. OVERVIEW ging system integrity. New technologies may improve an opera. The ultimate goal of assessing risks is to mance-based method.1-2 provides a common and the nature and severity of the consequences that may basis to develop (and periodically re-evaluate) an occur following a failure. detect risks more options for inspection intervals. The results of the Performance measurement of the system and the performance-based method must meet or exceed the program itself is an integral part of a pipeline integrity results of the prescriptive method. and that the program utilizes the best set of prevention. decisions to assess and reduce those risks. and make prudent 2. The resulting performance- and practical. the integration of design. the continuing effectiveness of the program and all its activities. Each operator shall choose signif. This Code utilizes recognized industry tions that may impact pipeline integrity. testing. A key element of the integrity management framework is the integration of all pertinent 2. and can detection/mitigation plan to address the risks. The operator shall periodically gather new or The prescriptive method incorporates expected worst- additional information and system operating experience. construction. and of the program. By analyzing all of the systematic. Additionally. The operator is in the best position to collectively provide the basis for a comprehensive. ASME B31. system integrity plan. a pipeline operator shall consider his company’s specific tenance. based integrity management program can contain tor’s ability to prevent certain types of failures.1 General information when performing risk assessments. and integrated integrity management pertinent information. Periodic reports of the effectiveness of an the influx of new data and information about the system. Pipeline system operators should avail quently more data-intensive risk assessments and themselves of new technology as it becomes proven analyses can be completed. operating. mitigation. identify the most significant risks so that an operator The prescriptive integrity management method can develop an effective and prioritized prevention/ requires the least amount of data and analysis. Integrity management activities shall be communicated detection. A performance-based integrity management program 2 .1-1 are required for all integrity management programs. 2 INTEGRITY MANAGEMENT PROGRAM Information integration is a key component for mana. can achieved. process. Information that can impact an operator’s understanding This section describes the required elements of an of the important risks to a pipeline system comes from a integrity management program. program elements. case indication growth to establish intervals between These shall become part of revised risk assessments and successive integrity assessments in exchange for analyses that in turn may require adjustments to the reduced data requirements and less extensive analysis. Each operator shall the conditions at that time. and conse- as appropriate. inspection. these measures to monitor and evaluate the effectiveness line operation. inspection tools. based program cannot be implemented until the operator icant performance measures at the beginning of the has performed adequate integrity assessments that program and then periodically evaluate the results of provide the data for a performance-based program. The performance-based integrity management method New technology should be evaluated and implemented requires more knowledge of the pipeline. and mitigation activities that are available for to the appropriate stakeholders. main. operator’s integrity management program shall be issued Periodic evaluation is required to ensure the program and evaluated in order to continuously improve the takes appropriate advantage of improved technologies program. which are the very apply the processes to ensure that these goals are foundation of an integrity management program. Risk assessment practices for developing an integrity management also determines the likelihood or probability of those program. the operator can determine where program. Risk assessments. and prevention methods. A performance- management program. changes in the operating environment. and then pipeline system. be successfully implemented by following the steps Assessing risks to pipeline integrity is a continuous provided in this Code and Nonmandatory Appendix A. The process of managing integrity is an integrated and (a) Time Dependent iterative process. One of the causes reported by all pipeline systems for all situations. Although the steps depicted in Figure (1) external corrosion 2.1-2. additional data needs (-b) defective pipe may be identified to more accurately evaluate potential (2) welding/fabrication related threats. the selec.1-1 and 2. This Code recognizes operators is “unknown. Gas pipeline incident data have The processes for developing and implementing a been analyzed and classified by the Pipeline Research performance-based integrity management program are Committee International (PRCI) into 22 root causes. or individual threats. All threats to pipeline integrity operator shall be considered. in time. including branch and T-joints tions until an operator has confidence that a satisfactory (-b) defective fabrication weld assessment has been achieved. the data gathering and risk assessment (-a) defective pipe girth weld (circumferential) steps are tightly coupled and may require several itera. assessment intervals and mitigation (repair and preven- tion) methods 2. time factors and failure mode grouping. and mitigation shown in Figure 2. will The first step in managing integrity is identifying poten- confirm the performance-based options chosen by the tial threats to integrity. Operators may choose to their nature and growth characteristics. segments. The remaining 21 threats are grouped management programs and provides alternatives into nine categories of related failure types according commensurate with this need. (2) internal corrosion there is a significant amount of information flow and inter. and further either a prescriptive-based or a performance-based delineated by three time-related defect types. For example.8S-2016 Figure 2. The nine approach for their entire system. as well as instructions to the (a) a description of the risk analysis method employed more specific and detailed description of the individual (b) documentation of all of the applicable data for each elements that compose the remainder of this Code.1-2 are shown sequentially for ease of illustration.1-1 are required for all integrity activities shall be correctly addressed according to the management programs. categories are useful in identifying potential threats. individual lines. (3) stress corrosion cracking action among the different steps.” that is. included in this Code.1-1 Integrity Management Program Elements shall include the following in the integrity management A brief overview of the individual process steps is plan: provided in section 2. integrity assessment. (-c) wrinkle bend or buckle 3 . (-a) defective pipe seam While performing a risk assessment. ASME B31. segment and where it was obtained References to the specific detailed sections in this Code (c) a documented analysis for determining integrity are shown in Figures 2. Thus. The program elements Risk assessment.2 Integrity Threat Classification ð16Þ (d) a documented performance matrix that. Each of the 22 causes represents a threat to pipeline integ- There is no single “best” approach that is applicable to rity that shall be managed. (b) Resident tion of a risk assessment approach depends in part on (1) manufacturing-related defects what integrity-related data and information are available. no root cause or causes the importance of flexibility in designing integrity were identified. An example of such an (-d) miscellaneous interaction is corrosion at a location that also has (c) Time Independent third-party damage.. (1) third-party/mechanical damage The operator shall consider each threat individually or (-a) damage inflicted by first. ASME B31. The prescriptive (-b) previously damaged pipe (such as dents and/ approach delineated in Nonmandatory Appendix A or gouges) (delayed failure mode) enables the operator to conduct the threat analysis in (-c) vandalism the context of the nine categories. All 21 threats shall (2) incorrect operational procedure be considered when applying the performance-based (3) weather-related and outside force approach. second.8S-2016 Figure 2. (-a) cold weather 4 . more than one (-b) control/relief equipment malfunction threat occurring on a section of pipeline at the same (-c) seal/pump packing failure time) shall also be considered.e. or third in the nine categories when following the process selected parties (instantaneous/immediate failure) for each pipeline system or segment.1-2 Integrity Management Plan Process Flow Diagram (-d) stripped threads/broken pipe/coupling (-b) lightning failure (-c) heavy rains or floods (3) equipment (-d) earth movements (-a) gasket O-ring failure The interactive nature of threats (i. a dent may be identified 4 provides details for data gathering.1-2 is described below. and understand the public. The operator should tailor the method to meet the needs of the 2. ASME B31.3. 2. areas to be addressed and where additional data may be of value. Section for those threats.g. such as corrosion. presence of other threats and performing risk assessment Section 3 provides information on consequences. and inte.. and analytical methods may be used. the steps to be followed for a prescriptive program. or other integrity assessment operator performs the initial collection. Integrity assessment gration of relevant data and information that are needed to method selection is based on the threats that have understand the condition of the pipe. assessments. native courses of action and time frames for performing ating history. method may be required to address all the threats to a environmental. pressure compared to prescribed criteria (see Nonmandatory differential. through vary depending on the threat being assessed. Intervals.1 Identify Potential Pipeline Impact by Threat. pressure and the potential threats to that segment. excavation work near a pipeline). The integrity sary data and information that characterize the segments assessment methods are in-line inspection.3.5 Responses to Integrity Assessment. The output of a 2. and integra.3 The Integrity Management Process system. methods.2 Gathering. Through the be examined and evaluated to determine if they are actual integrated evaluation of the information and data defects or not. the testing. 2.3. maintenance.3. including any to rank the segments for integrity assessments. provides an understanding of the likelihood and conse- quences (see section 3) of an event. An initial screening risk assessment can be bene- The integrity management process depicted in Figure ficial in terms of focusing resources on the most important 2. when running a magnetic flux leakage (MFL) tool while tion of pipeline data. deficiencies in cathodic protection). checking for corrosion.2. and specific failures and concerns that integrity assessments. A useful refer. methods that can be applied based on the available 0178. the data assembled third-party or construction damage. 6. Repair activities for the anomalies discovered during inspection are identified and 5 . or relate to the introduc. Indications may be evaluated using an collected in the previous step. available data are are subjected to significant pressure cycles.g. and rates of change of pressure fluctuations. There are a variety of risk assessment ence to help the operator with this consideration is GRI 04. the risk assessment appropriate examination and evaluation tool. identify the location.. pipeline segment. to determine alter- on the operation. In this step.g. See management plan. assessments are selected and conducted. In this step. Risk assessments are required in order fatigue shall be considered by the operator. review.8S-2016 If the operational mode changes and pipeline segments Under the prescriptive approach. 2. Effect of Pressure Cycles on Gas Pipelines. Based on the risk assess- The first step in evaluating the potential threats for a pipe.3 Risk Assessment. design. Mitigation risk assessment should include the nature and location (Repair and Prevention). patrolling. schedules to respond to indications from inspections are developed. (e. enable the operator to prioritize the pipeline segments Each identified pipeline segment shall have the threats for appropriate actions that will be defined in the integrity considered individually or by the nine categories. reduce pipe Data and information from integrity assessments for a properties (e.. Section 6 provides details on tool those conditions or actions that affect defect growth selection and inspection. It is the operator’s responsibility to are unique to each system and segment will be document the analyses justifying the alternative courses needed. More than one integrity assessment specific threats to its integrity. This data element should be inte- grated with other data elements for other threats. field welding).4 Integrity Assessment. For local process identifies the location-specific events and/or internal or external metal loss. oper. as defined in para. data and the nature of the threats. been identified. the appropriate integrity line system or segment is to define and gather the neces. specific threat may be of value when considering the tion of new defects (e. and operational consequences of an inci. The types of data to support a risk assessment will A performance-based program may be able. for the prescriptive approach and risk assessment for the This program element involves the identification of poten. from the previous step are used to conduct a risk assess- Indications that are discovered during inspections shall ment of the pipeline system or segments. dent.3. and Setting Inspection of the most significant risks to the pipeline. ASME B31G or similar conditions that could lead to a pipeline failure. direct assessment. especially in areas of concern. ment made in the previous step. Appendix A). Relevant data and information also include of action or time frames. review. and Integrating Data.5. Reviewing. such as 2. Section 5 provides details on the criteria selection 2. In this step. The results of this step tial threats to the pipeline. The combined effect from other failure mechanisms that are performance-based approach relies on detailed risk considered to be present. Nonmandatory Appendix A provides para. For example. Information appropriate evaluation and analysis. performance-based approach. and to ensure that changes 6 .4. and other information is collected. as the system assessments. performed periodically within regular intervals and The operator shall also evaluate the effectiveness of its when substantial changes occur to the pipeline. emergency responders. Section 10 provides 2. The management systems and processes in supporting operator shall consider recent operating data. continues to operate.1-2 and discussed in 2. develop and implement a plan for effective communica- tions with employees. After the information and the current understanding of integrity initial integrity assessments have been performed. Furthermore. ASME B31. system or segment.1-1 and are described ment efforts. The operator shall collect improving the historical database of operating experience. if damage from excavation internal and external corrosion as well as static threats was identified as a significant risk to a particular such as seam weld defects and defective fabrication welds.8S-2016 initiated. information shall be retained and added to the database Furthermore. As new risks or new manifestations of previously operator has improved and updated information about known risks are identified. shall also be factored into future risk assessments. Risk assessment shall be repair activities. or maintenance are evaluated dule established that considers the timing of the practices for their potential risk impacts. In such instances. Pipeline systems section 8. The plan is the documentation of the execution and the environment in which they operate are seldom of each of the steps and the supporting analyses that are static. The plan shall be periodically updated to reflect new 2. Also.7 Reassess Risk. mitigation may be an appropriate alternative to a pipeline’s integrity for both time-dependent threats like inspection.4 Management of Change Plan. as appropriate. and Review Data. management plan is the outcome of applying the process depicted in Figure 2.3. or increased excavator awareness in conjunction information and analyses based on more extensive knowl- with inspection. operation. more effective excavation notification plan. This Code does not require a The mitigation alternatives and implementation time specific risk analysis model. only that the risk model frames for performance-based integrity management used can be shown to be effective. a hydrostatic test may demonstrate lines. The operator shall reflects the latest understanding of pipe condition. additional operating. This plan shall provide information to be below. to ensure that the analytical process 2. the plan shall consider Prevention practices are also implemented in this step.3. The integrity further information about communications plans. thus expanding and 2.6 Update. Section 7 provides tion of a performance-based integrity management plan. Those systems or segments with the highest risk accepted industry standards and practices. analyses will provide a better understanding of integrity. maintenance. Repairs are performed in accordance with deployed. The detailed risk programs may vary from the prescriptive requirements. The application of new technologies into the integrity porate data from risk assessment activities for other management program shall be evaluated for further use in threats. those practices that may address more than one For third-party damage prevention and low-stress pipe. Integrate. threat. The plan shall include prevention.4 Integrity Management Program local officials. performance information and periodically evaluate the success of its integrity assessment techniques. details on repair and prevention techniques.4.3 Communications Plan. A performance-based plan requires more detailed systems.4. Section 8 provides details on plan development. the information required for developing performance analyze the impact of any external changes that may measures to evaluate program effectiveness. Section 9 provides changes to the pipeline system design and operation. such as the program. The plan shall also have a sche. additional mitigative actions to the condition of the pipeline system or segment. the public. communicated to each stakeholder about the integrity plan and the results achieved. pipeline 2. detection. and jurisdictional authorities in order to The essential elements of an integrity management keep the public informed about their integrity manage- program are depicted in Figure 2. the updated risk assessment results shall of information used to support future risk assessments also be used to support scheduling of future integrity and integrity assessments. the operator may elect to conduct A performance-based integrity management plan damage-prevention activities such as increased public contains the same basic elements as a prescriptive communication. For example. edge about the pipeline. the threats. and the mitigative risk control activities. The results of integrity assessment. A systematic process shall be used to ensure conducted. changes to the pipeline and mitigation practices. system design. For instance. prior to implementation.1 Integrity Management Plan. consider sound integrity management decisions.2 Performance Plan. should be addressed first. and incor. 2. have occurred since the last risk assessment. that. internal inspection. the performance-based analyses that which will enable an operator to have a greater degree of lead to these conclusions shall be documented as part flexibility in the timing and methods for the implementa- of the integrity management program. This address these risks shall be performed.4. 7 . the user is advised to (SI Units) carefully observe the differentiation and use of pound mass r = 0. That section outlines the neces- sary documentation for the integrity management (2) A 762-mm diameter pipe with a maximum allowable oper- ating pressure of 6 900 kPa has a radius of impact of approxi- program. ft (m) tained. This section specifically addresses the consequence 115. and prevention activities. (mm) incorporated. is affected by a pipeline failure (potential impact area) in Btu/lbm (kJ/kg) order to evaluate the potential consequences of such an Ith = threshold heat flux. ft (m) ture is at least 32°F (0°C) is calculated using the following T = gas temperature. program.8 Code manages risk to pipeline integrity ao = sonic velocity of gas. °R (K) formula: γ = specific heat ratio of gas λ = release rate decay factor (U.69(30 in.5 Quality Control Plan.00315 · d p (lbm) and pound force (lbf) units. lower pressure pipeline will affect a smaller Risk is the mathematical product of the likelihood area than a larger diameter. mately 660 ft. or 2 both. mitigation activities. The radius of impact for natural gas whose methane + inert constituents +1 content is not less than 93%. Btu/hr-ft2 (kW/m2) event. r = 0.2 describes how to determine the area that HC = heat of combustion (lower or net heat value). (m) Paragraph 3. Risk may be decreased by reducing Equation (1) is derived from either the likelihood or the consequences of a failure. After these changes are made.) result from a failure. lbf/in. r = radius of impact. p = live pressure. ft/sec (m/s) by adjusting design and safety factors. and main.1 General diameter.69 · d p (1) NOTE: When performing these calculations.1 Typical Natural Gas. r = 0. operated. r = radius of impact. Customary Units) μ = combustion efficiency factor χg = emissivity factor r = 0. Section 11 discusses the important (1) A 30-in. The operator shall consider 8 ao Ith consequences of a potential failure when prioritizing inspections and mitigation activities.00315 ·d p = 0.S.2 (Pa) Q = flow factor 3.8S-2016 to the environment in which the pipeline operates are where evaluated.000 lb/in. ft-lbf/lb-mole °R (J/kmole K) does not exceed 1.00315 (762 mm)(6 900 kPa)1/2 3 CONSEQUENCES = 199.4. in.2)1/2 2. whose initial pressure R = gas constant.000 psig has a radius of impact of approxi- management. diameter pipe with a maximum allowable operating aspects of managing changes as they relate to integrity pressure of 1.6 ft 660 ft quality control purposes. and whose tempera. lbm/lb-mole (g/mole) diameter and pressure. inspections. including the processes. The section also discusses auditing of the mately 200 m.69· d p = 0. Section 12 discusses the evaluation of the integrity management program for = 654.450 psig (10 MPa). into future risk assessments p = pipeline segment’s maximum allowable operating to ensure that the risk assessment process addresses the pressure (MAOP). The results of the plan’s mitigative activities should be used as a feedback for systems and facilities EXAMPLES: design and operation. and inspection and RT x = maintenance frequencies as the potential consequences of m a failure increase. higher pressure pipeline. where The ASME B31. d = line diameter. psig (kPa) systems as currently configured. ASME B31. in. This has been done on an empirical basis Cd = discharge coefficient without quantifying the consequences of a failure. The area impacted is a function of the pipeline m = gas molecular weight. they shall be d = outside diameter of the pipeline.4 m 200 m Use of this equation shows that failure of a smaller 3.2 Potential Impact Area +1 x = 2 2( 1) ð16Þ 3.)(1. as appropriate. 920 Q pd r= · · g · ·Cd·HC · · portion of the risk equation.2. (probability) and the consequences of events that (See GRI-00/0189. 3.4-1).2. ment communities.1 must be derived for the actual gas composition or range of compositions being transported.00315). or gases transported (c) proximity of populations with limited or impaired at low temperatures such as may be encountered in arctic mobility (e. schools. hospitals. the interruption of service) operator may consider alternate models that calculate (h) public convenience and necessity impact areas and consider additional factors. (762-mm) pipe with an MAOP of 1. the factor may be significantly the impact zone. gas mixtures subject to a that may provide some level of protection) phase change during decompression.69 (0. impacts resulting from Considerations. particu- For gases outside the range of para. lighter-than-air flammable gases oper.3 Performance-Based Programs — Other (g) security of gas supply (e..450 psig (10 MPa). Integrity Management Program.1.g. Derivation of of a rupture of the pipeline segment. the natural gas factor of 0.69 (0.2. prisons. child-care centers.2 Other Gases.3 Consequence Factors to Consider 3. Potential Impact Radius Formulae for Vapor Cloud The ranking of these areas is an important element of Dispersion Subject to 49 CFR 192 risk assessment.2.2. Potential Impact potential impact area extends from the extremity of Radius Formulae for Flammable Gases Other Than the first affected circle to the extremity of the last affected Natural Gas Subject to 49 CFR 192 circle (see Figure 3. Although a similar methodology sections 4 and 5).2.00315) in para. Determining the likelihood of failure is the other important element of risk assessment (see 3. The Delivery Order DTRS56-02-D-70036.8S-2016 ð16Þ Figure 3. Depending When evaluating the consequences of a failure within on the gas composition. recreation areas). the user must larly in unprotected outside areas demonstrate the applicability of the methods and factors (d) property damage used in the determination of the potential impact area. following: This methodology may not be applicable or sufficient (a) population density for nonflammable gases. Additional guidance when considering the transported 3. toxic gases. ASME B31. may be used for other lighter-than-air flammable gases.4 Ranking of Potential Impact Areas.. 3. The gases other than natural gas can be found in the following: operator shall count the number of houses and individual (a) TTO Number 13. In a performance-based program. The richer the gas. Note that the consequences may vary based on the rich- ness of the gas transported and as a result of how the gas decompresses. then be used to help determine the relative consequences Delivery Order DTRS56-02-D-70036. retire- conditions. such as (i) potential for secondary failures depth of burial.000 psig (6 900 kPa). that may reduce impact areas.2.g. This housing unit count can (b) TTO Number 14 Integrity Management Program. the operator shall consider at least the higher or lower than 0. (including consideration of man-made or natural barriers ating above 1.2.4-1 Potential Impact Area GENERAL NOTE: This diagram represents the results for a 30-in. units in buildings within the potential impact area. the more important 8 . (e) environmental damage (f) effects of unignited gas releases 3. heavier-than-air (b) proximity of the population to the pipeline flammable gases. at a minimum.1 Prescriptive Integrity Management Programs. In addition. Geometry tool inspections mance-based integrity management programs. and other pipeline Pressure test operator documents specify and require collection of data that are suitable for integrity/risk assessment. incident information. operation and mainte- Crossings/casings nance plans.1 General Integrity Program This section provides a systematic process for pipeline Category Data operators to collect and effectively utilize the data Attribute data Pipe wall thickness elements necessary for risk assessment. Data are a key element in Equipment properties the decision-making process required for program imple- mentation.2. Pipe wall temperature Limited data sets shall be gathered to evaluate each Pipe inspection reports threat for prescriptive integrity management program OD/ID corrosion monitoring applications. CP inspections (CIS) those data elements specified in the prescriptive-based Coating condition inspections (DCVG) program requirements. CP system performance 4. Implementation of the integrity management pressures program will drive the collection and prioritization of Leak/failure history additional data elements required to more fully under. When the operator lacks sufficient data or Construction Year of installation where data quality is below requirements.8S-2016 defects and material properties are in modeling the char.1-1. Field coating methods Integration of the data elements is essential in order to Soil. AND INTEGRATING management programs require more data elements DATA than those listed in Nonmandatory Appendix A. miti. Depth of cover Pipeline operator procedures. All of the specified data elements Encroachments shall be available for each threat in order to perform Repairs the risk assessment. it Vandalism shall be assumed that the particular threat applies to External forces the pipeline segment being evaluated. and process/procedure Material properties reviews is also necessary. backfill obtain complete and accurate information needed for Inspection reports an integrity management program.1-1 Data Elements for Prescriptive Pipeline 4.2 Data Requirements The operator shall have a comprehensive plan for Operational Gas quality collecting all data sets.2. Cathodic protection (CP) installed Coating type 4. elements will vary between operators and within a acteristics of the failure.2. If such data are not available. Increasingly complex risk assess- ment methods applied in performance-based integrity 4 GATHERING. the operator Bending method shall follow the prescriptive-based processes as shown in Joining method. Manufacturing date gation techniques employed. There is no standard list of required data In-line inspections elements that apply to all pipeline systems for perfor. The quantity and specific data Audits and reviews 9 .2. The operator must first collect Flow rate the data required to perform a risk assessment (see Normal maximum and minimum operating section 5).2 Performance-Based Integrity Management Inspection Pressure tests Programs. ASME B31. Diameter Comprehensive pipeline and facility knowledge is an essential component of a performance-based integrity Seam type and joint factor management program. Table 4. the environment around the pipeline. Manufacturer tional history. These data lists are provided in Pressure fluctuations Nonmandatory Appendix A for each threat and summar. information on opera. given pipeline system. the operator shall collect. Coating condition stand and prevent/mitigate pipeline threats. REVIEWING. Bell hole inspections However. 4. Regulator/relief performance ized in Table 4. process and inspection results Nonmandatory Appendix A. These processes are needed to verify Manufacturer equipment data the quality and consistency of the data.3-1 are necessary for Operator standards/specifications integrity management program initiation. Generalized integrity assump- 4. the focus shall be on collecting the data necessary and how unsubstantiated data are used in the risk assess- to evaluate areas of concern and other specific areas of ment process. and hydrology. as examples. ASME B31. The operator will collect the data required to and accuracy of assessment results can be considered.4 Data Collection..5 Data Integration results of any prior risk or threat assessments are also Individual data elements shall be brought together and useful data sources. justification for exclusion of a threat from the integrity ciencies are found. Industry consortia and other Survey reports/drawings operators can also be useful information sources. A major strength of in the risk assessment and integrity management program an effective integrity management program lies in its processes. Root cause analyses of previous failures are a ability to merge and utilize multiple data elements 10 . industry-wide data). and The unavailability of identified data elements is not a to determine if significant data deficiencies exist. and Analysis ð16Þ Compliance records Design/engineering reports A plan for collecting. reviewing. and evaluation data obtained Inspection records from the integrity management program and data devel- oped for the performance metrics covered in section 9. as corrosion or stress corrosion cracking (SCC) may mentation. A survey of all potential locations that could house these Resident and time-independent threats do not have records may be required to document what is available implied time dependence. additional inspection actions or field data collec- additional inspections and field data collection efforts.g. Significant insight can also be analyzed in their context to realize the full value of integ- obtained from subject matter experts and those involved rity management and risk assessment. Records shall be maintained throughout the process that identify where Initially. Pipeline alignment drawings These may include jurisdictional agency reports and data- Original construction inspector notes/records bases that include information such as soil data. data. Every is implemented over years of operation. Test reports/records Incident reports 4. so earlier data are applicable. Research Facility drawings/maps organizations can provide background on many pipe- As-built drawings line-related issues useful for application in an integrity Material certifications management program. tion efforts may be required.3-1 Typical Data Sources for Pipeline Integrity valuable data source. assessments. O&M procedures additional data will become available. As the integrity Industry standards/specifications management program is developed and implemented. and its form (including the units or reference system). Safety-related condition reports The data sources listed in Table 4. examination.3 Data Sources tions used in place of specific data elements should be The data needed for integrity management programs avoided. This data are then integrated into the initial Data resolution and units shall also be determined. The volume and types of data will expand as the plan Consistency in units is essential for integration. This is often referred to as metadata or information tional data required for general pipeline and facility risk about the data. These may reflect additional needs Program in personnel training or qualifications. and analyzing the data shall be created and in place from the conception of the Technical evaluations data collection effort. effort should be made to utilize all of the actual data for the pipeline or facility. the integrity management program was developed. so the potential impact on the variability high risk. Process and instrumentation drawings (P&ID) Valuable data for integrity management program imple- mentation can also be obtained from external sources. perform system-wide integrity assessments and any addi. the documentation containing the required threat. Data pertaining to time-dependent threats such data elements is located in design and construction docu. and current operational and maintenance not be relevant if it was collected many years before records. This will include Emergency response plans inspection. This may require the data.8S-2016 Table 4. action to obtain the data can be planned management program. Existing management information system (MIS) or geographic information system (GIS) databases and the 4. can be obtained from within the operating company Another data collection consideration is whether the and from external sources (e. age of the data invalidates its applicability to the Typically. Depending on the importance of and initiated relative to its importance. Review. If defi. demo- Pipeline aerial photography graphics. to the pipeline system. Graphical Risk = (Pi × Ci) for threat categories 1 to 9 integration can be accomplished by loading risk. It can also lead to an improved 5. Depending on the data resolution used. (2) An operator suspects that a possible corrosion problem exists on a large-diameter pipeline located in a populated area. Risk assessments are required for both the first data integration steps includes development of a prescriptive-based and performance-based integrity common reference system (and consistent measurement management programs. factors: the failure likelihood (or probability) that some Data integration can also be accomplished manually or adverse event will occur and the resulting consequences of graphically. More specific where data integration software is also available that facilitates 1 to 9 = failure threat category (see para. risk assessments to directly combine with over-the-line surveys such as serve the following purposes: close interval survey (CIS) that are referenced to engi- (a) to organize data and information to help operators neering station locations.2 Definition without the benefit of inspection data and may only include the pipe attribute and construction data elements The operator shall follow section 5 in its entirety to shown in Table 4. The benefits of data integration C = failure consequence can be illustrated by the following hypothetical examples: EXAMPLES: P = failure likelihood (1) In reviewing ILI data. Risk assessments shall be conducted for pipelines and For integrity management program applications. prevention. (b) assessment of the benefits derived from mitigating action 11 . as shown in section 3. As other information such as conduct a performance-based integrity management inspection data becomes available. Risk consequences typically Each of these facts taken individually provides some indica.1-1. One method of describing risk is superimposing of scaled potential impact area circles Risk i = Pi × Ci for a single threat (see section 3) on pipeline aerial photography to deter. Total segment risk cally overlaying them to establish the location of a specific = (P1 × C1) + (P2 × C 2) + … + (P9 × C 9) threat. The CIS results did not indicate a potential integ- integrity assessments and mitigating action rity issue.2. A prescriptive-based integrity management tion step can be performed to confirm the previous infer. prioritize and plan activities Table 4. but as a group the result the event on individuals. An example of manual integration is the that event. Such tified in this section and in Nonmandatory Appendix A.3 Risk Assessment Objectives coverage in the area. units) that will allow data elements from various sources For prescriptive-based programs. this can be accomplished 5. but data integration prevented possibly incorrect conclusions. business.1 Introduction analysis of overall risk. However. risk assessments are to be combined and accurately associated with common primarily utilized to prioritize integrity management plan pipeline locations. 9 mine the extent of the potential impact area. ASME B31. inside of the pipeline (wheel count). property. program. risk assess- (DCVG) coating condition inspection is performed and ment has the following objectives: reveals that the welds were tape-coated and are in poor (a) prioritization of pipelines/segments for scheduling condition. which can be difficult For performance-based programs.1-1 describes data elements that can be eval- (b) to determine which inspection. this could be applied to local areas or larger segments. Initially. in-line inspection (ILI) activities. For instance. i=1 related data elements into an MIS/GIS system and graphi. data integration is also very effective for assessing the Risk is typically described as the product of two primary need for and type of mitigation measures to be used. one of related facilities. and/or uated in a structured manner to determine if a particular mitigation activities will be performed and when threat is applicable to the area of concern or the segment being considered.2. consider components such as the potential impact of tion of possible mechanical damage. an operator suspects mechanical damage in the top quadrant of a pipeline in a cultivated The risk analysis method used shall address all nine field. 2. It is also known that the farmer has been plowing threat categories or each of the individual 21 threats in this area and that the depth of cover may be reduced.2) use in combined analyses. They help to organize data and information to data may reference the distance traveled along the make decisions. onment. A direct current voltage gradient For application to pipelines and facilities. a CIS indicates good cathodic protection 5.8S-2016 obtained from several sources to provide an improved 5 RISK ASSESSMENT confidence that a specific threat may or may not apply to a pipeline segment. and the envir- is more definitive. an additional integra. program shall be conducted using the requirements iden- ence concerning the validity of the presumed threat. This type of assess- tely relied upon to establish risk estimates or to address or ment builds on pipeline-specific experience and more mitigate known risks. and low likelihood and conse- likelihood that such events may occur. weigh the major threats and consequences relevant to Such experience-based reviews should validate risk past pipeline operations. These approaches are consid- assessment output with other relevant factors not ered relative risk models.5 Risk Assessment Approaches measures for the identified threats (d) assessment of the integrity impact from modified (a) In order to organize integrity assessments for pipe- inspection intervals line segments of concern. can be used to making. a variety of inputs. and calculate the relative risk. quence values. ASME B31. This risk assessment approach creates models that generate a description of an event or series of events leading to a level of risk. They provide a risk ranking for the integrity mated data. that provide an improved under. The relative risk reporting. rithms weighing the major threats and consequences. and includes both the likelihood and consequences of such events. (2) Relative Assessment Models. The following paragraphs describe risk assessment methods for the four listed approaches: As an integral part of any pipeline integrity manage. and the results obtained and incorporate additional processes as required (see shall be documented in the integrity management section 11). engineering. the impact of assumptions. Multiplying the relative likelihood and conse- results are used to identify locations for integrity assess. sophistication. or compared with results generated from the same the potential risk variability caused by missing or esti. medium. and includes the development of risk used in conjunction with knowledgeable. program. (1) Subject Matter Experts (SMEs). relative assessments. risk assessment approaches are subject matter experts. Conversely. This method usually includes construction 12 . the process also avoids focusing on less These approaches are listed in a hierarchy of increasing likely catastrophic events while overlooking more complexity. Examining both relative risk for the segment and a relative priority for primary risk factors (likelihood and consequences) its assessment. avoids focusing solely on the most visible or frequently (b) An operator shall utilize one or more of the occurring problems while ignoring potential events following risk assessment approaches consistent with that could cause significantly greater damage. Risk assessment methods should be extensive data. and facility mapping processes assessment approach. These likely scenarios. combined with infor- shall provide risk estimates to facilitate decision. and An integral part of the risk assessment process is the provide sufficient data to meaningfully assess them. To ensure regular updates. pipeline segment. and data requirements. the operator shall require more specific pipeline system data than SME- incorporate the risk assessment process into existing field based risk assessment approaches. scenario assessments. using of failure for each threat and the resulting consequences. assumptions. This risk value is composed of a number inspection methodologies reflecting the overall likelihood of failure and a (f) more effective resource allocation number reflecting the consequences. mation obtained from technical literature. incorporation of additional data elements or changes to Relative assessment models are more complex and facility data.4 Developing a Risk Assessment Approach istic assessments. an effective risk assessment process operating company or consultants. and probabil- 5. quence numbers together provides the operator with a ments and resulting mitigative action. SMEs from the ment program. These models utilize algo- documented in the integrity management plan. Having such a quences) or can be more complex and involve a larger measure supports the integrity management process range to provide greater differentiation between pipeline by facilitating rational and consistent decisions. risk assessment provide a relative numeric value describing the likelihood methods can be very powerful analytic methods. The SMEs are utilized by the operator to analyze each standing of the nature and locations of risks along a pipe.8S-2016 (c) determination of the most effective mitigation 5. Risk assessment methods alone should not be comple. the model. a risk priority shall be estab- (e) assessment of the use of or need for alternative lished. Risk segments. experienced models addressing the known threats that have histori- personnel (subject matter experts and people familiar cally impacted pipeline operations. (3) Scenario-Based Models. Such relative or data- with the facilities) who regularly review the data based methods use models that identify and quantitatively input. assign relative likelihood and conse- line or within a facility. the objectives of the integrity management program. model. since the risk results are included in the process. The risk analysis Risk assessment provides a measure that evaluates both can be fairly simple with values ranging from 1 to 3 the potential impact of different incident types and the (to reflect high. When properly implemented. and results of the risk assessments. These processes and their results shall be management decision process. 5. risk values are determined. From these assessments utilizing any of the methods described in constructs. Another valuable approach is the use of trending. a risk assess- use minimal data sets. rather than using a comparative basis. and fault trees. These characteristics shall ment and/or mitigation options. The risk previously. A thorough understanding of the strengths adopting a more simple approach for the short term. management programs shall prioritize initial integrity 13 . Any risk assessment approach shall mechanism. Assessment Approach (2) They evaluate likelihood of failure and Considering the objectives summarized in para. Adequate personnel and time shall be rupture. sary before a long-term strategy is adopted. More An initial strategy for an operator with minimal experi- than one type of model may be used throughout an opera.5. tion.1-1. tial problem areas.6. Such risk analyses will require more compared to acceptable risk probabilities established data elements than required in Nonmandatory Appendix by the operator. but they do not less rigorous to apply and require more input from subject consider whether failure occurs as a leak or rupture. have the following common components: (1) They identify potential events or conditions that 5. Any risk assessment shall consider the frequency and consequences of past 5. ASME B31.1 Risk Analysis for Prescriptive Integrity events. the risk assessment method shall account for any ments. As additional data and experience are gained. Once the integrity of a segment is established. This approach is the most Risk analyses for performance-based integrity manage- complex and demanding with respect to data require. number of general characteristics exist that will contri- (3) They permit risk ranking and identification of bute to the overall effectiveness of a risk assessment specific threats that primarily influence or drive the risk. and objective analysis of risk. a worst-case assumption of rupture shall be allotted to permit implementation of the selected made.6 Risk Analysis (c) Operating/Mitigation History. for either prescriptive or performance-based integrity (4) They lead to the identification of integrity assess- management programs. ence using structured risk analysis methods may include tor’s system. The risk analyses developed system or a similar system. risk methods require a more rigid structure (and consid- Some risk assessment approaches consider the likeli- erably more input data). 5. To be effective. the more simplistic risk assessment tions to provide risk estimates that may result from approaches provided in para. They shall all follow an established struc- Ruptures have more potential for damage than leaks. Knowledge-based methods are hood and consequences of damage. matter experts. where the results of inspections. ment programs may also be used as a basis for establishing ments. as a knowledge-based or a screening relative risk model. threats previously not considered. ture and consider the nine categories of pipeline threats Consequently. when a risk assessment approach does and consequences. A and more detailed analyses. examinations. Some for risk reassessments. In addi- used to prioritize the pipeline segment integrity assess. this should include the subject pipeline Management Programs.7 Characteristics of an Effective Risk could threaten system integrity. Preferably. The results of these analyses It is the operator’s responsibility to apply the level of may also be used to evaluate alternative mitigation and integrity/risk analysis methods that meets the needs of prevention methods and their timing.6. They cannot be used to increase the ment method should be able to identify pipeline integrity reinspection intervals. the operator (c) All risk assessment approaches described above can transition to a more comprehensive method. The risk output is provided in a format that is inspection intervals. but other industry data can be for a prescriptive integrity management program are used where sufficient data is initially not available. a consequences. the corrective or risk mitigation action that has occurred reinspection interval is specified in Table 5. It shall be able to make When the operator follows the prescriptive reinspec. 5. the operator’s integrity management program. para.2 Risk Analysis for Performance-Based Integrity and evaluations are collected over time in order to predict Management Programs. contain a defined logic and be structured to provide a (6) They provide structure and continuous updating complete. such and limitations of each risk assessment method is neces. include the following: (5) They provide for a data feedback loop (a) Attributes. analyses for prescriptive integrity management programs (d) Predictive Capability. accurate.8S-2016 of event trees. Performance-based integrity future conditions. not consider whether a failure may occur as a leak or (b) Resources. 5. (4) Probabilistic Models. use of (or integrate) the data from various pipeline inspec- tion intervals.6.3. approach and future considerations. decision trees. 5.5 are considered threats that have not been previously recognized as poten- appropriate. yr Operating Pressure Above 30% But Not Operating Pressure Not Technique [Note (1)] Above 50% of SMYS Exceeding 50% of SMYS Exceeding 30% of SMYS Hydrostatic testing 5 TP to 1. (2) TP is test pressure. and changeable to accommodate new threats. the a process of continuous improvement.1-1 Integrity Assessment Intervals: Time-Dependent Threats. The indications are process-based and may not align with each other. In addition.65 times MAOP [Note (3)] MAOP [Note (3)] MAOP [Note (3)] 10 Pf above 1.39 times MAOP TP to 1. model validation. Effective feedback operator should determine and document the default is an essential process component in continuous risk values that will be used and why they were chosen.75 times MAOP [Note (3)] MAOP [Note (3)] 20 Not allowed Not allowed Pf above 3. 14 . method shall not be considered as a static tool but as rate risk result. Inaccurate data will produce a less accu.20 times MAOP [Note (3)] MAOP [Note (3)] MAOP [Note (3)] 15 Not allowed Pf above 2.65 times Pf above 2. (3) Pf is predicted failure pressure as determined from ASME B31G or equivalent. depending on repairs made and prevention activities instituted. the model shall be adaptable The operator should choose default values that conserva.39 times Pf above 1. Any risk assessment (see section 12). tively reflect the values of other similar segments on the (g) Documentation. Like the risk process values may be reduced. indications for inspection are classified and prioritized using NACE SP0204. Pipeline External Corrosion Direct Assessment Methodology. the External Corrosion DA indications may not be at the same location as the Internal Corrosion DA indications.00 times Pf above 2. itself.33 times MAOP [Note (3)] Direct assessment 5 All immediate indications All immediate indications All immediate indications plus one scheduled plus one scheduled plus one scheduled [Note (4)] [Note (4)] [Note (4)] 10 All immediate indications All immediate indications All immediate indications plus all scheduled plus more than half of scheduled plus one scheduled [Note (4)] [Note (4)] [Note (4)] 15 Not allowed All immediate indications All immediate indications plus all scheduled plus more than half of [Note (4)] scheduled [Note (4)] 20 Not allowed Not allowed All immediate indications plus all scheduled [Note (4)] NOTES: (1) Intervals are maximum and may be less.39 times MAOP TP to 1. (f) Feedback.00 times MAOP TP to 2.65 times MAOP TP to 2.25 times Pf above 1.20 times MAOP [Note (2)] [Note (2)] [Note (2)] 15 Not allowed TP to 2. Occurrence of a time-dependent failure requires immediate reassessment of the interval. or NACE SP0502.39 times Pf above 1. For missing or questionable data. The risk assessment process shall pipeline or in the operator’s system. For example. (4) For the direct assessment process.33 times MAOP [Note (2)] In-line inspection 5 Pf above 1. Stress Corrosion Cracking (SCC) Direct Assessment Methodology. One of the most important steps in an ment process shall be verified and checked for accuracy effective risk analysis is feedback. In addition. ASME B31. As the data are obtained.75 times MAOP [Note (2)] [Note (2)] 20 Not allowed Not allowed TP to 3. These conservative be thoroughly and completely documented to provide the values may elevate the risk of the pipeline and encourage background and technical justification for the methods action to obtain accurate data. NACE SP0206. Prescriptive Integrity Management Plan Criteria Operating Pressure Inspection Interval. Internal and External Corrosion. Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas (DG-ICDA). (e) Risk Confidence.65 times MAOP [Note (2)] [Note (2)] [Note (2)]] 10 TP to 1.25 times MAOP TP to 1.8S-2016 Table 5. Any data applied in a risk assess. the and procedures used and their impact on decisions uncertainties will be eliminated and the resultant risk based on the risk estimates. such a document should be periodically updated as modifications or risk process changes are incorporated.6. certain threats can be extremely aggressive and may significantly reduce the interval between inspections. An effective risk assessment process reflected in the re-evaluation and any risk comparisons shall incorporate sufficient resolution of pipeline segment are on an equal basis. to ensure that (1. A specified period component. not have the same level of influence on the risk estimate. Risk assessment and data collection may then be focused on the most likely threats without requiring excessive detail. This structure can provide esti. The results of this elements are not available. and other data. as well as confirm the reasonableness A description of various details and complexities asso. and others knowledgeable of threats reduction benefit from maintenance or remedial actions. such as areas of concern. Such lishing which particular threats or factors have the most a re-evaluation should include all pipelines or segments influence on the result. estab. This is called dynamic segmentation. When comprising these two segments now becomes four risk analyzing the results of the risk assessments. Application of any type of risk analysis methodology Therefore. but be limited to areas with a history of mated values. system-wide risk re-evaluation but shall not exceed the ence. This can require a reanalysis of the pipeline segments included be illustrated by assuming that two adjacent 1-mi-long in the integrity management program. as a minimum. including both failure probability and conse. Segments experience. An alternative could be to use related data problems or where failure could result in the most elements in order to make an inferential threat estimate. the pipeline length Data collection issues are discussed in section 4. 5. segment lengths can range from units of feet the operator’s overall integrity management program. size to analyze data as they exist along the pipeline. It should also provide for least annually but may be more frequent. The risk assessment process shall included in the risk analysis process to ensure that the be structured. most recent inspection results and information are (k) Segmentation. depending on the pipeline Adjustments and improvements to the risk assessment attributes.8S-2016 (h) “What If” Determinations. a structured set of weighting factors shall be shall be considered as an element of continuous included that indicate the value of each risk assessment process and not a one-time event. The rank the risk results to support the integrity management frequency of the system-wide re-evaluation must be at program’s decision process. Such factors can be based on operational experi. engineering. or industry required maximum interval in Table 5. accurate results consistent with the objectives of purposes.6. For risk assessment relevant.1-1.6-km-long) segments have been identified. A group “what if” calculations. A impact of missing data and taking into account the poten- screening risk assessment may not include the entire pipe. Any risk assessment process shall or that are to be monitored must be assessed within time provide. 5. a pipe replacement is completed from the midpoint of one segment to some point within the other. containing indications that are scheduled for examination (j) Structure. In order 5. modifications of the proposed screening can be implemented within a short time model may be required after carefully reviewing the frame and focus given to the most important areas. These adjustments shall action that changes the risk in a particular length. of the results. ciated with different risk assessment processes has been Determining the risk of potential threats will result in provided in para. that may exist is assembled to focus on the potential (i) Weighting Factors. ASME B31. and verifiable. All threats and consequences threats and risk reduction measures that would be effec- contained in a relative risk assessment process should tive in the integrity management program.5. Operators that have not previously specification of the minimum data set required for imple- initiated a formal risk assessment process may find an mentation of the selected risk process.9 Data Collection for Risk Assessment to account for the risk reduction. based on the several types of data evaluation and comparisons. the opinions of subject matter experts. An effective risk model approach can include subject matter experts or simple should contain the structure necessary to perform relative risk models as described in para. Iteration of the risk assessment process may be required to improve the 5. Such The processes and risk assessment methods used shall analysis will facilitate location of local high-risk areas that be periodically reviewed to ensure they continue to yield may need immediate attention. of subject matter experts representing pipeline opera- mates of the effects of changes over time and the risk tions. A screening risk assessment suitable for this 15 . to miles (meters to kilometers). may find that additional data are required.5. defined by the operator shall be established for a quences. severe consequences.8 Risk Estimates Using Assessment Methods clarity of the results. methods will be necessary as more complete and accurate Another requirement of the model involves the ability to information concerning pipeline system attributes and update the risk model to account for mitigation or other history becomes available. documented. its environment. If significant data initial screening to be beneficial. tial effect of uncertainties created by using required esti- line system. Suppose equivalent assessments or comparisons are made. the operator analysis segments. frequency and importance of data modifications. the ability to compare and intervals that will maintain system integrity. tor’s and industry’s experience. as a result of maintenance or other activities. Timely may not prevent corrosion in areas of damaged coating resolution of the single highest threat segment may be must be considered. CP data. and sche. Some threats. risk results such an event may not have occurred in any given pipeline could be evaluated simply on a “high–medium–low” basis segment. more appropriate than resolution of the highest aggregate When considering threat exclusion. the failure probability and conse.12 Validation operating conditions. When segments being compared considered time-dependent should require very strong have similar risk values. ogies that can provide a more effective or comprehensive (d) The threat is not supported by like/similar risk mitigation approach. such as quences should be considered separately. a cautionary note threat segment. More specifically. Depending on the importance of factors can be applied to help select. Section 6 discusses integrity assessment and eration are specified in Nonmandatory Appendix A. for the external corrosion threat. 16 . It is also data or experience. but rank much lower for the aggregate tion shielding in rocky terrain where impressed current of threats compared to all other pipeline segments. multiple results that are usable and are consistent with the opera- data elements such as soil type/moisture level. the risk segment should be considered in determining the minimum data required and the criteria for risk assess- most effective integrity assessment and/or mitigation ment in order to eliminate a threat from further consid- option.10 Prioritization for Prescriptive-Based and be used. cathodic protec- for a single threat. For instance. pipelines operating at segment shall be assigned a higher priority when deciding low stress levels do not develop SCC-related failures. the operator should assess risk factors justification for exclusion of a threat from the integrity that cause higher risk levels for particular segments. Similar sorting can also be achieved allows for the fact that some pipeline systems or segments by separately considering decreasing consequences or are not vulnerable to some threats. prudent to consider the possibility of using new technol- (c) The threat is not implied by related data elements. These management program. throughput requirements can also influence prioritization. may not be immediately the highest consequence segment being given a higher evident and can become a significant threat even after priority. analyses. applies to threats classified as time-dependent. (a) There is no history of a threat impacting the parti- It is necessary to consider a variety of options or combi- cular segment or pipeline system. be done to ensure that the methods used have produced As an example. the fact that the threat is or as a numerical value. CP current demand. For a most significant risks. Also. A recalculation of each segment’s risk that use more comprehensive analysis methods should after integrity assessment and/or mitigation actions is consider the following in order to exclude a threat in a required to ensure that the segment’s integrity can be segment: maintained to the next inspection interval. (e) The threat is not applicable to system or segment 5. justification for its exclusion. The risk drivers for each high- prescriptive integrity management program. 5. The highest risk level industry research and experience. system. prioritize. Paragraph (e) order of overall risk. or facility. a threat cannot be testing. section 7 discusses options that are commonly used to Performance-based integrity management programs mitigate threats. This shall presence when other data elements may not be available. the data. The unavailability of identified data elements is not a tion actions. For excluded without consideration given to the likelihood of example. In addition. A reassessment of and CIS data. Factors including line availability and system extended operating periods. or if one is unavailable a subset may be sufficient Performance-Based Integrity Management to determine whether the threat shall be considered for Programs that segment.8S-2016 5. a pipeline segment may rank extremely high interaction by other threats. ASME B31. nations of integrity assessments and mitigation actions (b) The threat is not supported by applicable industry that directly address the primary threat(s). in-line inspection. where to implement integrity assessment and/or mitiga. or direct assessment. based on failure probability levels. Paragraph (d) considers the evaluation of pipeline segments with known and similar conditions that A first step in prioritization usually involves sorting can be used as a basis for evaluating the existence of each particular segment’s risk results in decreasing threats on pipelines with missing data. and coating condition can all modification to the risk assessment process shall be required if. This may lead to internal corrosion and SCC. For instance. para. additional inspection actions or field data collec- dule locations for inspection actions such as hydrostatic tion efforts may be required. (c) considers the application of Validation of risk analysis results is one of the most related data elements to provide an indication of a threat’s important steps in any assessment process.11 Integrity Assessment and Mitigation The integrity plan shall also provide for the elimination The process begins with examining the nature of the of any specific threat from the risk assessment. Although For initial efforts and screening purposes. A risk validation process shall be ment methods discussed in section 6 only provide indica- identified and documented in the integrity management tions of defects. In-Line Inspection tion. API Std 1163. High inspection speeds degrade sizing accuracy.2. or pipe joint. The operator locations that are indicated as either high risk or low risk may choose to go directly to examination and evaluation to determine if the methods are correctly characterizing for the entire length of the pipeline segment being the risks. Sizing accuracy degrades where pits are component. It is not generally reliable for axially aligned defects. in lieu of conducting inspections. Conversely. It is not reliable for detection or dependent threats can typically be addressed by utilizing sizing of most defects other than metal loss and not reli- any one of the integrity assessment methods discussed in able for detection or sizing of axially aligned metal-loss this section. find indications of threats other than those that the assess. 6. 6. sizing capability where return signals are lost. Random threats typically cannot present or defect geometry becomes complex. the third. can typically be (b) Magnetic Flux Leakage. Examination of the dent may be an appropriate It is sensitive to debris and deposits on the inside pipe wall. the pipe. such as defects that defects. and when a defect is shielded by a lamination. Standard Resolution Tool. The integrity and how well the tool matches the requirements set by the assessment methods that can be used are in-line inspec. an in-line can occur in defects with rapidly changing profiles. performing prior to the maintenance activity can indicate if mean. The integrity assessment pipeline in-line inspection. ingful results are being generated. istics. as prevention. For another location’s information regarding the condition example. scabs and slivers. 17 .1 Metal Loss Tools for the Internal and External required to address all the threats in a pipeline Corrosion Threat. Resident threats. which mentation of prevention activities. for sizing. This addressed by pressure testing. and time-independent. to third-party activity. such (a) Magnetic Flux Leakage. inspection objectives. It Section 2 provides a listing of threats by three groups: is sensitive to certain metallurgical defects such as time-dependent. variety of nondestructive examination (NDE) techniques Risk result validations can be successfully performed by is required. For example. Systems Qualification. examinations. in-line inspection is not necessary. Their effectiveness is limited by the tech- assessment methods may not be the appropriate action for nology the tool employs. This usually ment was intended to address. such as metal loss or deformation. pressure testing. action in order to determine if the pipe was damaged due High speeds degrade axial sizing resolution. Validation can be achieved by considering assessed. (c) Ultrasonic Compression Wave Tool. may provide better integrity management This is better suited for detection of metal loss than results. the operator to take for certain threats. defect shapes. resident. however. provides additional guidance on odologies provided in para. Since the pipe is accessible for this technique and special risk assessment performed using known data external corrosion can be readily evaluated. Sizing accuracy is limited by sensor size.8S-2016 areas are found that are inaccurately represented by the It is important to note that some of the integrity assess- risk assessment process. Based on the priorities determined by risk assessment. The following paragraphs method is based on the threats to which the segment is discuss the use of ILI tools for certain threats. Sizing accuracy is best for geometrically simple nation and evaluation of the specific piece of equipment. There is be addressed through use of any of the integrity assess. tools. ment methods discussed in this section but are subject to but ability varies with defect geometries and character- the prevention measures discussed in section 7. susceptible. For these threats. Other actions. the following tools segment. while construction and provides better sizing accuracy than standard resolution equipment threats can typically be addressed by exami. requires a liquid couplant. It provides no detection or party damage threat is usually best addressed by imple.1 General cations. and evaluations at results in order to characterize the defect. ASME B31. A threat. inspection using any of the integrity can be used. direct assessment. some ability to detect defects other than metal loss. followed by evaluation of these inspection conducting inspections. High-Resolution Tool. the operator may wish to conduct visual exam- of a pipeline segment and the condition determined ination of aboveground piping for the external corrosion during maintenance action or prior remedial efforts. Examination using visual inspection and a program. or other meth. occurred during manufacturing. in a pipeline. inspection tool may indicate a dent in the top half of some bends. Time. More than one method and/or tool may be 6.2 Pipeline In-Line Inspection 6 INTEGRITY ASSESSMENT In-line inspection (ILI) is an integrity assessment method used to locate and preliminarily characterize indi- ð16Þ 6. Use of a particular integrity assessment method may High inspection speeds degrade sizing accuracy. The effectiveness of the ILI tool used depends on the the operator shall conduct integrity assessments using the condition of the specific pipeline section to be inspected appropriate integrity assessment methods.5. dents caused by the pipe settling onto rocks. unbarred pipe cross section. Dents and tant issues that should be considered are as follows: areas of metal loss are the only aspect of these threats (1) Pipeline Questionnaire. There of the defect. grade. This is more sensitive to axially aligned metal-loss defects than standard and 6. In-line inspection is typically high-resolution MFL tools. It is less sensitive than stan. third-party damage. not including SCC. such as steel and sizing. Sizing accuracy is the pipe may challenge the lower limits of reliable detec- limited by the number of sensors and the complexity tion of both the standard and high-resolution tools. High speeds can degrade sizing accuracy. each caliper arm. It generally provides less sizing accuracy Inspection Tools than high-resolution MFL tools for most defect geome- tries. High inspection speeds can (b) Typically. Sizing accuracy enables priori- limited by the number of sensors and the complexity tization and is a key to a successful integrity management of the crack colony. Some of the more impor- Damage and Mechanical Damage Threat. diameter. (e) Transverse Flux Tool. bends. Total time of inspection is dictated by sharpness or estimate strains associated with the defor- inspection speed but is limited by the total capacity of mation using the standard caliper tool output. type of welds. pipeline operators provide answers to a degrade sizing accuracy. This is able to detect some have to be adequate for the specific operator’s defect axially aligned cracks. Third-party damage that has 18 . complexity. A higher resolution is provided by (4) Type of Fluid. it is possible to identify be compromised.2. Sizing accuracy is (3) Sizing Accuracy. This type of tool can be used to discern of the gas will influence the speed of the ILI tool inspection. which can be useful for identifying bending or settlement of the pipeline. of the pipe cross section. presence of inclusions and impurities in the pipe wall. It may also be sensitive to not the appropriate inspection method to use for all other other axially aligned defects. wall thickness. the following tools can be fied for the ILI tool should be smaller than the size of the used. couplings. (2) Classification. valves.2. The cleanliness can significantly adequate for identifying and locating severe deformation affect data collection. Some also indicate slope or change in should be considered. slope. the questionnaire identifies detecting damage to the line involving deformation of the any restrictions. and wrinkles or buckles caused by (2) Launchers and Receivers. Flow rate circumference. length. This type of tool is (3) Pipe Cleanliness. negotiate. MFL tools are not useful for sizing degrade sizing resolution. The type of phase — gas or liquid — standard caliper tools that record a channel of data for affects the possible choice of technologies. resolution can deformation. typically 10 or 12 spaced around the (5) Flow Rate. Results of ILI (b) Transverse Flux Tool. These items should be compressive loading or uneven settlement of the pipeline. which can be caused by construction tees. and maneuverability. (5) Requirements for Defect Assessment. High lution tools provide the most detailed information about temperatures can affect tool operation quality and the deformation. but is not consid. Sizing accuracy is degraded by the presence has been limited success identifying third-party damage of inclusions and impurities in the pipe wall. reviewed for suitability. assessment program. threats listed in section 2. questionnaire provided by the ILI vendor that should list all the significant parameters and characteristics of the 6. For this threat. With some effort. and chill rings the ILI tool may need to damage. and Temperature. since ILI tools vary in overall The lowest-resolution geometry tool is the gaging pig or length. Location accuracy enables High inspection speeds degrade sizing accuracy and location of anomalies by excavation. ASME B31. Also. deformation severity and overall shape aspects of the If speeds are outside of the normal ranges.5 Special Considerations for the Use of In-Line aligned defects. Sizing accuracy is degraded by the plan. ered accurate for sizing. known ovalities. geometry.4 All Other Threats.2 Crack Detection Tools for the Stress Corrosion (1) Detection Sensitivity. High-reso- batteries and data storage available on the tool. This requires a liquid rerounded under the influence of internal pressure in couplant or a wheel-coupled system. dard and high-resolution MFL tools to circumferentially 6. Pressure. (4) Location Accuracy. single-channel caliper-type tool. High speeds using MFL tools. The questionnaire for which ILI tools can be effectively used for detection provides a review of pipe characteristics. resolution. Deformation or geometry tools are most often used for elevation profiles.8S-2016 (d) Ultrasonic Shear Wave Tool. Classification allows differentia- (a) Ultrasonic Shear Wave Tool.3 Metal Loss and Caliper Tools for Third-Party pipeline section to be inspected. Minimum defect size speci- Cracking Threat.2.2. This requires a liquid tion among types of anomalies. (a) The following shall also be considered when selecting the appropriate tool: 6. tool employs. couplant or a wheel-coupled system. deformations. Their effectiveness is limited by the technology the defect sought to be detected. etc. 3. References for determining if a specific selection and implementation of the ILI inspections. Any section of pipe Pressure testing has long been an industry-accepted that fails a pressure test shall be examined in order to method for validating the integrity of pipelines. ð16Þ 6. to the effective date of this Code).e. ASME B31.3 All Other Threats. not the appropriate integrity assessment method to use for all other threats listed in section 2.8 contains details on conducting pressure and the segment reassessed for risk.0 (e. Petroleum Gas. Pressure testing is typically Mitigation is discussed in section 7. the operator must evaluate the defect in order to determine the appropriate mitigation actions.8. or Carbon Dioxide.25 times the MAOP. inspections Pressure testing shall be in accordance with ASME using NDE equipment. If the failure was due to leak test.6 Examination and Evaluation. (4) ability of the tool to inspect the full length and full circumference of the section 6.2. may be a consideration in higher velocity lines.3. in B31. Testing of Steel Pipelines for the Transportation of and evaluation. lap- with the capabilities and performance of the tool. The operator shall outline welded electric-resistance-welded (ERW) pipe or flash- the process used in the integrity management plan for the welded pipe. Generally. pressure testing must be Examination consists of a variety of direct inspection performed to address the seam issue. Reduction of gas Gas. When raising the MAOP of a steel pipeline or when tion is required in order to determine the time frame for raising the operating pressure above the historical oper- examination and evaluation. characterization of the defect. Seam issues have been known to exist factors known about the pipeline and expected anomalies for pipe with a joint factor of less than 1.3. Selection of this method shall be appropriate for another threat. Time-dependent threats are external corrosion. Once the defect is and in-service pipelines. and sizing the anomalies) threats. including visual inspection. representatives from the pipeline operator Pressure testing shall comply with the requirements of and the ILI service vendor should analyze the goal and ASME B31. prob. the ILI method by looking at the following: 6.. hammer-welded pipe. It also specifies allowable test mediums utilizing a structured process through which the operator and under what conditions the various test mediums is able to integrate knowledge of the physical character- can be used. Hazardous Liquids.8 order to characterize the defect in confirmatory excava- defines how to conduct tests for both post-construction tions where anomalies are detected.) and History of Line Pipe inspection only provide indications of defects. appropriate for use when addressing time-dependent ability of detecting. techniques. in order to determine the integrity. stress corrosion cracking.g.. Recommended Practice for the Pressure segment with the results of inspection. characterized. classifying. and taking measurements. The time frame is discussed ating pressure (i. tests for both post-construction testing and for subse- quent testing after a pipeline has been in service for a 6. 19 . and other (3) success rate/failed surveys environmentally assisted corrosion mechanisms. This integ- evaluate that the failure was due to the threat that the rity assessment method can be both a strength test and a test was intended to address.3 Pressure Testing 6.. mine when to conduct inspections utilizing pressure (c) The operator shall assess the general reliability of testing. 6.8S-2016 (6) Product Bypass/Supplement. This will define whether air or water objective of the inspection. grated with other information relative to the other threat ASME B31. examination. Results of in-line Foundation. and match significant shall be used. pipe is susceptible to seam issues are Integrity Characteristics of Vintage Pipelines (The INGAA 6.3. The Code specifies the test pressure to be attained and the test duration in order to address Direct assessment is an integrity assessment method certain threats. and butt-welded tool will depend on the specifics of the pipeline section and pipe) or if the pipeline is composed of low-frequency- the goal set for the inspection. the test failure information must be inte- the threats being assessed.g. Additional guidance can be found in API istics and operating history of a pipeline system or RP 1110.4 Examination and Evaluation. Screening of this informa.8.4 Direct Assessment period of time. The operator should consider the results of the risk Conversely. (5) ability to indicate the presence of multiple cause Pressure testing is appropriate for use when addressing anomalies the pipe seam aspect of the manufacturing threat.1 Time-Dependent Threats. with some Manufacturing in North America (ASME research report). highest pressure recorded in 5 yr prior in section 7. Highly Volatile flow and speed reduction capability on the ILI tool Liquids. to at least 1. (2) history of the ILI method/tool internal corrosion. Inc. the availability of supplementary gas assessment and the expected types of anomalies to deter- where the flow rate is too low shall be considered.2 Manufacturing and Related Defect Threats. ASME B31. Pressure testing is (1) confidence level of the ILI method (e. Choice of welded pipe. 6. process requires direct examinations and evaluations. If the locations (c) examinations and evaluations most susceptible to corrosion are determined not to (d) post-assessment contain defects.4. Direct examinations and evaluations confirm the ability lytes). Examinations are performed at locations where electro- The ECDA process requires direct examinations and lyte accumulation is predicted. rate to set the reinspection interval. Nonintrusive a new input or output changes the potential for electrolyte (typically aboveground or indirect) inspections are entry or flow characteristics. ICDA applies between any feed points until the physical characteristics of a pipeline. validation. requiring certain data (see current and historical field inspections and tests.1 External Corrosion Direct Assessment (ECDA) Internal corrosion is most likely to occur where water for the External Corrosion Threat. (SCCDA) for the Stress Corrosion Cracking Threat. internal corrosion. ness at those locations. Predicting the locations of water accu- direct assessment can be used for determining integrity mulation (if upsets occur) serves as a method for prior- for the external corrosion threat on pipeline segments. indirect) observations and inspections are used to esti- rity for the internal corrosion threat on pipeline segments mate the absence of corrosion protection. with section 4). and confirm the validity of the other locations further downstream are less likely to accu. mulate electrolytes and therefore can be considered free The focus of the SCCDA approach described in this Code from corrosion. or mechanical damage may be detected during the SCCDA process. Pipeline guidance and procedures for conducting SCCDA. provide information about the remaining spection interval. Post-assessment is required to determine a corrosion internal corrosion monitoring method(s) [e. (SCC) Direct Assessment Methodology. then their current applicability.4.3 Stress Corrosion Cracking Direct Assessment ternal corrosion threats.g. reassess the performance metrics and length of pipe. Process for the Internal Corrosion Threat.2 Internal Corrosion Direct Assessment (ICDA) with the physical characteristics of a pipeline. There may also be some applications The ECDA process therefore has the following four where the most effective approach is to conduct in-line components: inspection for a portion of pipe. probe. For most pipelines it is evaluations. nized that evidence of other threats such as external corro- sion. coupon. the integrity of a large portion of the pipe- The focus of the ECDA approach described in this Code is line has been ensured. and/or sion direct assessment can be used for determining integ. It is recognized that evidence of other threats 3. and flow behavior in the pipe. Internal corro. It is recog- require examination. term upsets of wet gas or free water (or other electro. Post-assessment is required to set the rein- first accumulate. These downstream locations would not is to identify locations where SCC may exist. the operator is advised to conduct examinations for nonex.4. itizing local examinations. implementing ECDA and when the pipe is exposed. The SCCDA that normally carry dry gas but may suffer from short. While implementing 20 . The prescriptive ECDA process requires the use of at Stress corrosion cracking direct assessment can be least two inspection methods. ASME B31. Note that NACE RP0204. which force an electrolyte such as water to the pipeline. If these low points have not corroded. accumulates requires knowledge about the multiphase The ECDA process integrates facilities data. reassess the perfor.8S-2016 6. see NACE SP0502. and post-assessment SCC on pipeline segments by evaluating the SCC threat. aboveground. see section B- have formed. verification checks by used to determine the likely presence or absence of examination and evaluations. current and historical field inspections. External corrosion first accumulates. Examinations of low points or at inclines along of the indirect inspections to locate evidence of SCC on a pipeline. to internal corrosion. and tests 6. and ensure to extend the reinspection interval and benefit from the assumptions made in the previous steps remain real-time monitoring in the locations most susceptible correct. Internal Corrosion Direct such as mechanical damage and stress corrosion cracking Assessment Methodology for Pipelines Carrying (SCC) may be detected during the ECDA process. SCCDA pre-assessment process integrates facilities data. ultrasonic (UT) sensor] may allow an operator mance metrics and their current applicability. The External Direct Assessment Methodology. Once a site has been exposed. used to estimate the success of the corrosion protection. While Normally Dry Natural Gas (DG-ICDA). and use the results to (a) pre-assessment assess the downstream internal corrosion where in- (b) inspections line inspection cannot be conducted. provides detailed rity assessment method. For more information on the ICDA to identify locations where external corrosion defects may process as an integrity assessment method. Nonintrusive (typically terrain. and NACE SP0206. Stress Corrosion Cracking For more information on the ECDA process as an integ.. assumptions made in the previous steps remain correct. Predicting where water first The operator may use NACE SP0502 to conduct ECDA. Direct examinations and evaluations expected that examination by radiography or ultrasonic confirm the ability of the indirect inspections to locate NDE will be required to measure the remaining wall thick- active and past corrosion locations on the pipeline. either examining them or reducing the operating pressure Inspection intervals are based on the characterization to provide an additional margin of safety. responses can be divided into the following three groups: 6. and when the pipe is exposed. Corrosion. Indications requiring immediate response are those that might be expected to cause immediate 7 RESPONSES TO INTEGRITY ASSESSMENTS AND or near-term leaks or ruptures based on their known MITIGATION (REPAIR AND PREVENTION) or perceived effects on the strength of the pipeline. and be approved response indications. and mitigative actions shall be 7.1 General predicted failure pressure level less than 1. The required response schedule not the appropriate integrity assessment method to use interval begins at the time the condition is discovered. the operator shall temporarily reduce the defect growth. see especially NACE SP0204. and establishment of the inspection interval.10 21 . and the useful life tion.1 times the MAOP as determined by ASME B31G or equivalent. techniques other than those published by or monitored responses.2 Responses to Pipeline In-Line Inspections advised to conduct examinations for non-SCC threats. the operator shall follow the performance tion is conducted and results obtained within the specified requirements of this Code and shall be diligent in time frame.5 Other Integrity Assessment Methodologies (a) immediate: indication shows that defect is at failure point Other proven integrity assessment methods may exist (b) scheduled: indication shows defect is significant but for use in managing the integrity of pipelines.2. it is acceptable for an operator (c) monitored: indication shows defect will not fail to use these inspections as an alternative to those before next inspection listed above.2.8S-2016 SCCDA. evaluation. rather than examine and evaluate. For the not at failure point purpose of this Code. 7.4 All Other Threats. If the examination cannot be completed within the of the data. For detailed information on the SCCDA process as an integ. The taken to reduce or eliminate a threat to the integrity of a operator shall take action on these indications by pipeline. preventive actions that can be resistance welding or by electric flash welding. ASME B31. within a period of defect indications. the level of mitigation achieved. for all other threats listed in section 2. Direct assessment is typically inspection indications. This section covers the schedule of responses to the Also in this group would be any metal-loss indication indications obtained by inspection (see section 6). to the scheduled response. affecting a detected longitudinal seam. prioritized schedule established by considering the results of a risk assessment and the severity of in-line 6. For scheduled programs.1-1 shall be used to determine the reduced operating selected and scheduled to achieve risk reduction where pressure based on the selected response time. This would include any corroded areas that have a 7.4. if that seam repair activities that can be affected to remedy or elim. Upon receipt of the characterization of indications For prescriptive-based integrity management discovered during a successful in-line inspection. an operator may reinspect consensus standards organizations may be utilized. or removal shall be promptly remediated by repair or The integrity management program shall provide removal unless the operating pressure is lowered to miti- analyses of existing and newly implemented mitigation gate the need to repair or remove the defect. The plan shall include the methods and timing of the For performance-based integrity management response (examination and evaluation). When establishing schedules. ination and evaluation. operating pressure until the indication is examined. with consideration given to expected required 5 days. organization. An operator shall complete the response according to a rity assessment method. not to exceed 5 days following determination of the condi- the prevention methods employed. Other indications shall be reviewed and published by an industry consensus standards within 6 months and a response plan shall be developed. actions to evaluate their effectiveness and justify their Indications in the scheduled group are suitable for use in the future.1-1 includes a summary of some prevention and provided they do not grow to critical dimensions prior repair methods and their applicability to each threat. the operator is 7. the programs. Figure Examination. was formed by direct current or low-frequency electric inate an unsafe condition.1 Metal Loss Tools for Internal and External ance was achieved. the alternative integrity assessment shall be operator shall promptly review the results for immediate an industry-recognized methodology. After exam- appropriate in each segment within the integrity manage. Indications characterized with a predicted failure pressure greater than 1. any defect found to require repair ment program. provided the reinspec- however. confirming and documenting the validity of this approach to confirm that a higher level of integrity or integrity assur. continued operation without immediate response Table 7. Table 7. Detection.8S-2016 O&M procedures X X X X X X X X X X X … X … … … … X X X X Operator training … … … … … … … … … X … … … … … … … … … … … 22 Increase marker frequency X X … … … … … … … … … … … … … … … … … … … Strain monitoring … … … … … … … … … … … … X … … … … … … X … External protection X X X … … … … … … … … … … … … … … … … X … Maintain ROW X X … … … … … … … … … … … … … … … … … X … Increased wall thickness X X X X X … … … … … … … … … … … … … … X … Warning tape mesh X X … … … … … … … … … … … … … … … … … … … CP monitor/maintain … … … X … … … … … … … … … … … … … … … … X Internal cleaning … … … … X … … … … … … … … … … … … … … … … Leakage control measures … X X X X X X X X … … … … … … … … X … … … Pig-GPS/strain measurement … … … … … … … … … … X … X … … … … … … X … Reduce external stress … … … … … … X … … … … … … … … … … X X X X Install heat tracing … … … … … … … … … … X … … … … … … … … … … Line relocation X … X … … … … … … … X … X … … … … … … X … Rehabilitation … X … X X … … … … … … … … … … … … X X X X Coating repair … … … X … … … … … … … … … … … … … … … … X Increase cover depth X … X … … … … … … … … … … … … … … … X … … Operating temperature reduction … … … … … X … … X … … … … … … … … … … … X Reduce moisture … … … … X … … … … … … … … … … … … … … … … Biocide/inhibiting injection … … … … X … … … … … … … … … … … … … … … … Install thermal protection … … … … … … … … … … X … … … … … … … … … … .1-1 Acceptable Threat Prevention and Repair Methods Corrosion Incorrect Third-Party Damage Related Equipment Operation Weather Related Manufacture Construction O-Force Environment Prevention. Gask/ Strip/ Cont/ Seal/ Pipe Fab and Repair Methods TPD(IF) PDP Vand Ext Int Oring BP Rel Pack IO CW L HR/F Seam Pipe Gweld Weld Coup WB/B EM SCC Prevention/Detection Aerial patrol X X X … … … … … … … X X X … … … … X … X … Foot patrol X X X X … … … … … … X X X … … … … X … X … Visual/mechanical inspection … … … … … X X X X … X … … … … X … … … … … One-call system X X X … … … … … … … … … … … … … … … … … … Compliance audit … … … … … … … … … X … … … … … … … … … … … Design specifications … … … X X X X X X … … … … … … X … X X X X Materials specifications … … … … … X X X X … X … X X X … X … … … … Manufacturer inspection … X … … … … … X X … … … … X X … X … … … … Transportation inspection … X … … … … … … … … … … … X X … … … … … … Construction inspection … X … X … X X X X … … … … … X X X X X … X Preservice pressure test … X … … … … … … … … … … … X X X X X X … … Public education X … … … … … … … … … … … … … … … … … … … … ASME B31. Gask/ Strip/ Cont/ Seal/ Pipe Fab and Repair Methods TPD(IF) PDP Vand Ext Int Oring BP Rel Pack IO CW L HR/F Seam Pipe Gweld Weld Coup WB/B EM SCC Repairs Pressure reduction … X … X X X … … … … … … … X X X X X … … X Replacement X X X X X X X X X … X X X X X X X X X X X ECA.2 and Nonmandatory Appendix R. para. IPC2006-10299. It can only be used for damaged pipe where all the stress risers have been ground out and the missing wall is filled with uncompressible filler.. recoat … … … X X … … … … … … … … … … X … … … … … Grind repair/ECA … X X … … … … … … … … … … X X X X … … … X Direct deposition weld … C C C C … … … … … … … … C C C C … … … … Type B. para.8S-2016 Key X = acceptable 23 . Explanations of the abbreviations are as follows: Cont/Rel = control/relief equipment malfunction Coup = coupling failure CW = cold weather Direct deposition weld = a very specialized repair technique that requires detailed materials information and procedure validation to avoid possible cracking on live lines ECA = engineering critical assessment EM = earth movement Ext = external corrosion Fab Weld = defective fabrication weld including branch and T-joints Gask/Oring = gasket or O-ring Gweld = defective pipe girth weld (circumferential) HR/F = heavy rains or floods Int = internal corrosion IO = incorrect operations L = lightning PDP = previously damaged pipe (delayed failure mode such as dents and/or gouges). and IPC2008-64353. GENERAL NOTE: The abbreviations found in Table 7. Transitions at girth welds and fittings and to heavy wall pipe require additional care to ensure the hoop carrying capacity is effectively restored.1-1 relate to the 21 threats discussed in section 5. Bruce et al. R-2 Pipe = defective pipe Pipe Seam = defective pipe seam SCC = stress corrosion cracking . 851. Detection. D = this repair is not intended to restore axial pipe strength. Table 7.8.4. Particular care must be exercised to ensure the safety of workers when welding on pressurized lines... A. reinforcing sleeve … X X X … … … … … … … … … X X X A/D … … … X Composite sleeve … D D X … … … … … … … … … X X X A … … … … Epoxy-filled sleeve … X X X … … … … … … … … … X X X A X X C … Annular filled saddle … … … … … … … … … … … … … … … … B … … … … Mechanical leak clamp … … … X … … … … … … … … … … … … A … … … … ASME B31. C = the materials. B = these may be used to repair branch and T-joints but may not be used to repair straight pipe. pressurized sleeve … X X X X … … … … … … … … X X X X X … … X Type A. IPC2002-27131. = unacceptable A = these may be used to repair straight pipe but may not be used to repair branch and T-joints. Guidance can be found in publications by W. see ASME B31.1-1 Acceptable Threat Prevention and Repair Methods (Cont'd) Corrosion Incorrect Third-Party Damage Related Equipment Operation Weather Related Manufacture Construction O-Force Environment Prevention. weld procedures. and pass sequences need to be properly designed and correctly applied to ensure cracking is avoided. second.1-1 Acceptable Threat Prevention and Repair Methods (Cont'd) GENERAL NOTE (Cont'd): Seal/Pack = seal/pump packing failure Strip/BP = stripped thread/broken pipe TPD(IF) = damage inflicted by first.8S-2016 24 . Table 7. or third parties (instantaneous/immediate failure) Vand = vandalism WB/B = wrinkle bend or buckle ASME B31. The failure pressure ratio is used to categorize a defect as immediate. dents with develop and document appropriate assessment. response. any including examination or pressure reduction within a defect found to require repair or removal shall be period not to exceed 5 days following determination of promptly remediated by repair or removal.1-1. Damage and Mechanical Damage. or monitored. an operator may elect to treat all indications of within a period not to exceed 1 yr following determination stress corrosion cracks as requiring immediate response. 851. Prescriptive Integrity Management Plan GENERAL NOTE: Predicted failure pressure.8S-2016 Figure 7. Pf. of the condition. the detection and sizing of indications of stress corrosion and dents of any depth that affect nonductile welds.2 Crack Detection Tools for Stress Corrosion pipe diameter. period not to exceed 5 days following determination of uled integrity assessment interval stipulated by the integ. cracks. or lowering the operating pressure until such time as removal or repair is completed.) The In lieu of developing assessment. and repair operator shall expeditiously examine these indications plans.2. is calculated using a proven engineering method for evaluating the remaining strength of corroded pipe. ASME B31.8. response. unless the the condition. any defect found to repair or remove the defect. 25 . The Monitored indications are the least severe and will not operator shall examine these indications within a require examination and evaluation until the next sched. rity management plan. (For cracking (SCC). para. the condition. removal. require repair or removal shall be promptly remediated by repair. Indications requiring Any defect found to require repair or removal shall be immediate response are those that might be expected to promptly remediated by repair or removal unless the cause immediate or near-term leaks or ruptures based on operating pressure is lowered to mitigate the need to their known or perceived effects on the strength of the repair or remove the defect.2. dents that affect ductile girth or seam welds if and repair plans when in-line inspection (ILI) is used for the depth is in excess of 2% of the nominal pipe diameter. additional information.1-1 Timing for Scheduled Responses: Time-Dependent Threats. mechanical damage with or without Cracking. It is the responsibility of the operator to concurrent visible indentation of the pipe. times the MAOP shall be examined and evaluated 7. see ASME B31.2. provided that they are not Indications requiring a scheduled response would expected to grow to critical dimensions prior to the include any indication on a pipeline operating at or next scheduled assessment. above 30% of specified minimum yield strength (SMYS) of a plain dent that exceeds 6% of the nominal 7. operating pressure is lowered to mitigate the need to After examination and evaluation.3 Metal Loss and Caliper Tools for Third-Party according to a schedule established by Figure 7. scheduled. After examination and evaluation.2. pipeline.4. These could include dents with gouges. such as pres. or internal corrosion. this Supplement).4 Responses to Direct Assessment Inspections ating conditions to ensure the pipeline segment does not 7. all the indications found by inspections and repair all sesses the criticality of the anomaly and adjusts the defects that could grow to failure in 20 yr. 7. the operator shall ensure that the defect will not attain critical dimensions perform the following: prior to the scheduled repair or next inspection. evaluation of all selected locations must be performed sion threats shall be consistent with Table 5. environmental permit issues. An engineering critical assessment For the ECDA prescriptive program for pipeline (ECA) of some defects may be performed to extend the segments operating up to but not exceeding 30% repair or reinspection interval for a performance-based SMYS. the operator should written retest program consider that certain threats to specific pipeline operating conditions may require a reduced examination and 7. 7.4 Limitations to Response Times for Prescriptive.2.3. evaluate. then the interval shall be 5 as access. remediated by repair or removal.2. remaining defects will not grow to failure in 10 yr. the operator shall tion and evaluation of all selected locations must be use one of the following options to address the long-term performed within 1 yr of selection. this does not alleviate operators of the responsibility to evaluate the specific conditions and changes in oper. the operator elects to examine.2.3. 7. ECA is a rigorous evaluation of the data that reas.2 Internal Corrosion Direct Assessment (ICDA). and gas supply yr.1 External and Internal Corrosion Threats. the inspection intervals are conservative for pressure recorded in 5 yr prior to the effective date of potential defects that could lead to a rupture.1-1. Based Program. and repairs all defects that could grow to failure in 10 sure reduction.3 Stress Corrosion Cracking Direct Assessment be as follows: (SCCDA). (1) a documented hydrostatic retest program with a Based Program. If the operator elects to examine. For prescriptive-based raised above the historical operating pressure (highest programs. In yr. provided an analysis is performed defect types and the ECA methods used for such analyses. and these analyses.2. If the considering projected repair intervals and methods.1-1. When time-dependent anomalies such as technically justifiable interval. an analysis utilizing appro. if the operator chooses to in relation to the time scheduled for the repair. GRI-00/ (1) implement a documented hydrostatic retest 0230 (see section 14) contains additional guidance for program for the subject segment. and repair a smaller set of indications. The interval between pressure tests for stress corrosion cracking shall 7. The interval between 7. until a permanent repair is completed.2 Stress Corrosion Cracking Threat. ASME B31. ILI or pressure mitigation of SCC: testing (hydrotesting) may not be warranted if significant and extensive cracking is not present on a pipeline system. however. provided an analysis is performed to ensure all requirements. if the operator chooses to examine and evaluate program. examination and interval between tests for the external and internal corro. warrant special consideration (see GRI-01/0085). external corrosion. For the ECDA prescriptive program for pipelines oper- If the analysis shows that the time to failure is too short ating above 30% SMYS.4. tion. within 1 yr of selection. the examine and evaluate all the indications found by inspec- operator shall apply temporary measures. The operator’s integrity management program shall evaluate. the reinspection projected growth rates on site-specific parameters. and repair a operator should consider potential delaying factors. 26 . The For the ICDA prescriptive program.4. interval shall be 20 yr. The interval between determination and examination shall 7. The interval between subsequent examinations shall be consistent with Figure 7. For the SCCDA prescriptive program.3. such smaller set of indications. 7.1-1. then the include documentation that describes grouping of specific interval shall be 10 yr.6.1 External Corrosion Direct Assessment (ECDA).5 Extending Response Times for Performance.2.4. then the reinspection interval shall be 10 yr. or stress corrosion (2) an engineering critical assessment to evaluate cracking are being evaluated.8S-2016 7.3 Responses to Pressure Testing determination and examination shall be consistent with Any defect that fails a pressure test shall be promptly Figure 7. to ensure all remaining defects will not grow to failure in 20 yr (at an 80% confidence level). (2) technically justify the retest interval in the When determining repair intervals.3 Manufacturing and Related Defect Threats. be consistent with Figure 7. This may include third-party subsequent pressure test for the manufacturing threat damage or construction threats in pipelines subject to is not required unless the MAOP of the pipeline has pressure cycling or external loading that may promote been raised or when the operating pressure has been increased defect growth rates. examina- (a) If no failures occurred due to SCC. A evaluation interval. the risk and identify further mitigation methods priate assumptions about growth rates shall be used to (b) If a failure occurred due to SCC.1-1. utilized. In integrity management program. 8 INTEGRITY MANAGEMENT PLAN 7.5. These techniques may programs. Integrity management some cases. and risk assessments priority for integrity assessment. or during repair. divided by the MAOP of the pipeline. 4. or time-independent include replacing defective piping with new pipe. The highest-risk segments shall be given gathering. mance-based program as provided in para. These activities shall be identified. Integrity assessment of each system can be accomplished through a pressure test. Repair activities shall program.1-1 provides acceptable repair methods for 8. system or segment.5 Timing for Scheduled Responses risk assessment. The intervals may be the consequences of unintended releases. Prevention extended for a performance-based program as provided activities do not necessarily require justification in para. at a minimum. information about operating conditions. 7.2. mitigation activities 5. implementation of the inspection plan. earth 27 . Figure 7.6 Repair Methods Table 7. and sched- Operators who opt for prescriptive programs should uled (see section 7). 3. direct assessment. use. shall evaluate prevention techniques that prevent future For operators who choose performance-based deterioration of the pipeline. Prevention actions can be identified during normal pipeline operation. The (a) preventing third-party damage three plots correspond to (b) controlling corrosion (a) pipelines operating at pressures above 50% of (c) detecting unintended releases SMYS (d) minimizing the consequences of unintended (b) pipelines operating at pressures above 30% of releases SMYS but not exceeding 50% of SMYS (e) operating pressure reduction (c) pipelines operating at pressures not exceeding 30% There are other prevention activities that the operator of SMYS may consider. Prevention plays a major role in existing conditions. and industry-proven risk assessment reducing or eliminating the threats from third-party methods.8S-2016 The interval between subsequent examinations shall 7. resident.1-1 and section An operator’s integrity management program shall A-4. Prevention strategies (including intervals) be made in accordance with ASME B31. conducted per the requirements of sections 2.2. injecting employed for each threat/segment should be determined corrosion inhibitors and pipeline cleaning.8 and/or other should also consider the classification of identified accepted industry repair techniques.7 Prevention Strategy/Methods inspection using a variety of tools.1 General each of the 21 threats. All repairs assessment (see section 5) for each threat and for each shall be made with materials and processes that are pipeline segment or system. the operator in Nonmandatory Appendix A.2.5.1-1 contains three plots of the allowed time to The predominant prevention activities presented in respond to an indication. based on the predictive failure section 7 include information on the following: pressure. The integrity management plan is developed after gath- Each operator’s integrity management program shall ering the data (see section 4) and completing the risk include documented repair procedures. or changing the by analysis using system attributes. installa- in order to ensure that effective prevention methods are tion of sleeves. a combination of these methods may be program prevention strategies should be based on data appropriate. A tabulation of prevention activities and The figure is applicable to the prescriptive-based their relevance to the threats identified in section 2 is program. cold-weather-related failures. an in-line ð16Þ 7. Repair may threats as time-dependent.2. internal corrosion. and Following the integrity assessment. presented in Table 7. prioritized. Mitigation consists of two parts.8 requirements. The intervals may be extended for the perfor. The past should be continued in the integrity management first part is the repair of the pipeline. Figure 7. external corrosion. 7. Prevention is an important proactive element of an or use of other proven technologies (see section 6).1-1. An appropriate integrity suitable for the pipeline operating conditions and meet assessment method shall be identified for each pipeline ASME B31. threat identification. both the preventive methods and time intervals include providing additional cathodic protection. through additional inspection data. ASME B31. Prevention measures shown to be effective in the shall be undertaken. stress corrosion cracking.1-1 and section A-4 are applicable to include applicable activities to prevent and minimize prescriptive-based programs. 7.8 Prevention Options provide similar safe interval between periodic integrity assessments consistent with Figure 7. the prevention methods indicated Once the repair activities are determined. coating repair. Pf. damage.2. or other rehabilitation. a pipeline operator consider changes made to the pipeline system or can exercise a variety of options for integrity assessments segment. performed after substantial changes to the system are made and before the end of the current interval. therefore. data for each threat and pipeline segment. and Integrating Data. current prioritization listing and schedule shall be contained in this section of the integrity management 8.”A each threat analyzed and each pipeline segment or system. Using a risk assessment model.3 Plan Framework discussed in para. over time. time-dependent threats for prescriptive plans. Risk assessment should be upon more complete data or information about the performed periodically to include new information. activities or more frequent maintenance activities may This ongoing process will most likely result in a series of provide a more effective solution. A series of additional mitigation inspection is being performed. These activities may include. Data gathering is covered A performance-based integrity management plan. methods and performing the inspections are covered integrate. Changes to the Data collected during the inspection and mitigation acceptance criteria will also necessitate reassessment.3. The assess- ment schedule for the stress corrosion cracking threat is 8.2 Updating the Plan results of this assessment are to be reflected in the mitiga- tion and integrity assessment activities. all the threats. information obtained and to provide for future integrity It is recognized that certain integrity assessment activ. the appropriate integrity assessments shall be ongoing data integration and periodic risk assessment implemented. incorporate any external changes. construction. The 8. organize. prevention for these threats is a key or segment is gathered. This of risk.6. ASME B31. prevention of third-party damage and moni. A-4. and consider and prevention activities. activities have been implemented. activities shall be analyzed and integrated with previously The integrity management plan shall contain specifics collected data. Based on the assessment assessments via its integration (see section 4).8S-2016 movement failures. and review all pertinent and available in section 6.1-1 provides the integrity assessment sche- shall remain flexible and incorporate any new dules for the external corrosion and internal corrosion information. sessment.1 Gathering. All data will be used to support future risk assess- toring for outside force damage. ities. All integ- equipment threats. The plan shall iden- ities may be one-time events and focused on elimination of tify required integrity assessment actions and at what certain threats. The plan shall be updated periodi. This process 28 . Integrity assessments shall be conducted will result in continual revision to the integrity assessment using in-line inspection tools. The addition of this new data is a continuous process that.2 Assess Risk. For certain threats. The plan. The specifics for selecting integrity assessment first step in the integrity management process is to collect. such as manufacturing. and established intervals the actions will take place. problems caused by heavy rains and step is repeated after integrity assessment and mitigation floods. and as new operation All threats cannot be dealt with through inspection and and maintenance information about the pipeline system repair. dent threats. ments and integrity evaluations.3 Integrity Assessment.3. Reviewing. This is in addition to other types of integrity about how risks are assessed and the frequency of reas- management-related data that is constantly being gath. and failures caused by incorrect operations. new scientific techniques that have been developed and Prior integrity assessments and mitigation activities commercialized since the last assessment. rity assessments shall be prioritized and scheduled. assessments at the required intervals. This information review shall be element in the plan.4. The specifics for assessing risk are covered in ered through normal operations and maintenance activ. Implementation of prevention or segment shall be properly managed (see section 11). requires more detailed analyses based 8. changes to direct assessment. line. containing the same structure as the prescriptive- based plan.3. plan. this cally as additional information is acquired and portion of the plan shall be modified to reflect all new incorporated. and/or and mitigation aspects of the plan. periodic inspection will be required. pressure testing. It is recom- should only be included in the plan if they were as rigorous mended that this be performed annually but shall be as those identified in this Code. section 5. For other threats. as well as their timing. The plan Table 5. will improve the accuracy of future risk 8. In addition. After each integrity assessment. in section 4. use of these the physical and operating aspects of the pipeline system tools may be inappropriate. for contained in the plan or in a database that is part of the example. such as time-depen. More than one assessment activities or follow-up to previous mitigation activities method or more than one tool may be required to address may also be required. Integrity assessment additional integrity assessments or review of previous method selection is based on the threats for which the integrity assessments. The assessment schedules for all The integrity management plan shall contain detailed other threats are identified in appropriate paragraphs of information regarding each of the following elements for Nonmandatory Appendix A titled “Assessment Interval. 3. and 8. Prevention least annually to provide a continuing measure of integrity is also an appropriate activity for time-independent management program effectiveness over time. aggregate improvements.42 MSm3/d) Repair methods Replacement Leak/rupture history None Pressure cycling Low CP effectiveness Fair SCC indications Minor cracking A performance-based integrity management plan can fied as new information is obtained and shall be a real-time provide alternative integrity assessment. and aspect of the plan (see section 7). Threat-specific evaluations may apply to a particular area of concern. including the reassessment interval. prevention methods with different implementation Tables 8. Integrity mitigation is prevention.4-2. segment 3). The responses shall be immediate. (6. for a hypothetical pipeline segment (line 1.35 mm) Manufacturer A.8S-2016 Table 8.4-1 Example of Integrity Management Plan for Hypothetical Pipeline Segment (Segment Data: Line 1.3. These This section provides the performance plan require- repairs shall be performed in accordance with accepted ments that apply to both prescriptive-based and perfor- standards and operating practices. while 29 .3.3. The mitigation element of the 9 PERFORMANCE PLAN plan consists of two parts. O. repair. ASME B31.4-3 provide an example times than those required under the prescriptive of an integrity management plan in a spreadsheet format program. The prioritization and schedule shall be modi. Smith Manufacturer process Low frequency Manufacturing date 1965 Seam type Electric resistance weld Design/construction Operating pressure (high/low) 630/550 psig (4 340/3 790 kPa) Operating stress 72% SMYS Coating type Coal tar Coating condition Fair Pipe install date 1966 Joining method Submerged arc weld Soil type Clay Soil stability Good Hydrostatic test None Operational Compressor discharge temperature 120°F (49°C) Pipe wall temperature 65°F (18°C) Gas quality Good Flow rate 50 MMSCFD (1. Based on the results of the integrity assess. rity assessments. Mitigation assessment plan devised based on the risk assessment. Such threats. The plan shall and the mitigation plan that would be implemented specify how and when the operator will respond to integ. All mitigation activities shall be prioritized and evaluations should consider both threat-specific and scheduled. appropriate repair activities shall be determined and conducted. 9. and Intervals. The second part of mance-based integrity management programs. Prevention can stop or slow management plan evaluations shall be performed at down future deterioration of the pipeline.4-1. Segment 3) Segment Data Type Example Pipe attributes Pipe grade API 5L-X42 (290 MPa) Size NPS 24 (DN 600) Wall thickness 0. This spreadsheet shows the segment data. The first part is the repair of the pipeline.4 Responses to Integrity Assessment. scheduled. or monitored.250 in. (Repair and Prevention). 8. These decisions shall be fully documented.3.1 Introduction ments and the threat being addressed. the integrity 8. The test pressure will be at 1. Proper selection GENERAL NOTE: For this pipeline segment. and permit timely evaluations. Change shall be monitored so the measures measures can be used to evaluate prevention or mitigation will remain effective over time as the plan matures.3. measure evaluation and trending can also lead to recogni. Threat Criteria/Risk Assessment Integrity Assessment Mitigation yr External corrosion Some external corrosion history. SCC. evaluation within a realistic time frame.0.2. Segment 3) Interval. hydrostatic testing will be and evaluation of performance measures is an essential conducted. Operational measures include operational and maintenance trends that measure how well the system is responding to the integ- rity management program.2 Operational Measures. Data Test failures for reasons other than external tion of unexpected results that may include the recogni. The safety has been attained. management program results that demonstrate improved Interval for The interval for reinspection will be 3 yr reinspection if there was a failure caused by SCC. tions. Performance successful. An example of such a measure 30 .4-3 Example of Integrity Management management program. Process or activity indicators. or perform 1.1 Process or Activity Measures. The measures provide an indica- interval will be 5 yr if the test was tion of effectiveness but are not absolute. no in.3. Conduct hydrostatic test. Performance measures should be selected carefully to ensure that they are reasonable program effectiveness 9. or seam defect tion of threats not previously identified.25 times the MAOP direct assessment SCC Have found SCC of near critical Conduct hydrostatic test Replace pipe at test 3–5 dimension failure locations Manufacturing ERW pipe. activities. These measures determine how well an The time required to obtain sufficient data for analysis operator is implementing various elements of the integrity shall also be considered when selecting performance management program. measurable.8S-2016 Table 8. Segment 3) following questions: Example Description (a) Were all integrity management program objectives Repair Any hydrostatic test failure will be repaired accomplished? by replacement of the entire joint of pipe. Measures relating to process or measures.4-2 Example of Integrity Management Plan for Hypothetical Pipeline Segment (Integrity Assessment Plan: Line 1.25 times the MAOP direct assessment Internal corrosion No history of IC issues.2. Plan for Hypothetical Pipeline Segment Program evaluation will help an operator answer the (Mitigation Plan: Line 1. attainable.2 Performance Measures Characteristics design and levels. Conduct hydrostatic test. measures shall be simple. (b) Were pipeline integrity and safety effectively Prevention Prevention activities will include further improved through the integrity management program? monitoring for SCC at susceptible locations.and long-term performance measure evalua. Selection of this method is appropriate due to its ability to address the internal and external corrosion threats as well as the manu- activity in determining integrity management program facturing threat and the SCC threat. Replace/repair locations 10 no in-line inspection perform in-line where CFP below inspection. Replace/repair locations 10 line inspection perform in-line where CFP below inspection. review of the cathodic protection 9. and monitoring for selective seam corrosion when the Performance measures focus attention on the integrity pipeline is exposed. joint factor <1. All performance must be considered when performing risk assessment for the associated threat. or perform 1.39 times effectiveness. rele- vant.or outside-force. ASME B31. 9. Methods shall be implemented to permit activity shall be selected carefully to permit performance both short. None required N/A N/A related issues overall measures apply to all pipelines under the integrity Table 8. the MAOP. integration or internal corrosion. Integrity management program performance measures can generally be categorized into groups. Conduct hydrostatic test Replace pipe at test N/A no hydrostatic test failure locations Construction/fabrication No construction issues None required N/A N/A Equipment No equipment issues None required N/A N/A Third-party damage No third-party damage issues None required N/A N/A Incorrect operations No operations issues None required N/A N/A Weather and outside force No weather. For this metric. they provide an indication of how the plan may be (4) number of leaks. (a) Performance metrics shall be selected and applied and occurrences listed in Table 9. performance multiple anomalies in a single repair area. the following overall program measure- annual basis. number of patrol detects Operational measures Number of significant ILI corrosion New rectifiers and ground anomalies beds installed.4-2 utilizing normaliza- on a periodic basis for the evaluation of both prescriptive- tion factors meaningful to the operator for that event and based and performance-based integrity management their system. internal benchmarking can be conducted miles (kilometers) of pipeline inspected during the that may compare a segment against another adjacent reporting period.3 Direct Integrity Measures. anywhere on the pipe- example. and for evaluation length.3-1 Performance Measures Measurement Category Lagging Measures Leading Measures Process/activity measures Pipe damage found per location Number of excavation excavated notification requests. injuries. number of customers. ASME B31. including pipeline miles (kilometers) segment or those from a different area of the same pipeline that were inspected as part of the integrity management system. shall be counted when a repair method is used that repairs In addition to the above categories.4-2 provides a suggested list. It may be appropriate and useful for operators to normalize the findings. or a combination of of overall integrity management program performance. the operator may develop 9. The information obtained may be used to evaluate plan but were not required to be inspected] the effectiveness of prevention activities. repairs. See explanation for (2). coating repairs are 9. the operator should choose three also by comparison with other systems on an industry. and incidents (classi- expected to perform. programs. Table 9.) measures can be categorized as leading measures or (3) number of scheduled repairs completed as a lagging measures.8S-2016 Table 9. time. Several examples of performance fied by cause) measures classified as described above are illustrated (c) For operators implementing performance-based in Table 9. although 9. performance-based program. or four metrics that measure the effectiveness of the wide basis.3 Performance Measurement Methodology others may be used that are more appropriate to the An operator can evaluate a system’s integrity manage. Direct integrity not considered repairs. ments shall be determined and documented: (d) In addition to performance metric data collected (1) number of miles (kilometers) of pipeline directly from segments covered by the integrity manage- inspected versus program requirements [the total ment program.2. events. programs. Only repairs physically made to the pipe are considered repairs. mitigation 31 . Such metrics shall be suitable for evaluation Such normalization factors may include covered pipeline of local and threat-specific conditions. it is essential that sufficient metric of the threat-specific metrics for each threat in data be collected to support those inspection intervals. Since performance-based inspection (b) For operators implementing prescriptive intervals will be utilized in a performance-based integrity programs.2. the threat-specific metrics shown in Nonmandatory Appendix A shall be considered. In addition to the ment program performance within their own system and four metrics above. such as improving the excavation repairs made to a pipeline as a consequence of the integ- notification process within the system.4 Performance Measurement: Intrasystem their own set of metrics. performance measurement shall include all management program. reduced CIS fault detects Direct integrity measures Leaks per mile (km) in an integrity Change in leaks per mile (km) management program might be the changes in corrosion rates due to the imple.3-1.] tive. and fatalities. Leading measures are proac. line. these or others. Lagging measures are reactive in result of the integrity management inspection program that they provide an indication of past integrity manage. [the total number of scheduled actionable anomaly ment program performance. Nonmandatory Appendix A (see Table 9.2. however. The number of result of the integrity management inspection program third-party pipeline hits after the implementation of (the total number of immediate actionable anomaly prevention activities. specific performance-based program. CP current demand change. is another rity management plan inspections. Each actionable anomaly repaired measures include leaks. failures. (2) number of immediate repairs completed as a mentation of a more effective CP program.4-1). and that would help them evaluate trends. ruptures. Program evaluation shall be performed on at least an Additionally. or relocation actions due to weather-related or outside-force threats 32 . replacement.8S-2016 Table 9.4-1 Performance Metrics Threats Performance Metrics for Prescriptive Programs External corrosion Number of hydrostatic test failures caused by external corrosion Number of repair actions taken due to in-line inspection results Number of repair actions taken due to direct assessment results Number of external corrosion leaks Internal corrosion Number of hydrostatic test failures caused by internal corrosion Number of repair actions taken due to in-line inspection results Number of repair actions taken due to direct assessment results Number of internal corrosion leaks Stress corrosion cracking Number of in-service leaks or failures due to SCC Number of repair replacements due to SCC Number of hydrostatic test failures due to SCC Manufacturing Number of hydrostatic test failures caused by manufacturing defects Number of leaks due to manufacturing defects Construction Number of leaks or failures due to construction defects Number of girth welds/couplings reinforced/removed Number of wrinkle bends removed Number of wrinkle bends inspected Number of fabrication welds repaired/removed Equipment Number of regulator valve failures Number of relief valve failures Number of gasket or O-ring failures Number of leaks due to equipment failures Number of block valve failures Third-party damage Number of leaks or failures caused by third-party damage Number of leaks or failures caused by previously damaged pipe Number of leaks or failures caused by vandalism Number of repairs implemented as a result of third-party damage prior to a leak or failure Incorrect operations Number of leaks or failures caused by incorrect operations Number of audits/reviews conducted Number of findings per audit/review. ASME B31. classified by severity Weather-related and outside Number of leaks that are weather related or due to outside force forces Number of repair. process. or performance validation.4-2 Overall Performance Measures Miles (kilometers) inspected versus integrity management program requirement Jurisdictional reportable incidents/safety-related conditions per unit of time Fraction of system included in the integrity management program Number of anomalies found requiring repair or mitigation Number of leaks repaired Number of pressure test failures and test pressures [psi (kPa) and % SMYS] Number of third-party damage events. sources. changes and/or improvements to the integrity manage- (6) Individuals have received proper qualification. odic audits to validate the effectiveness of their integrity management programs and ensure that they have been 9. met. mance measures and audits. external audit frequency shall be established. and documented. integrity management program. damage detected Risk or probability of failure reduction achieved by integrity management program Number of unauthorized crossings Number of right-of-way encroachments Number of pipeline hits by third parties due to lack of notification as locate request through the one-call process Number of aerial/ground patrol incursion detections Number of excavation notifications received and their disposition Integrity management program costs techniques. ASME B31. (10) The risk criteria used have been reviewed and documented. An In addition to intrasystem comparisons. Internal and external audit results are perfor- (4) A responsible individual has been assigned for mance measures that should be used to evaluate effective- each element. however. Recommendations for sible individuals. Audits may be performed by internal staff. and repair criteria have can provide a basis to substantiate metric analyses and been established. be used to provide an effective basis for evaluation of the mation is internal auditing. considering the comparisons can provide a basis for performance established performance metrics and their particular measurement of the integrity management program. The results.5 Performance Measurement: Industry Based conducted in accordance with the written plan. and audits shall (e) Another technique that will provide effective infor. (8) Required activities are documented. and resultant changes made to the requirements of this document. can be useful.6 Performance Improvement place. results of internal benchmarking. prefer. Audits conducted by outside entities can also audit program. audits shall be utilized to modify the integrity manage- (3) Activities are performed in accordance with the ment program as part of a continuous improvement plan.8S-2016 Table 9. mitigation. Such comparisons (11) Prevention. (2) Written integrity management plan procedures The results of the performance measurements and and task descriptions are up to date and readily available. (1) A written integrity management policy and program for all the elements in Figure 2. (7) The integrity management program meets the recommendations. metrics. integrity management program. Benchmarking with other gas pipeline operators ably by personnel not directly involved in the administra. integrity management program shall be documented. and jurisdictional data evolves. near misses. (f) Data developed from program-specific performance ment program. A list of essential audit items is provided evaluated to ensure that all comparisons made are below as a starting point in developing a company valid. time base in addition to changes or modifications This can include comparisons with other pipeline opera- made to the integrity management program as it tors. ment program shall be based on analysis of the perfor- which has been documented. provide useful evaluation data. Operators shall conduct peri. ness in addition to other measures stipulated in the (5) Appropriate references are available to respon. identify areas for improvements in the integrity manage. (9) Action items or nonconformances are closed in a timely manner. industry data sources. any performance measure or tion of the integrity management program.1-2 shall be in 9. 33 . or other evaluation derived from such sources shall be carefully resources. including exca. both routine and program should also be part of the internal communica- emergency tions plan. ASME B31. and respond to a leak informed about their integrity management efforts and (6) general information about the operator’s preven- the results of their integrity management activities. temporary. and who to contact if there is any procedures should be flexible enough to accommodate damage both major and minor changes. Public Awareness Programs for Pipeline pipeline. and the environment. including general business contact mended that communications take place periodically It is expected that some dialogue may be necessary and as often as necessary to communicate significant between the operator and the public in order to changes to the integrity management plan. (1) operator should maintain continuing liaison with A management of change process includes the all emergency responders. regional and area planning (1) reason for change (2) authority for approving changes 34 . 11 MANAGEMENT OF CHANGE PLAN rity management plan (a) Formal management of change procedures shall be (7) damage prevention information. procedural. API RP convey the operator’s confidence in the integrity of the 1162. whether permanent or (2) summary of emergency preparedness and integ. (1) information regarding operator’s efforts to Communications should be conducted as often as neces- support excavation notification and other damage preven- sary to ensure that appropriate individuals and authori- tion initiatives ties have current information about the operator’s system (2) company name. and must be understood (b) Public Officials Other Than Emergency Responders by the personnel that use them. and how to obtain a summary of the integ. 10.8S-2016 10 COMMUNICATIONS PLAN committees. physical.2 External Communications Such opportunities should be welcomed in order to help protect assets. report. and company ness with local officials websites may be an effective way to conduct these (d) General Public communication efforts. and emergency preparedness. location. as well as to convey the operator’s expectations Operators. contact. 10. Other information may be communicated upon (9) coordination of operator’s emergency prepared- request.3 Internal Communications (a) Landowners and Tenants Along the Rights-of-Way Operator management and other appropriate operator (1) company name. both routine and emergency The operator shall develop and implement a commu- (3) local maps nications plan in order to keep appropriate company (4) facility description and commodity transported personnel. and contact personnel must understand and support the integrity information management program. report. The following items should be considered for commu- nication to the various interested parties: 10. and how to obtain a summary The information may be communicated as part of of the integrity management plan other required communications. provides additional guidance. jurisdictional emergency planning offices. and the public (5) how to recognize. of the public as to where they can help maintain integrity. Management of change (1) periodic distribution to each municipality of shall address technical.1 General (2) company name and contact numbers. jurisdictional. excavation notification changes to pipeline systems and their integrity. tion and integrity measures. integrity measures. including local emergency following: planning commissions. people. jurisdictional authorities. Use of industry. etc. developed in order to identify and consider the impact of vation notification numbers. and emergency and their integrity management efforts. This should be accomplished (2) general location information and where more through the development and implementation of an specific location information or maps can be obtained internal communications aspect of the plan. It is recom- reporting information. and respond to a leak and resulting adjustments to the integrity management (5) contact phone numbers. These center requirements. and organi- maps and company contact information zational changes to the system. The process should incorporate planning rity management program for each of these situations and consider the unique (c) Local and Regional Emergency Responders circumstances of each. (7) station locations and descriptions Some of the information should be communicated routi- (8) summary of operator’s emergency capabilities nely. (6) general information about the pipeline opera- tor’s prevention. (3) commodity transported Performance measures reviewed on a periodic basis (4) how to recognize. or documentation. daily changes in operating mented proof that the operator meets all the requirements pressure). however small. For example.2 Quality Management Control management process remains viable and effective as (a) Requirements of a quality control program include changes to the system occur and/or new.g. suggest controls or modi. Most changes. such as changes to the CP program or. fatigue shall be considered in each of the of their integrity management program. The following are examples that are be included in the information provided in communication gas-pipeline specific but are by no means all-inclusive. (2) If the results of an integrity management (h) The application of new technologies in the integrity program inspection indicate the need for a change to management program and the results of such applications the system. tion of the new equipment. require qualification of personnel for the correct opera- tion near the pipeline.8S-2016 (3) analysis of implications understanding of the system and possible threats to its (4) acquisition of required work permits integrity. Pipeline operators that have a quality control program (c) Along with management. a docu- (5) Monitor. that change shall be reflected in shall be part of an acceptable integrity management the integrity plan and the threats shall be re-evaluated program. 35 . and maintenance. revised.1 General (4) If a line has been operating in a steady-state mode and a new load on the line changes the mode of operation Quality control as defined for this Code is the docu- to a more cyclical load (e. results from the program can cause conducted periodically. will have a conse- quality program. conversely. commu- can require changes in the integrity management program nications regarding the integrity of the pipeline should be and. mented record of changes should be developed and main- (6) Implement actions necessary to achieve planned tained. accordingly. It should include the process and design infor- (5) documentation mation both before and after the changes were put into (6) communication of change to affected parties place. technical or procedural change. processes. In addition. This information will provide a better results and continued improvement of these processes. quent effect on another aspect of the system. the allowable MAOP. or closer This section describes the quality control activities that to. The corrected data becomes available. measure. from the pipeline operator to affected parties. or a change in likelihood of an inci. if necessary. and analyze these processes. (d) Management of change ensures that the integrity 12.. Management ensure that both the operation and control of these of change procedures provides a means of maintaining processes are effective. the review procedure that meets or exceeds the requirements in this section can should require involvement of staff that can assess incorporate the integrity management program activities safety impact and. Any changes to the system should system changes. 12. Any change to equip- following six activities are usually required: ment or procedures has the potential to affect pipeline (1) Identify the processes that will be included in the integrity. implementation. (1) If a change in land use would affect either the (g) System changes. such as subsidence due to underground mining. particularly in equipment. For those operators who do not fications. ASME B31. The operator shall have the flexibility to main. threats where it applies as an additional stress factor. this section outlines the basic tain continuity of operation within established safe requirements of such a program. order during periods of change in the system and (4) Provide the resources and information necessary helps to preserve confidence in the integrity of the to support the operation and monitoring of these pipeline. should be documented and communicated to appropriate other than temporary reductions in operating pressure. procedures. operating limits. staff and stakeholders. have a quality program. As provided in section 10. these shall be communicated to operators and reflected in an updated integrity management program. may consequence of an incident. All changes shall be iden- (3) Determine the criteria and methods needed to tified and reviewed before implementation. such as increases in popula. within their existing plan. (e) In order to ensure the integrity of a system. 12 QUALITY CONTROL PLAN (3) If an operator decides to increase pressure in the system from its historical operating pressure to. refresher training dent. (7) time limitations (f) Communication of the changes carried out in the (8) qualification of staff pipeline system to any affected parties is imperative to (b) The operator shall recognize that system changes the safety of the system. (2) Determine the sequence and interaction of these many equipment changes will require a corresponding processes. the should be provided to ensure that facility personnel change must be reflected in the integrity management understand and adhere to the facility’s current operating plan and the threats re-evaluated accordingly. DEFINITIONS. ment them within the quality program. activities to be included in the quality implemented according to plan and document these steps. of documented activities include risk assessments. and be qualified to execute the activ. their achievement shall be part of the quality control plan.8S-2016 ð16Þ Figure 13-1 Hierarchy of Terminology for Integrity Assessment (b) Specifically. Documentation of such compe. and qualification. aware of the program 13 TERMS. and making recommendations operator shall ensure control of such processes and docu- for improvement. ð16Þ ities within the program. and/or performance (1) The operator shall determine the documentation metrics shall be defined. mented and the effectiveness of their implementation (2) The responsibilities and authorities under this monitored. program shall be clearly and formally defined. the (7) Corrective actions to improve the integrity integrity management plan. These (6) Periodic internal audits or independent third- documents shall be controlled and maintained at appro. ASME B31. (4) The personnel involved in the integrity manage- ment program shall be competent. awareness. Examples and its quality plan are required. and data documents. actionable anomalies: anomalies that may exceed accep- (5) The operator shall determine how to monitor the table limits based on the operator’s anomaly and pipeline integrity management program to show that it is being data analysis. party reviews of the integrity management program priate locations for the duration of the program. 36 . and the processes for integrity assessment. control program are as follows: These control points. integrity management management program or quality plan shall be docu- reports. (c) When an operator chooses to use outside resources (3) Results of the integrity management program to conduct any process (for example. the predetermined intervals. AND ACRONYMS and all of its activities. See Figure 13-1 for the hierarchy of terminology for tence. required and include it in the quality program. pigging) that affects and the quality control program shall be reviewed at the quality of the integrity management program. criteria. 8S-2016 active corrosion: corrosion that is continuing or not cathodic protection (CP): technique to reduce the corro- arrested. orientation. produces coalescence by heating them with an arc. environment. that loads acting alone or in combination with hydrostatic results from an electrochemical reaction with its pressure.] such as. prevents or reduces corrosion. size. and closures. sensing the shape of the internal surface of the pipe. backfill: material placed in a hole or trench to fill excavated (When used in a broader sense. 3. elongated defect caused by mechan- of an in-line inspection tool with the purpose of improving ical splitting into two parts. a close fit around a hot tap “T. corrosion rate: rate at which corrosion proceeds. property. ASME B31. data interpretation. which is a cast ferrous material in which a major detect: to sense or obtain measurable wall loss indications part of the carbon content occurs as free carbon in the from an anomaly in a steel pipeline using in-line inspection form of flakes interspersed throughout the metal. impact. of the pipe that produces a decrease in the diameter and is cast iron: unqualified term “cast iron” shall apply to gray concave inward. sion of a metal surface by making that surface the cathode annular filled saddle: an external steel fabrication similar of an electromechanical cell. dry film thickness.” includes a series of aboveground pipe-to-soil potential measurements taken at predetermined increments of a anomaly: an unexamined deviation from the norm in pipe few to several feet (meters) along the pipeline and material. and angle. and substances that. See Figs. pretreatments. valves. tion caused by bending. after application to a surface. and/or torsional corrosion: deterioration of a material. coating system: complete number and types of coats sure and with or without filler metal. but not limited to. by inspection indications are classified and characterized. dissolves in water to form carbonic acid. the “T” is joined with seam welds like a type A sleeve. corrosion inhibitor: chemical substance or combination of mately in the same plane. shape. such as data analysis: the evaluation process through which dents. consequence: impact that a pipeline failure could have on ling in the pipe wall or excessive cross-sectional deforma. processes are used with or without the application of pres. space around a pipeline or other appurtenances. combustion. [Sealing (batching) pigs are typically used for element fitted in line with pipe in a pipeline system. ovality. The and location of an anomaly. annular space between the pressure-containing pipes and the saddle is filled with an incompressible material to close interval survey (CIS): inspection technique that provide mechanical support to the welded “T. cast iron. and manner of applica- batch: a volume of liquid that flows en masse in a pipeline tion are included.” The other half away from characterize: to qualify the type. colorless gas that does not support characteristics that exceed acceptable limits. calibration dig: exploratory excavation to validate findings crack: very narrow. which is applied with an buckle: condition in which the pipeline has undergone adhesive. wrinkles. 37 . used to provide information on the effectiveness of the anomaly and pipeline data analysis: the process through cathodic protection system. caliper tool or geometry tool: an instrumented in-line inspection tool designed to record conditions. decorative. surface preparation. The Coating also includes tape wrap. analyzed to further classify and characterize anomalies.0. bell hole: excavation that minimizes surface disturbance flanges. or welds. 2(A). is converted into a solid arc welding or arc weld: group of welding processes that protective. elbows. yet provides sufficient room for examination or repair of composite repair sleeve: permanent repair method using buried facilities. coatings. and the environment. applied to a substrate in a predetermined order. defect: a physically examined anomaly with dimensions or carbon dioxide: a heavy. employees. or other technologies.) physically separated from adjacent volume(s) of liquid or component or pipeline component: an individual item or gas. or functional adherent film. butt weld: a nonstandard term for a weld in a butt joint. when present in the environment or on a 51(B) in AWS A3. bend radius. liquefiable. separation. butt joint: a joint between two members aligned approxi. tees. surface. which anomaly and pipeline data are integrated and coating: liquid. the public. axial. current: flow of electric charge. usually a metal. or mastic composition that. 51(A). to a sleeve except one half is pierced and forged to provide certification: written testimony of qualification. 1(A). and dent: permanent deformation of the circular cross section is found in some natural gas streams. composite sleeve material. sufficient plastic deformation to cause permanent wrink. method under the direction of qualified supervision including the performance of the NDT method and discontinuity: an interruption of the typical structure of a related activities but not including time spent in organized material. is still operable but is documented: condition of being in written form. a competent following: person with demonstrated understanding and experience (a) the point of custody transfer of gas suitable for in the application of the engineering principles related to delivery to a distribution system the issue being assessed. 12. metal or nonmetallic conductor in a corrosive electrolyte. crack as a result of repeated cycles of stress. such as a lack of homogeneity in its mechanical. because of an electrical contact with a more noble welded pipe as a result of being produced in a continuous metal and/or a more noble localized section of the forming process from coils of flat plate. evaluation: a review following the characterization of an fied outside diameter of 8. examination: direct physical inspection of a pipeline that direct current voltage gradient (DCVG): inspection tech. a competent person with demonstrated gas processing plant: facility used for extracting commer- understanding and experience in the application of the cial products from gas. ASME B31. may include the use of nondestructive examination (NDE) nique that includes aboveground electrical measurements techniques or methods. taken at predetermined increments along the pipeline and is used to provide information on the effectiveness of the experience: work activities accomplished in a specific NDT coating system. training programs. (323. Features may be anomalies.85 mm). NPS 8 (DN 200) pipe has a speci. If no gas processing plant exists. not necessarily visible layer of material. or physical characteristics. tion system. ductility: measure of the capability of a material to be feature: any physical object detected by an in-line inspec- deformed plastically before fracturing. For example. or under the super- vision of. or has deteriorated seriously to the point that it has has a straight longitudinal or helical seam containing filler become unreliable or unsafe for continued use. gas from one or more production facilities to the inlet of a based upon fracture mechanics. failure: general term used to imply that a part in service has become completely inoperable. suitable for domestic or industrial fuel and transmitted or distributed to the user through a piping system. without the admixture of air. electrolyte: medium containing ions that migrate in an gas: as used in this Code. or some other item. not to be confused aromatic polyols (like bisphenol) with epichlorohydrin with the dimensionless NPS (DN). incapable of satisfactorily performing its intended func- double submerged-arc welded pipe (DSAW pipe): pipe that tion. (219. A discontinuity is not necessarily a defect. 38 . (609. straight longitudinal seam produced without the addition film: thin.000 meets specified acceptance criteria. welds. (b) the point where accumulation and preparation of gas from separate geographic production fields in reason- environment: surroundings or conditions (physical. using common types are natural gas. electric-resistance-welded pipe (ERW pipe): pipe that has a nearby metallic objects. of filler metal by the application of pressure and heat obtained from electrical resistance. and NPS 24 actionable anomaly to determine whether the anomaly (DN 600) pipe has a specified outside diameter of 24. the of the maximum tolerable sizes for imperfections. manufactured gas. and gas is transported to the most downstream of either of the conducted by. or under the supervision of. ERW pipe forming galvanic corrosion: accelerated corrosion of a metal is distinct from flash welded pipe and furnace butt. metal deposited on both sides of the joint by the fatigue: process of development of or enlargement of a submerged-arc welded process. the issue being assessed. components. neering principles. metallurgical. and conducted by. in. mechanical) in which a material exists. engineering and risk management principles related to gathering system: one or more segments of pipeline.625 in.08 mm). any gas or mixture of gases electric field. of the effect of relevant variables liquefied petroleum gas distributed as a vapor. and engineering principles. NPS 12 and characterized by the presence of reactive oxirane (DN 300) pipe has a specified outside diameter of end groups. that allows determination gas processing plant. that transports engineering critical assessment: an analytical procedure. able proximity has been completed chemical. usually interconnected to form a network. The engineering assessment: a documented assessment.8S-2016 diameter or nominal outside diameter: as-produced or as. using engi.750 in.90 mm). epoxy: type of resin formed by the reaction of aliphatic or specified outside diameter of the pipe. with or upon service or integrity of a pipeline system. ” dard service pressure delivered to the customer. and loose connections. attack (i. sulfide. girth weld: complete circumferential butt weld joining integrity assessment: process that includes inspection of pipe or components. Examples length: a piece of pipe of the length delivered from the mill. sometimes referred to as a “pig trap. lished by this section. caused by exposure to environments (liquid or gas) that allows absorption of hydrogen into the material. and determining the resulting integrity of the lized elongated grooves or cavities in a metal pipeline. surface decarburization and chemical reaction liquefied petroleum gas(es) (LPG): liquid petroleum gases with hydrogen). In such a system.e. separation or pullout. pipeline through analysis.e. variety of techniques. regardless of its actual dimen- cracks. in-line inspection tools: any instrumented device or vehicle that records data and uses nondestructive test methods or magnetic particle inspection (MPI): a nondestructive test other techniques to inspect the pipeline from the inside. and other defects. and circumfer- hydrogen-induced damage: form of degradation of metals ential). in leakage in this magnetic flux (flow) outside the pipe wall. a service regulator is required on each service line leak: unintentional escape of gas from the pipeline. service lines. analyze. sion. surized pipeline. hardware. indication: finding of a nondestructive testing technique or low-stress pipeline: pipeline that is operated in its entirety method that deviates from the expected. It also can be generated in situ butane or isobutane). and ethane. as a result of microbiologic activity. data. of hydrogen-induced damage are formation of internal Each piece is called a length. It may or may not at a hoop stress level of 20% or less of the specified be a defect. minimum yield strength of the line pipe. propylene. temperatures. system in which the gas pressure in the mains and incident: unintentional release of gas due to the failure of a service lines is substantially the same as that delivered pipeline. composed predominantly of the following hydrocarbons. or voids in steels. Sensors record status indications of metal loss. propane. The to control the pressure delivered to the customer.. procedural. which can be correlated to metal loss. severity. method utilizing magnetic leakage fields and suitable indi- These tools are also known as intelligent pigs or smart cating materials to disclose surface and near-surface pigs. imperfection: an anomaly with characteristics that do not low-pressure distribution system: gas distribution piping exceed acceptable limits. and high-temperature hydrogen preferred. examining the pipe using a the latitude and longitude of locations using GPS satellites. deformation. to the customer’s appliances.8S-2016 geographic information system (GIS): system of computer integrity: defined herein as the capability of the pipeline to software. cracks (include propa- gating and nonpropagating. These devices run inside the pipe and provide between two poles of a magnet. source of the leak may be holes. characterizing the evaluation by defect type and gouge: mechanically induced metal loss that causes loca. evaluating the indications resulting global positioning system (GPS): system used to identify from the inspections. embrittlement (i. In such a system. discontinuity indications. high-pressure distribution system: gas distribution piping launcher: pipeline facility used to insert a pig into a pres- system that operates at a pressure higher than the stan. and present information that is tied to a to operating pressure) plus the margin of safety estab- geographic location. ASME B31. butylene (including isomers). 39 . in-service pipeline: defined herein as a pipeline that management of change: process that systematically recog- contains natural gas to be transported. in-line inspection (ILI): steel pipeline inspection technique magnetic flux leakage (MFL): an in-line inspection tech- that uses devices known in the industry as intelligent or nique that induces a magnetic field in a pipe wall smart pigs. withstand all anticipated loads (including hoop stress due ulate. and personnel to help manip. a inclusion: nonmetallic phase such as an oxide. This is sometimes called a “joint. LPG can be stored as liquids under moderate pressures [approximately 80 hydrostatic test or hydrotest: a pressure test using water as psig to 250 psig (550 kPa to 1 720 kPa)] at ambient the test medium. blisters. of a technical. pipeline facilities. physical. longitudinal. or service regulator is not required on the individual silicate particle in a metal pipeline.” but “length” is loss of ductility). or organizational nature that can impact system integrity. hydrogen sulfide (H2S): toxic gaseous impurity found in either by themselves or as mixtures: butane (normal some well gas streams. evaluating the results of the exam- inations.. inspection: use of a nondestructive testing technique or method. The gas may or nizes and communicates to the necessary parties changes may not be flowing. F. agent. pressure-regulating stations. made for sale as a validate integrity and detect construction defects and production item. facilities to onshore locations.8S-2016 maximum allowable operating pressure (MAOP): pipeline: all parts of physical facilities through which gas maximum pressure at which a pipeline system may be moves in transportation. fittings. leak or pipeline facility. is set to unity. and fabricated assem- removal. owner. metal movement. or a testing technique. shear-wave ultrasonic. visual. nondestructive examination (NDE) or nondestructive piping and instrumentation diagram (P&ID): drawing testing (NDT): testing method. Pf : an internal pressure that is under normal operating conditions. during the fabrication of auxiliary equipment are not pipe as defined herein. or vehicle that moves through the interior of the pipe. gage pressure). entity currently responsible for the design. pressure: unless otherwise stated. operating stress: stress in a pipe or structural member predicted failure pressure. and is abbreviated as psig pipeline. structure and the electrolyte that is measured with refer- sion of a state.2. along with documented training and/ pipe grade: portion of the material specification for pipe. See the detail explanation with Figure operator or operating company: individual. pressure-limiting Mechanical damage can include denting. pipe-to-soil potential: electric potential difference between the surface of a buried or submerged metallic municipality: city. or other ASME B31G or similar method when the design factor. in which the item is filled line for inspecting. inspection. and acoustic emission. and contact confined to a small area and takes the form of cavities compression-wave ultrasonic. equipment (pipe) is assessed. Such corrosion may be initiated or accelerated by microbial activity. compressor units. facility. such as magnetic flux leakage. showing the piping and instrumentation for a pipeline sonic. magnetic testing. and maintenance of the pipeline facilities. appurte- mechanical damage: type of metal damage in a pipe or pipe nances attached to pipe. pressure is expressed in pounds per square inch (kilopascals) above atmospheric pig: device run inside a pipeline to clean or inspect the pressure (i. or any other political subdivi. and any equipment. including tubing. facilities. sometimes for storage. Cylinders formed from plate probability: likelihood of an event occurring. and gas storage equipment of the closed-pipe type that is fabricated or forged from metal loss: types of anomalies in pipe in which metal has pipe or fabricated from pipe and fittings. or monitored. or drying. and subjected to pressure. called pits. detection. pigging: use of any independent. used to prioritize a defect as immediate. ASME B31. such as radiography. eddy current. or building used in the trans- microbiologically influenced corrosion (MIC): corrosion or portation of gas or in the treatment of gas during the deterioration of metals resulting from the metabolic course of transportation. activity of microorganisms. 40 .e. valves. rights-of-way. principles and risk assessments to determine prevention. relief valves. Included within this definition are gas transmission working of the underlying metal. sure vessels. pres- ASME B31. qualification: demonstration and documented knowledge. or between adjacent block valves. cleaning.8 Code. sealed. (kPa). county. between a compressor station and a mitigation: limitation or reduction of the probability of block valve. puncturing. skills. the duties of a specific job or task. The failure pressure is calculated utilizing corporation. and abilities. pressure relief stations. ultra. metering coating caused by the application of an external force. liquid penetrant.1-1. used primarily for conveying a fluid and defective materials. ence to an electrode in contact with the electrolyte. usually due to corro- sion or gouging. cold blies. 7. and residual and gathering lines. regulators. pipeline section: continuous run of pipe between adjacent compressor stations. metal removal. pressure test: means by which the integrity of a piece of tool. or experience required for personnel to properly perform which includes specified minimum yield strength. partnership. public agency. dimensioning. with a fluid. pipeline facility: new and existing pipelines. been removed from the pipe surface. which transport gas from production stresses. prescriptive integrity management program: integrity management process that follows preset conditions performance-based integrity management program: integ. It is used to pipe: a tubular product. testing. and mitigation actions and their timing. scheduled. that result in fixed inspection and mitigation activities rity management process that utilizes risk management and timelines. operation. operated in accordance with the provisions of the flanges (including bolting and gaskets). pulsation dampeners. occurrence or expected consequence for a particular event. magnetic pitting: localized corrosion of a metal surface that is particle inspection. or to batch fluids. testing. self-contained device. including pipe. construction.. coating stations. The ROW agreement secures smart pig: see in-line inspection tools.. roads. root cause analysis: family of processes implemented to stress level: level of tangential or hoop stress. pure methane or ethane. the operator’s objectives (see section 5). or by permitting authority. The ROW the effective shear strength of the soil is reduced such width can vary with the construction and maintenance that the soil exhibits the properties of a liquid. mission. These processes expressed as a percentage of specified minimum yield all seek to examine a cause-and-effect relationship strength. typically resulting from manufac. (b) measure of the ability of an electrolyte (e. remains to iron and ferrous alloys). Such processes are often used in failure analyses. protection current from its natural path. rail. ROW agreements generally allow the right of ingress soil liquefaction: soil condition. trans- hazards from facility operation are identified. sometimes referred to as a “pig trap. subject matter experts: individuals that have expertise in a specific area of operation or engineering. earthquake. turing or construction processes.g. expressed in units of force per unit area (psi or MPa)... dormant and does not deteriorate with time. the right to pass through property owned by others. percentage of all metal-loss features will be sized. soil) to resist the flow of electric charge (e. and the installation of the facility. welding/fabrication-.” that allows the product to escape to the environment.g. lihood and consequences of potential adverse events are strain: change in length of a material in response to an estimated. mitigating risk by reducing attack of the metal involving an interaction of a local corro- the likelihood. the risk reduction results achieved. resident threat: a manufacturing-.” the risk associated with those threats in terms of incident stress corrosion cracking (SCC): form of environmental likelihood and consequences. fying potential threats to an area or equipment.g. the consequences. minimum yield strength owner. pounds per square inch (MPa). facilities are constructed.g. force.” and “it is recommended” are carbons or components that are heavier than methane and used to indicate that a provision is not mandatory but ethane. that are completed for and dedicated to subsurface risk assessment: systematic process in which potential storage of large quantities of gas for later recovery. by legal action. uniform cross section an ultrasonic sensor detects ultrasound). and measuring sive environment and tensile stresses in the metal. and other similar fixed percentage is stated as the confidence level. The roads. and the like. typically caused by and egress for the operation and maintenance of the dynamic cyclic loading (e. and applied force. or rust: corrosion product consisting of various iron oxides equipment-related imperfection that if not acted upon by a and hydrated iron oxides (this term properly applies only time-dependent or time-independent threat. segment: length of pipeline or part of the system that has resistivity: unique characteristics in a specific geographic location. highways.g. probability (likelihood) of occurrence and the magnitude storage field: geographic field containing a well or wells of the consequences. stress: internal resistance of a body to an external applied risk management: overall program consisting of identi. power lines. (a) resistance per unit length of a substance with sensors: devices that receive a response to a stimulus (e. through the organization and analysis of data. Rich gases decompress in a different fashion than recommended as good practice. Risk assessments can have varying scopes. requirements of the facility’s operator and is usually specified minimum yield strength (SMYS): expressed in determined based on negotiation with the affected land. and end use. Resistivity data are used to design a groundbed for a shielding: preventing or diverting the flow of cathodic cathodic protection system. ASME B31. 41 .. prescribed by the specification under which pipe is risk: measure of potential loss in terms of both the incident purchased from the manufacturer. circular cross section. usually determine the primary cause of an event. waves) where facility.” “should not.. expressed on a unit length basis (e.8S-2016 receiver: pipeline facility used for removing a pig from a rupture: complete failure of any portion of the pipeline pressurized pipeline. sizing accuracy: given by the interval within which a fixed right-of-way (ROW): strip of land on which pipelines. should: “should. or both. resulting in formation and growth of cracks. can be performed at varying levels of detail depending on inches per inch or millimeters per millimeter). cathodic protection shall: “shall” and “shall not” are used to indicate that a current) provision is mandatory. rich gas: gas that contains significant amounts of hydro. seam weld: longitudinal or helical seam in pipe that is residual stress: stress present in an object in the absence of made in the pipe mill for the purpose of making a complete any external loading. assessing It may also be termed “unit stress. the specific edition reference date shown herein.org) transportation of gas: gathering.aga. ASME B31. unless specifically prohibited by this Standard. and provided the user has reviewed the latest edition of temperature: expressed in degrees Fahrenheit (°F) the standard to ensure that the integrity of the pipeline [degrees Celsius (°C)]. If a newer or amended edition tensile stress: applied pulling force divided by the original of a standard is not ANSI approved. 600 North storage field. Milwaukee. this also includes National Standard by the American National Standards damage caused by the operator’s personnel or the opera. Juran’s Quality Handbook (sixth edition.or low-pressure distri. specific editions cited below. Managing System Integrity for or by the application of pressure alone and with or without Hazardous Liquid Pipelines the use of filler material. reaffirmed temperature. *API Std 1163 (second edition.org) 42 . An third-party damage: damage to a gas pipeline facility by an asterisk (*) is used to indicate that the specific edition outside party other than those performing work for the of the standard has been accepted as an American operator. or another Publisher: American Society for Quality (ASQ). December 2010). *ANSI/GPTC-Z380-TR-1 (November 2001). November 2001.8S-2016 submerged arc welding: arc welding process that uses an wrinkle bend: pipe bend produced by field machine or arc or arcs between a bare metal electrode or electrodes controlled process that may result in prominent and the weld pool. transmission. or Carbon Dioxide uprating: qualifying of an existing pipeline or main for a API RP 1162 (second edition.api. Washington. smooth ripples are present. DC 20005 (www. For the purposes of this Code. a large-volume customer. Review of tool: generic term signifying any type of instrumented tool Integrity Management for Natural Gas Transmission or pig. Publisher: American Petroleum Institute (API). Pipelines training: organized program developed to impart the Publisher: Gas Piping Technology Committee (GPTC) of knowledge and skills necessary for qualification. Ultrasonic examination Recommended Practice for the Pressure Testing of is used to determine wall thickness and to detect the Steel Pipelines for the Transportation of Gas. tor’s contractors. inspections. except the user may use the line infrastructure or large portions of that infrastructure latest published edition of ANSI-approved standards that have definable starting and stopping points. Plankinton Avenue.org) mission system or between storage fields. with or without the application of pressure. WI 53203 (www. The arc and molten metal are shielded contour discontinuities on the inner radius. or a storage field to a high. 1220 L Street. April 2013). or distribu- tion of gas by pipeline or the storage of gas. the American Gas Association (AGA).asq. survey: measurements. referenced in this Standard. Public Awareness Programs weld: localized coalescence of metals or nonmetals for Pipeline Operators produced by heating the materials to the welding *API Std 1160 (first edition. Highly Volatile Liquids. February 2013). 2010) bution system. ultrasonic: high-frequency sound. Petroleum Gas. Recommended Practice. The wrinkle is deliberately introduced as a means of short- process is used without pressure and with filler metal ening the inside meridian of the bend. *ANSI/ISO/ASQ Q9004-2009. higher maximum allowable operating pressure. system is not compromised. The following is a list of publications that support or are maged condition of the pipeline. minor. Hazardous Liquids. The references shall be to the system or pipeline system: either the operator’s entire pipe. NW. transmission system: one or more segments of pipeline. the outlet of a gas processing Organization plant. or observations intended to discover and identify events or conditions 14 REFERENCES AND STANDARDS ð16Þ that indicate a departure from normal operation or unda. Washington. *API RP 1110 (sixth edition. 400 North Capitol Street. In-Line welding procedures: detailed methods and practices Inspection Systems Qualification involved in the production of a weldment. flux. Note that this defi- from the electrode and sometimes from a supplemental nition does not apply to a pipeline bend in which incidental source (welding rod. The by a blanket of granular flux on the workpieces. presence of defects.Quality Management usually interconnected to form a network. then the user shall use cross-sectional area. DC 20001 transmission line: segment of pipeline installed in a trans- (www. NW. Institute (ANSI). November 2008). that transports Systems: Managing for the Sustained Success of an gas from a gathering system. or metal granules). 0:2001 (including 2001 Errata). Volume I: Selected Technical Welding Terms and Definitions. Risk-Based Inservice Testing — for High-Consequence Areas Development of Guidelines. September 2006 Gas Transmission Pipelines IPC2006-10299. Soldering.8-2012. 4th GRI-00/0247 (2000). GRI Guide for Locating and Using Pipelines and Piping Systems Pipeline Industry Research NACE SP0169-2007.” B31. DC 20001 (www. October 31. Control of Internal Corrosion in Steel GRI-00/0192 (2000).gastechnology. Arlington. Volume III: Industry Practices Analysis Publisher: Common Ground Alliance (CGA). No.org) GRI-00/0077 (2000). 2008 GRI-00/0246 (2000). Introduction to Smart Pigging in International Pipeline Conference. Volume 1: General GRI-00/0231 (2000). Volume II: Search of Literature Publisher: American Welding Society (AWS). Pipeline Open Data Standard Test Intervals for Pipelines With Stress-Corrosion (PODS) Cracking. IL 60018 Factors (www.1 (1995). 8669 NW 36 Worldwide on Risk Assessment/Risk Management Street. 20 F GRI-00/0189 (2000). 7th International Pipeline Pipeline Incident Conference. Natural Gas Pipeline Risk Boulevard. Including Terms for Terminology Adhesive Bonding.aws.0. Determining the Full Cost of a Proceedings of IPC2008. Detection & Mitigation NACE SP0204-2008. Inc. Standard Management. Safety Performance of Natural Gas Transmission and Gathering Systems Regulated by Integrity Characteristics of Vintage Pipelines (2005) Office of Pipeline Safety Publisher: The INGAA Foundation. Gas Transmission and Distribution GRI-00/0228 (2000). NY 10016-5990 GRI-04/0178 (2004). “Method for Establishing Hydrostatic Re.4 (1995). Review of Pressure Retesting for Pipeline Conference.” GRI-01/0111 (2001). NW. VA 22201 Management. Two Park Avenue. Brazing.ingaa.org) for Loss of Containment Common Ground Alliance. New York. Natural Gas Pipeline Risk 2013 Management. Integrity Management of Stress SMYS as a Precursor to Increasing the Design Stress Corrosion Cracking in Gas Pipeline High Level Consequence Areas. Des Plaines. September 2002 Natural Gas Pipelines IPC2006-10163. GRI-01/0027 (2001). 6th International GRI-01/0083 (2001). 130. Suite 120–172. “Qualification of Procedures for Welding Re-Verification Intervals for High-Consequence Areas Onto In-Service Pipelines. Evaluation of Pipeline Design Mount Prospect Road. Quantifying Pipeline Design at 72% ASME STP-PT-011. Proposed New Guidelines for ASME Safe Parameters for Welding Onto In-Service Pipelines. September 2008 GRI-01/0154 (2001). Cost of Periodically Assuring Piping Systems Pipeline Integrity in High Consequence Areas by In- *ASME B31G-2012. Stress Corrosion Cracking (SCC) Practices Direct Assessment Methodology 43 . GRI-95/0228. Manual for Determining the Line Inspection. (INGAA).org) Areas Associated With Natural Gas Pipelines NACE SP0106-2006. Pressure Testing and Direct Remaining Strength of Corroded Pipelines: Assessment Supplement to ASME B31 Code for Pressure Piping GRI-00/0230 (2000). Schedule of Responses to Corrosion- Conference. September 2006 Caused Metal Loss Revealed by Integrity-Assessment IPC2008-64353.8S-2016 *ASME B31. Thermal GRI-95/0228. Implementation Plan for Periodic IPC2002-27131. “Comparison of Methods for Predicting GRI-01/0084 (2001). Leak Versus Rupture ASME Research Report. 6th International Pipeline GRI-01/0085 (2001).2 (1995). Washington. Volume IV: Identification of Risk (www.” Proceedings of IPC2006. Natural Gas Pipeline Risk Cutting. Direct Assessment and Validation Document (2000) GRI-00/0232 (2000). History of Line Pipe Considerations for Steel Low-Stress Pipelines Manufacturing in North America (1996) GRI-00/0233 (2000).8 on Assessment of Dents and Mechanical Damage Proceedings of IPC2006. “Improved Burnthrough Prediction Results M o d e l f o r I n -S e r v i c e W e l d i n g A p p l i c a t i o n s . Natural Gas Pipeline Risk *AWS A3. Periodic Re-Verification Intervals ASME CRTD-Vol. Effect of Pressure Cycles on Gas (www. Natural Gas Pipeline Integrity Publisher: The American Society of Mechanical Engineers Management Committee Process Overview Report (ASME).” Proceedings of IPC2002.3 (1995). ASME B31. Natural Gas Transmission Pipelines: Underground or Submerged Metallic Piping Systems Pipeline Integrity — Prevention.asme.commongroundalliance. 2200 Wilson GRI-95/0228. Best Practices Version 10. FL 33166 (www. Control of External Corrosion on GRI-00/0193 (2000). Miami. and Thermal Spraying Management. 1700 South GRI-00/0076 (2000). 40-1.org) Pipelines GRI-95/0228. Model for Sizing High Consequence Street.com) Management Methodologies Publisher: Gas Technology Institute (GTI). SE. NY 10005 Subject to 49 CFR 192 (January 2005) (www. Potential Impact Radius Formulae for Flammable Gases Other Than Natural Plant Guidelines for Technical Management of Chemical Gas Subject to 49 CFR 192 (June 2005) Process Safety (revised edition) 1992 TTO Number 14. 3141 Fairview Park Drive. TTO Number 13. Floor 23.8S-2016 NACE SP0206-2006. P.S. Internal Corrosion Direct PR-218-9801 (2001). Suite 525. New York.gov) 44 . Delivery Houston. 15835 Park Ten Place.org) Pipeline Risk Management Manual (third edition.org) Publisher: Pipeline and Hazardous Materials Safety PR-218-08350 (2008). TX 77084 (www.org) (PRCI).Pipeline External Corrosion Direct PR-268-9823 (2004). Publisher: Pipeline Research Council International. Washington. U. Analysis of DOT Reportable Assessment Methodology for Pipelines Carrying Incidents for Gas Transmission and Gathering Normally Dry Natural Gas (DG-ICDA) System Pipelines. Integrity Management Program.nace. Pipeline Facility Incident Data Administration (PHMSA). Houston. Guidelines for the Seismic Design Assessment Methodology and Assessment of Natural Gas and Liquid Publisher: National Association of Corrosion Engineers Hydrocarbon Pipelines (NACE International). ASME B31.dot. Department of Review and Statistical Analysis Transportation. TX 77252 (www.prci.gulfpub.aiche. Box 2608.phmsa. 2004) Publisher: Gulf Publishing Company. Inc. Falls Church. DC 20590 (www. Integrity Management Program. 1985–1997 *NACE SP0502-2010. VA 22042 (www. Derivation of Potential the American Institute of Chemical Engineers (AIChE).com) Order DTRS5602-D-70036. Delivery Publisher: Center for Chemical Process Safety (CCPS) of Order DTRS56-02-D-70036. Impact Radius Formulae for Vapor Cloud Dispersion 120 Wall Street. 1200 New Jersey Avenue.O. alternatively. or conducting direct assessment. provided the inspections tions. as provided each segment and reviewed before a risk assessment can in para. prescribed inspections in this Code. design A-2. the data are used primarily for prior- This Appendix provides process charts and the essen. the first required reassessment of integrity exceed 10 yr This section outlines the integrity management process for pipe operating above 60% SMYS. and 20 yr for pipe operating below 30% SMYS. and construction inspections. such as identifying severe situations requiring have equal or greater rigor than that provided by the more or additional activities. 15 yr specific issues. The interval (a) year of installation between the previous integrity assessment and the (b) coating type next integrity assessment cannot exceed the interval (c) coating condition stated in this Code. A-2. which defines the capability of various ILI (l) diameter devices and provides criteria for running of the tool. The required activities and intervals are not applic. The operator shall consult (k) wall thickness section 6. to establish the condition of Section A-2 provides an integrity management plan to the pipe. as well as the current operating history. 13 yr for pipe oper- for external corrosion in general and also covers some ating above 50% SMYS and at or below 60% SMYS. (m) operating stress level (% SMYS) 45 . A-2. conservative nine categories of threats listed in the main body of this assumptions shall be used when performing the risk Code. the operator must determine address the threat. (d) years with adequate cathodic protection (e) years with questionable cathodic protection A-2. itization of integrity assessment and/or mitigation activ- tials of a prescriptive integrity management plan for the ities. no. rigor than that provided by the prescribed integrity External corrosion is defined in this context to include assessment in this Code.8S-2016 NONMANDATORY APPENDIX A THREAT PROCESS CHARTS AND PRESCRIPTIVE INTEGRITY MANAGEMENT PLANS ð16Þ A-1 INTRODUCTION (n) past hydrostatic test information For this threat.1-1). encounter.3 Criteria and Risk Assessment A-2 EXTERNAL CORROSION THREAT For new pipelines or pipeline segments.2 Gathering. and Integrating Data integrity assessment shall be conducted using a metho- The following minimal data sets should be collected for dology. For this situation. the segment shall be prior- able for severe conditions that the operator may itized higher. or unknown) sure test. (j) leak history (a) In-Line Inspection. of external corrosion (see Figure A-2. galvanic corrosion and microbiologically influenced In no case shall the interval between construction and corrosion (MIC). These data are collected in support of Previous integrity assessments can be considered as performing risk assessment and for special considera. For all pipeline segments older than those stated above. be conducted. the operator may wish to use the original material selection. In those instances.5. performing a pres- (i) MIC detected (yes. and methods of integrity assessment that the construction inspections have an equal or greater and mitigation. Reviewing.1 Scope conditions. within the specified response interval. more rigorous analysis and more frequent inspection may be necessary. A-2. Pipeline incident analysis has identified for pipe operating at or above 30% SMYS and at or below external corrosion among the causes of past incidents. assessment or. such as an MFL tool. ASME B31. Where the operator is missing data. 50% SMYS.4 Integrity Assessment (f) years without cathodic protection The operator has a choice of three integrity assessment (g) soil characteristics methods: in-line inspection with a tool capable of (h) pipe inspection reports (bell hole) detecting wall loss. meeting these requirements. evaluated. 46 . and section 6. critical failure pressure of indications (see ASME B31G which defines how to conduct tests for both post-construc. test pressure. The response is dependent on (c) Direct Assessment. Refer to section 7 for responses to integrity tions. the severity of corrosion as determined by calculating (b) Pressure Test. performs the test.25 times MAOP. repaired. tools.39 times MAOP.8S-2016 ð16Þ Figure A-2. The operator shall consult section 6. If the test pressure was at least 1. which defines the process. or equivalent) and a reasonably anticipated or scientifi- tion and in-service pipelines. The operator shall consult the number of indications examined. the interval shall be 10 yr.1-1 Integrity Management Plan. reviewing. DA. If the test pressure was at A-2. and inspec. and integrating data Criteria and risk assessment Determine Integrity assessment assessment (ILI. section 7). the interval shall be 5 yr (see Responses to integrity assessments are detailed below. Refer to section 7 for appropriate test and he/she or his/her representative responses to integrity assessment. (b) Direct Assessment. The interval is dependent on the inspections. he/she or his/her representative performs the (c) Pressure Testing. hydrotest. The operator selects the appropriate tools and assessment.5 Responses and Mitigation least 1. The operator selects the cally proven rate of corrosion. interval or other) Responses and Other information mitigation to other threats (repair and/or prevent) Performance metrics The operator selects the appropriate tools and he/she or (a) In-Line Inspection. ASME B31. The response is dependent on his/her representative performs the inspection. External Corrosion Threat (Simplified Process: Prescriptive) Gathering. immediate and scheduled rigor than that provided by the prescribed integrity (d) number of external corrosion leaks (for low-stress assessments in this Code. a leak on the flow velocity and especially periods where there is no segment that may be caused by external corrosion flow) should necessitate immediate reassessment. Where the operator is missing data. liquid. In no case may the interval between construction and the first required reassessment of integrity exceed 10 yr A-3 INTERNAL CORROSION THREAT for pipe operating above 60% SMYS. (f) past hydrostatic test information The interval for assessments is dependent on the (g) gas. the operator must determine (c) number of repair actions taken due to direct assess. design external corrosion conditions. sulfide. For this threat. A-2. Pipeline incident analysis methods as outlined in section 7. of internal corrosion. the operator (a) number of hydrostatic test failures caused by may wish to use the original material selection. 47 . A-3. the operator may each segment and reviewed before a risk assessment can discover other data that should be used when performing be conducted.5. practices as outlined in section 7. A-3. This data are collected in support of risk assessments for other threats. third-party damage. etc. (b) pipe inspection reports (bell hole) party damage threat.) becomes available and that may require more frequent (j) operating parameters (particularly pressure and integrity assessments. that the construction inspections have an equal or greater ment results. and 15 yr for pipe operating at or below 50% SMYS. ities.7 Assessment Interval (e) diameter The operator is required to assess integrity periodically. immediate and scheduled the pipe. For example. management process for internal corrosion in general and The operator shall select the appropriate repair also covers some specific issues. probes. and methods of integrity assessment integrity assessment shall be conducted using a metho- and mitigation. Section A-3 provides an integrity management plan to For all pipeline segments older than those stated above. has identified internal corrosion among the causes of past The operator shall select the appropriate prevention incidents. A-3. The operator (h) bacteria culture test results must incorporate new data into the assessment as data (i) corrosion detection devices (coupons. as provided defined in this context to include chemical corrosion and in para. Internal corrosion is dology within the specified response interval. and Integrating Data A-2. address the threat. For this situation. dents may be detected tions. In addition. see factors shown above can be applied to the actual operating Figure A-3. and construction inspections. such as identifying severe situations requiring on the top half of the pipe. 13 yr for pipe oper- A-3. (k) operating stress level (% SMYS) Changes to the segment may also require reassessment. Reviewing. oxygen. (a) year of installation mation when conducting risk assessment for the third. For example. the internal microbiologically influenced corrosion (MIC.3 Criteria and Risk Assessment lish the effectiveness of the program and for confirmation of the integrity assessment interval: For new pipelines or pipeline segments. The following performance measures shall be docu- mented for the external corrosion threat. conservative assumptions shall be used when performing the risk A-2.8 Performance Measures assessment or. It is appropriate then to use this infor. free water. in order to estab. when performing risk assessment and for special considera- conducting an ILI with an MFL tool. to establish the condition of inspection results. the segment shall be prior- itized higher.1 Scope ating above 50% SMYS and at or below 60% SMYS. carbon dioxide. This may have been caused by more or additional activities. the data are used primarily for prior- Change management is addressed in this Code in section itization of integrity assessment and/or mitigation activ- 11. pressure in lieu of MAOP for ensuring integrity at the Section A-3 provides a general overview of the integrity reduced pressure only. or solid analysis (particularly hydrogen responses taken as outlined in para. the operator pipelines it may be beneficial to compile leaks by leak shall determine that a corrosive environment does not classification) exist.1-1). ASME B31.6 Other Data The following minimal data sets should be collected for During the inspection activities. alternatively.5.2 Gathering. as well as the (b) number of repair actions taken due to in-line current operating history. (c) leak history (d) wall thickness A-2.8S-2016 If the actual operating pressure is less than MAOP. and chlorides) These intervals are maximum intervals. such as an MFL tool. which defines the process. or conducting direct assessment. reviewing. inspections. The operator shall consult section 6. The operator selects the stated in this Code. between the previous integrity assessment and the which defines how to conduct tests for both post-construc- next integrity assessment cannot exceed the interval tion and in-service pipelines. prescribed inspections in this Code. hydrotest. appropriate test and he/she or his/her representative performs the test. and inspec- methods: in-line inspection with a tool capable of tions. provided the inspections priate tools and he/she or his/her representative have equal or greater rigor than that provided by the performs the inspection. The operator shall consult The operator has a choice of three integrity assessment section 6. tools. DA. ASME B31. interval or other) Responses and Other information mitigation to other threats Performance metrics Previous integrity assessments can be considered as for running of the tool. The interval (b) Pressure Test. A-3. and integrating data Criteria and risk assessment Determine Integrity assessment assessment (ILI. performing a pres. Internal Corrosion Threat (Simplified Process: Prescriptive) Gathering. which defines the capability of various ILI devices and provides criteria Responses to integrity assessments are detailed below.4 Integrity Assessment (c) Direct Assessment. The operator selects the appro- meeting these requirements. The operator selects the appropriate tools and detecting wall loss. 48 . (a) In-Line Inspection. the A-3.5 Responses and Mitigation operator must consult section 6. he/she or his/her representative performs the sure test. For in-line inspection.8S-2016 ð16Þ Figure A-3.1-1 Integrity Management Plan. when literature. An acceptable method to address dry gas inspection results. (c) number of repair actions taken due to direct assess- (c) Pressure Testing. The response is dependent on (a) number of hydrostatic test failures caused by the number of indications examined. the interval is 10 yr. Integrity assessment and mitigation plans discover other data that should be used when performing for both phenomena are discussed in published research risk assessments for other threats. the interval is 5 yr (see grade) section 7). the extent and severity of the threat. immediate and scheduled internal corrosion is NACE SP0206. that may be caused by internal corrosion would necessi. and Integrating Data The interval for assessment is dependent on the responses taken. Data suggesting that a corrosive examination and testing strategies. that can be used to select an integrity assessment method or to customize one of the methods for a specific pipeline.2 Gathering. it may be beneficial to compile leaks by leak was at least 1. The following minimal data sets should be collected for These intervals are maximum intervals. a leak on the segment situations requiring more or additional activities. The operator each segment and reviewed before a threat assessment shall incorporate new data into the assessment as data can be conducted. The operator is required to assess integrity periodically. and internal corrosion repaired. for stress corrosion cracking (SCC) of gas The operator shall select the appropriate prevention line pipe. ASME B31. dents may be means of inspecting for mitigation of SCC.1 Scope integrity at the reduced pressure only. to identify and select mentation should occur. and SCC direct assessment a corrosive environment exists should prompt the (SCCDA). Refer to section 7 for responses to integrity (b) number of repair actions taken due to in-line assessment. (b) operating stress level (% SMYS) (c) operating temperature 49 . This change management is addressed in section 11. ASME STP-PT-011. has been assessed for SCC. Methods of assessment include hydrostatic practices as outlined in section 7. then the operator should identify description of a process utilizing Engineering Assessment the conditions that would prompt reevaluation. This section does not address all possible conducting an ILI with an MFL tool. and methods of integrity assessment methods as outlined in section 7. A-3. It is appropriate and be available for use by the operator. As new tools called out on the top half of the pipe. Integrity Management of Stress Corrosion Cracking in Gas Pipeline High Consequence A-3.8 Performance Metrics the severity of corrosion.8S-2016 (a) In-Line Inspection.6 Other Data This process is applicable to both near-neutral pH and During the inspection activities. (a) age of pipe tate immediate reassessment. in-line inspection.25 times MAOP. Section A-4 provides an integrity management plan to The operator shall select the appropriate repair address the threat. Additionally. as determined by calculating critical failure pressure of indications (see ASME B31G The following performance metrics shall be docu- or equivalent) and a reasonably anticipated or scientifi. mented for the internal corrosion threat. these data are collected becomes available. This may have and technologies are developed.7 Assessment Interval Areas. The interval is dependent on the ment results. Additional then to use this data when conducting integrity assess. evaluated. NOTE: Age of pipe coating may be used if the pipeline segment Changes to the segment may also drive reassessment.5. If the test pressure was at least (d) number of internal corrosion leaks (for low-stress 1. Data confirming that testing. as outlined in A-3. in order to estab- cally proven rate of corrosion. of the integrity assessment interval: (b) Direct Assessment. and/or to develop environment may exist should prompt an immediate technically defensible plans that demonstrate satisfactory reevaluation. Included in this section is a or environment exists. immediate and scheduled hydrostatic test pressure. they can be evaluated been caused by third-party damage. If the data shows that no corrosive condition pipeline safety performance. Engineering Assessment can be used to evaluate design of a mitigation plan of action and immediate imple. Refer to section 7 for lish the effectiveness of the program and for confirmation responses to integrity assessments. such as identifying severe integrity assessments. the A-4 STRESS CORROSION CRACKING THREAT factors shown above can be applied to the actual operating pressure in lieu of MAOP for the purposes of ensuring A-4. The response is dependent on A-3. For example. and that may require more frequent for special considerations. A-4. If the actual operating pressure is less than MAOP. For example.39 times MAOP. If the test pressure pipelines. guidance for management of SCC can be found in ment for the third-party damage threat. Reviewing. the operator may high pH SCC. and mitigation. Each If the pipeline experiences an in-service leak or rupture segment should be assessed for the possible threat of that is attributed to SCC. (51 mm) maximum length and depth less than <30% WT 1 Predicted failure pressure >110% SMYS Exceeds 10 yr 2 110% SMYS ≥ predicted failure pressure >125% MAOP Exceeds 5 yr 3 125% MAOP ≥ predicted failure pressure >110% MAOP Exceeds 2 yr 4 Predicted failure pressure ≤110% MAOP Less than 2 yr (d) distance of the segment downstream from a not met and if the segment does not have a history of SCC.1-1.4-1 SCC Crack Severity Criteria Category Crack Severity Remaining Life 0 Crack of any length having depth <10% WT. segment in which one or more service incidents or one exothermically welded attachments. using widely accepted fracture mechanics should be assessed for the possible threat of high pH SCC if analysis methods. hydrotest failures caused by SCC.4 Integrity Assessment Where the operator is missing data.3 Criteria and Threat Assessment are at risk for SCC. give consideration to integrity assessment for other threats and prioritization among other segments that A-4. in- service failures caused by SCC. A documented hydrostatic retest program (a) operating stress level >60% SMYS shall be developed for this segment. has been assessed for SCC. The values in Table A-4.3). Note that hydrostatic (b) age of pipe >10 yr pressure testing is required. A-4.3 Additional Considerations.1 through A-4.2 Possible Threat of High pH SCC.g. encroachments. if one of the conditions of the criteria is 50 . Coating For this threat.3. the threat assessment consists of condition should be assessed and documented. A-4.4-1 have been devel- susceptibility using the criteria in this section. Any indications of SCC shall be addressed SCC history (i. All SCC comparing the data elements to the criteria. Several alternative fracture mechanics used during field coating application). remove soil from the top portion of the pipe) are not unless the conditions that led to the SCC have been subject to the MPI requirement as described unless corrected. and foreign line or more hydrostatic test breaks or leaks has been crossings where the operator may need only to caused by one of the two types of SCC shall be evaluated.4. In addition. Magnetic particle inspection methods (MPI).8S-2016 ð16Þ Table A-4. there is a prior history of SCC in the segment.3.3. meet the criteria in assumptions shall be used when performing the risk para. presence of SCC.e. Acceptable inspection and mitigation methods for addressing pipe segments at risk for SCC are covered (c) all corrosion coating systems other than plant- in paras. the three criteria in para. Use of test media other than NOTE: Age of pipe coating may be used if the pipeline segment water is not permitted. A-4. A-4. the particular segment shall be near-neutral pH SCC if all of the following criteria are subjected to a hydrostatic test (as described below) within present: 12 months. each pipe is not completely exposed (e. a written inspection.4-1 and A-4.. (a) operating temperature >100°F (38°C) or other equivalent nondestructive evaluation methods.4. Excavations where the A-4. or leaks caused by SCC). the segment shall be prioritized evaluation plan shall be prepared. oped for typical pipeline attributes and representative SCC A-4. conservative If conditions for SCC are present (i.4. the pipe is considered to be at risk for the occurrence of SCC. examination. Field joint approaches exist for operators to use for crack severity coating systems should also be considered for their assessment. Otherwise. alternatively.1 Possible Threat of Near-Neutral pH SCC.1 Bell Hole Examination and Evaluation following two criteria are also present: Method.1 are present and the A-4.e. Each segment growth rates. compressor station no action is required.4-1. ASME B31. applied or field-applied fusion bonded epoxy (FBE) or The severity of SCC indications is characterized by Table liquid epoxy (when abrasive surface preparation was A-4. or crack with Exceeds 15 yr 2 in..4.4. (b) distance from compressor station discharge ≤20 mi shall be used when disbonded coating or bare pipe is (32 km) encountered during integrity-related excavation of pipe- line segments susceptible to SCC. and analysis or. bell hole inspection indicating the using guidance from Tables A-4.. The plan should higher. If the condi- inspection activities shall be conducted using documented tions of the criteria are met or if the segment has a previous procedures.3. (e) coating type (f) past hydrotest information A-4. the operator During the integrity assessment and mitigation activ- shall use one of the following two options to address ities. ILI. an engineering critical assessment may ence has indicated some successful use of in-line inspec- be conducted to evaluate the threat. critical-sized flaws while minimizing growth of subcri- tical-sized flaws. or MPI completed. gathering and analyzing data for pipe having similar (b) Target test pressure shall be maintained for a operational characteristics and residing in a similar minimum period of 10 min. or equivalent. These data should be (-a) Implement a written hydrostatic retest used where appropriate for performing risk assessments program with a technically justifiable interval.4. A-4. Stress Corrosion than SCC. Detailed guidance for this ered for hydrostatic test failure events due to causes other process is provided in NACE SP0204. SCC integrity assessment.2 for appropriate response to indications of SCC identified by A-4. 7. examination The response requirements applicable to the SCC crack 10163.8S-2016 ð16Þ Table A-4. or 100% MPI examination. the operator may discover other data that may long-term mitigation of SCC: be pertinent to other threats. within 2 yr.4-1 can be used to establish a testing conditions for SCC mitigation have been developed reassessment interval for ILI. Table A-4.5 Other Data leaks or ruptures due to SCC occurred. ILI. If no A-4. a flame ionization conduct excavations for the purposes of conducting an survey) shall be performed. A single excavation for SCC is adequate. 3. Category 1 Conduct a minimum of two additional excavations. physical environment. The type and timing of further assessment(s) depend on the results of hydrotest. or equivalent. primarily follows: by examining with MPI or equivalent technology selected (a) High-point test pressure equivalent to a minimum joints of pipe within that segment after systematically of 100% SMYS. SCCDA is a formal process to assess a pipe SCC. Category 2 Consider temporary pressure reduction until hydrotest. an guidance for operators to select appropriate sites to instrumented leak survey (e. A-4. ASME B31. Refer to para.. tion (ILI) for SCC in gas pipelines. or equivalent. ILI. response requirements in Table A-4. (Alternatives may be consid.4. Hydrostatic testing utilizing the criteria A-4. If a leak or The following performance measures shall be docu- rupture due to SCC occurred. Assess the segment using hydrotest. Hydrostatic in-line inspection.1-1.1-1 Actions Following Discovery of SCC During Excavation Crack Severity Response Requirement No SCC or Category 0 Schedule SCCDA as appropriate. the operator shall establish a mented for the SCC threat. Method for Establishing Hydrostatic Re-Test severity categories are provided in Table A-4.3 In-Line Inspection for SCC.4 Stress Corrosion Cracking Direct Assessment in this section is considered an integrity assessment for (SCCDA). (-b) Perform engineering assessment to evaluate the threat and identify further mitigation methods.6 Performance Measures (2) SCC Hydrostatic Test Leak or Rupture. An example of an inspection interval: SCC hydrostatic retest approach is found in IPC2006- (a) number of in-service leaks/failures due to SCC 51 . in order to establish the effec- written hydrostatic retest program and procedure with tiveness of the program and for confirmation of the justification for the retest interval. If the largest flaw is Category 1. The SCCDA process includes (c) Upon returning the pipeline to gas service.4. The Intervals for Pipelines With Stress Corrosion Cracking. (d) Results (1) No SCC Hydrostatic Test Leak or Rupture. conduct next assessment in 3 yr. provided that the entire through industry research to optimize the removal of segment has been inspected. Recommended hydrostatic test criteria are as segment for the presence and severity of SCC. examination Category 4 Immediate pressure reduction and assessment of the segment using one of the following: (a) hydrostatic test (b) ILI (c) 100% MPI.2.g. Category 3 Immediate pressure reduction and assessment of the segment using one of the following: (a) hydrostatic test (b) ILI (c) 100% MPI.1-1 incorporate conservative assumptions regarding remaining flaw sizes. or MPI. follow the response requirement applicable to that category. or 4. for other threats. If the largest flaw is Category 2.2 Hydrostatic Testing for SCC.4. Industry experi- Alternatively.) Cracking (SCC) Direct Assessment Methodology.4.4. (a) pipe material (b) year of installation 52 .1-1).8S-2016 ð16Þ Figure A-5. for manufacturing concerns. and methods of integrity assessment be conducted. Reviewing. Manufacturing Threat (Pipe Seam and Pipe. and Integrating Data A-5. These data are collected for performing risk and mitigation.2 Gathering.1 Scope The following minimal data sets should be collected for Section A-5 provides an integrity management plan to each segment and reviewed before a risk assessment can address the threat. Simplified Process: Prescriptive) (b) number of repairs or replacements due to SCC This section outlines the integrity management process (c) number of hydrostatic test failures due to SCC for manufacturing concerns in general and also covers some specific issues. PIPE) A-5. assessment and for special considerations such as iden- Manufacturing is defined in this context as pipe seam tifying severe situations requiring more or additional and pipe (see Figure A-5. Pipeline incident analysis has iden- A-5 MANUFACTURING THREAT (PIPE SEAM AND tified manufacturing among the causes of past incidents.1-1 Integrity Management Plan. ASME B31. activities. a pipeline movement moni. steel pipe manufactured prior to 1952. COUPLING) A-5. fabrication weld. Effects of Pressure Cycles FABRICATION WELD. This data are collected to support ment of pipe or stabilization of pipe. the operator may refer to discover other data that should be used when performing History of Line Pipe Manufacturing in North America by J. During the inspection activities. a pipeline or when raising the operating pressure above wrinkle bend or buckle. see note below) must be replaced. seam types may be more susceptible to accelerated corro- sion. ASME. broken pipe. the segment shall be prior. and methods of integrity assessment land movement or subject to removal of support. if the pipeline segment operates with significant pressure fluctuations.8 defines how to construction among the causes of past incidents. management is addressed in section 11. Reviewing. conservative meets or exceeds the requirements of ASME B31. recorded in the past 5 yr). If land movement is observed or conditions. The following performance measures shall be docu- welded pipe. the operator should develop (f) operating pressure history pipe specifications to be used when ordering pipe that Where the operator is missing data. seam fatigue shall A-6 CONSTRUCTION THREAT (PIPE GIRTH WELD. 1996.5 Responses and Mitigation each segment and reviewed before a risk assessment can For cast iron pipe. A-5.8 Performance Measures If the pipe has a joint factor of less than 1.8.3 Criteria and Risk Assessment conducting risk assessments for external or internal corrosion. ASME B31. a manufacturing threat the inspection interval: is considered to exist. when raising the MAOP of defined in this context as pipe girth weld. examination of the the pipeline’s operating pressure. to at least specific issues. assumptions shall be used when performing the risk assessment or. ASME B31. or pipelines A-5. in order to establish or if the pipeline is composed of low-frequency-welded the effectiveness of the program and for confirmation of ERW pipe or flash-welded pipe.25 times the MAOP. the assessment should include Section A-6 provides an integrity management plan to evaluation as to whether or not the pipe is subject to address the threat. and also covers some shall be in accordance with ASME B31.6 Other Data itized higher. B. (a) number of hydrostatic test failures caused by Fatigue along longitudinal pipe seams due to operating manufacturing defects pressure cycles has not been a significant issue for natural (b) number of leaks due to manufacturing defects gas pipelines. alternatively. and Integrating Data The following minimal data sets should be collected for A-5.4 Integrity Assessment A-6. performing risk assessment and for special 53 . STRIPPED THREADS/BROKEN PIPE/ fatigue due to pressure cycling. be conducted. or changes in operating terrain is required. and mitigation. For this threat. for construction concerns. such as significant pressure cycling. be considered by the operator as an additional integrity threat.2 Gathering. A-5. where low temperatures are experienced or where the pipe is Periodic integrity assessment is not required.7 Assessment Interval joined by means of acetylene girth welds. and butt-welded pipe) mented for the manufacturing threat. Pipeline incident analysis has identified 1. any section that fails the pressure test alternative. pressure testing must be This section outlines the integrity management process performed to address the seam issue. F.8.1-1).1 Scope For cast iron pipe.8S-2016 (c) manufacturing process (age of manufacture as For steel pipe. WRINKLE BEND OR on Gas Pipelines. risk assessments for other threats. Clark. stripped threads.0 (such as lap. such as uprating removal of supporting backfill. toring program should be established and appropriate intervention activities undertaken. hammer-welded pipe. GRI Report GRI-04/0178. Change can reasonably be anticipated. conduct tests for both post-construction and in-service pipelines. For example. A-6. Pressure testing for construction concerns in general. certain Kiefner and E. It is appropriate to use this information when A-5. For cast iron pipe. Changes exposed to movement such as land movement or to the segment may drive reassessment. may be a useful reference regarding BUCKLE. mitigation options include replace. However. Construction is For steel pipe seam concerns. mechanically coupled pipelines. (d) seam type The operator shall select the appropriate prevention (e) joint factor practices. or the historical operating pressure (highest pressure coupling (see Figure A-6. the operator may NOTE: When pipe data is unknown. 8S-2016 Figure A-6. alternatively. (k) soil properties and depth of cover for wrinkle bends (l) maximum temperature ranges for wrinkle bends (m) bend radii and degrees of angle change for wrinkle bends 54 . requiring more or additional activities. (f) post-construction girth weld reinforcement (g) NDT information on welds A-6. the segment shall be prior- (e) welding procedures itized higher. Fabrication Weld. Stripped Threads/Broken Pipe/Coupling. such as identifying severe situations (n) operating pressure history and expected operation. including significant pressure cycling and fatigue (a) pipe material mechanism (b) wrinkle bend identification Where the operator is missing data. a review of the welding procedures and (i) pipe inspection reports (bell hole) NDT information is required to ascertain that the welds (j) potential for outside forces (see section A-10) are adequate.1-1 Integrity Management Plan. Wrinkle Bend or ð16Þ Buckle. ASME B31.3 Criteria and Risk Assessment (h) hydrostatic test information For girth welds. conservative (c) coupling identification assumptions shall be used when performing the risk (d) post-construction coupling reinforcement assessment or. Construction Threat (Pipe Girth Weld. Simplified Process: Prescriptive) considerations. 8S-2016 For fabrication welds. the operator may tolerances) discover other data that should be used when performing (f) relief set point drift risk assessments for other threats. assessment or. Equipment is defined in this context as pipeline facilities other than A-6. Pipeline incident analysis has identified pressure control and relief equipment. depth of cover. (c) number of wrinkle bends removed degree of bend. Periodic assessment is not required.8 Performance Measures dures and NDT information.2 Gathering. The data must be integrated and evaluated Section A-7 provides an integrity management plan to to determine where these construction characteristics address the threat. (a) year of installation of failed equipment nance reasons occurs. reviewing (g) O-ring failure information the hydrostatic test information might reveal previous (h) seal/packing information failures due to pipe seam defects. the segment shall be prior- A-6. as well as a review of forces due to ground settlement or other outside loads.1 Scope an event. when the need to inspect the pipeline for other mainte. replacement. the effectiveness of the program: reports of visual inspection should be reviewed to ascer. A-6. A-7 EQUIPMENT THREAT (GASKETS AND O- The existence of these construction-related threats RINGS. SEAL/PUMP alone does not pose an integrity issue. conservative use this information when conducting risk assessments assumptions shall be used when performing the risk for manufacturing threats. the operator should develop excavation protocols to ensure the pipe is not moved The following minimal data sets should be collected for and additional stresses introduced. Changes to the segment or changes in land use may drive reassessment. In addition. Meter/regulator and For construction threats. For this threat. For example. examination.6 Other Data (d) flange gasket failure information (e) regulator set point drift (outside of manufacturer’s During the inspection activities. (b) regulator valve failure information (c) relief valve failure information ð16Þ A-6. alternatively. and mitigation. The operator shall select the appropriate prevention A-7. or reinforcement more or additional activities. It is appropriate to Where the operator is missing data. (d) number of wrinkle bend inspections These are important factors in determining whether or (e) number of fabrication welds repaired/removed not bends are being subjected to injurious stresses or strains. The presence of PACKING) these threats in conjunction with the potential for outside forces significantly increases the likelihood of A-7. issues.5 Responses and Mitigation seal/pump packing among the causes of past incidents.7 Assessment Interval itized higher. CONTROL/RELIEF. for pipeline equipment failure. Reviewing. and methods of integrity assessment coexist with external or outside force potential. 55 .4 Integrity Assessment pipe and pipe components. the inspection should be by compressor stations are typical equipment locations data integration. Information relative to pipe movement should removed be reviewed. ASME B31. a review of the welding proce. threats that are coincident with the potential for This section outlines the integrity management process ground movement or outside forces that will impact for equipment in general and also covers some specific the pipe. Potential movement of the defects pipeline may cause additional lateral and/or axial (b) number of girth welds/couplings reinforced/ stresses. the each segment and reviewed before a risk assessment can operator should conduct examinations and evaluations be conducted. bend radius.1-1). such as identifying severe situations requiring require inspection. in order to establish For wrinkle bends and buckles as well as couplings. and Integrating Data practices. gaskets and O-rings. repair. and A-6. These data are collected in support of every time the pipe is exposed. (a) number of leaks or failures due to construction tain their continued integrity. Potential threats performing risk assessment and for special considera- should be mitigated by proactive procedures that tions. and soil properties. The following performance measures shall be docu- is required to ascertain that the welds are adequate. Change management is addressed in section 11. mented for the construction threat. and evaluation for (see Figure A-7. such as temperature range. ð16Þ Simplified Process: Prescriptive) A-7. Seal/Pump Packing.4 Integrity Assessment During the inspection activities. Certain gasket types are prone to premature degrada. the operator may The inspections for this threat are normally conducted discover other data that should be used when performing per the requirements of the O&M procedures. it is discov- of equipment shall be performed and what specific ered that there has been a lightning strike.6 Other Data A-7. These equipment types may require A-7.3 Criteria and Risk Assessment tions may be necessary if the equipment has a leak and failure history. Control/Relief. 56 .5 Responses and Mitigation extra scrutiny. For example. It is appropriate action is required. These equipment types may require more-frequent required. These risk assessments for other threats. Certain relief and regulator valves are known to have their set points drift.8S-2016 Figure A-7. A-7. ASME B31. to use this information when conducting risk assessments for the weather-related and outside force threat. Equipment Threat (Gasket and O-Ring.1-1 Integrity Management Plan. Replacement or repair of the equipment may be tion. when procedures detail when inspections and maintenance inspecting gaskets at aboveground facilities. Additional or more frequent inspec. leak checks. 7 Assessment Interval (d) number of leaks due to equipment failures The interval for assessment is contained within the operation and maintenance procedure for the specific A-8 THIRD-PARTY DAMAGE THREAT [THIRD- types of equipment. vandalism. A-8. Simplified Process: Prescriptive] A-7. for third-party damage. ASME B31. (b) number of relief valve failures (c) number of gasket or O-ring failures 57 . PARTY INFLICTED DAMAGE (IMMEDIATE). ð16Þ Vandalism. PREVIOUSLY DAMAGED PIPE] change management is addressed in section 11. Changes to the segment may drive reassessment. and (a) number of regulator valve failures previously damaged pipe (see Figure A-8.8 Performance Measures Section A-8 provides an integrity management plan to The following performance measures shall be docu. and methods of integrity assessment mented for the equipment threat.1-1). address the threat. This VANDALISM.1 Scope A-7. Third-Party Damage Threat [Third-Party Inflicted Damage (Immediate). in order to establish and mitigation.8S-2016 Figure A-8. Third-party the effectiveness of the program and for confirmation damage is defined in this context as third-party inflicted of the inspection interval: damage with immediate failure. Previously Damaged Pipe.1-1 Integrity Management Plan. the fact that the defect was revealed indirectly even This section outlines the integrity management process though it may have been adequately described by a for incorrect operations in general and also covers some previous inspection such as an in-line inspection. and Integrating Data excavation activities revealed by one-call records or other encroachment records. each segment and reviewed before a risk assessment can For example. for incorrect operations. Pipeline incident analysis has identified third-party damage among the causes of past incidents. and Integrating Data operator may discover other data that should be used The following minimal data sets should be collected for when performing risk assessments for other threats. indications discovered by inspections that cannot be directly interpreted. Deficiencies in these areas damage require mitigation as outlined below. more or additional activities.5 Responses and Mitigation be conducted. These data are collected in support of exposed pipe may indicate active external corrosion. in the case of incidents involving procedures or failure to follow a procedure (see Figure previously damaged pipe. ASME B31. A-8.1-1). such as agricultural lands with shallow depth of cover. and methods of integrity assessment accomplished during patrols and leak surveys conducted and mitigation. when monitoring an encroachment.6 Other Data During the inspection and examination activities. Changes to the (c) leak reports resulting from immediate damage segment may drive reassessment. (a) vandalism incidents A-8. be conducted. specific issues.4 Integrity Assessment Section A-9 provides an integrity management plan to Observance of encroachments or third-party damage is address the threat.1 Scope A-8. tions. the operator should investigate suspicious incorrect operations among the causes of past incidents.7 Assessment Interval (b) pipe inspection reports (bell hole) where the pipe Assessment shall be performed periodically. such as identifying severe situations requiring actions or repair of damage found as a result of inspec- more or additional activities.8S-2016 This section outlines the integrity management process tion activities may be warranted as provided in section 7.2 Gathering. is appropriate to use this information when conducting tions. it is frequently found after A-9.8 Performance Measures (f) one-call records (g) encroachment records The following performance measures shall be docu- mented for the third-party threat in order to establish A-8. These data are collected in support of performing risk assessment and for special considera- Mitigation of third-party damage is through preventive tions. examinations. the A-8. for third-party damage in general and also covers some such as development of a damage prevention plan. party damage prior to a leak or failure Specific land uses. (e) in-line inspection results for dents and gouges at top half of pipe A-8.2 Gathering. may be more susceptible to A-9 INCORRECT OPERATIONS THREAT third-party damage.3 Criteria and Risk Assessment the effectiveness of the program and for confirmation of the inspection interval: Review of data may show susceptibility to certain types (a) number of leaks or failures caused by third-party of third-party inflicted damage. especially in areas of concern. The operator (a) procedure review information shall ensure that third-party damage prevention (b) audit information programs are in place and functioning. such as identifying severe situations requiring risk assessments for external corrosion. but may be correlated with known A-9. even with the damaged pipe absence of any of these indicators. Reviewing. or tests performed. It performing risk assessment and for special considera. specific issues. Change management (d) incidents involving previous damage is addressed in section 11. Because third-party (b) number of leaks or failures caused by previously damage is a time-independent threat. Reviewing. A-9. It is recom- has been hit mended that it be performed annually. third-party damage (c) number of leaks or failures caused by vandalism can occur at any time and strong prevention measures (d) number of repairs implemented as a result of third- are necessary. However. The following minimal data sets should be collected for each segment and reviewed before a risk assessment can A-8. Incorrect opera- as required by the operations and maintenance proce- tions are defined in this context as incorrect operating dures. Additional preven- 58 . Pipeline incident analysis has identified Therefore. ASME B31. This program should include initial qualification required. the procedures are correct. by recognized organizations may be included in this program. Incorrect Operations Threat (Simplified Process: Prescriptive) (c) failures caused by incorrect operation A-9.3 Criteria and Risk Assessment Mitigation in this instance is prevention. Deficiencies in these areas require mitigation and periodic reassessment of qualification. ongoing basis. no additional assessment is perform.4 Integrity Assessment In addition. These inspections are conducted by company personnel and/or by third-party experts. and that operating The operator should have a program to qualify opera- personnel are adequately qualified to fulfill the require.1-1 Integrity Management Plan. The operator shall ensure that procedures are current. and that the following of proce- performed in accordance with operation and maintenance dures is enforced.5 Responses and Mitigation A-9. tion and maintenance personnel for each activity that they ments of the procedure. the personnel If the data shows the operation and maintenance are are adequately qualified. procedures. 59 . Certification as outlined below. A-9. a strong internal review or audit program The audits and reviews are normally conducted on an by in-house experts or third-party experts is necessary.8S-2016 ð16Þ Figure A-9. (e) depth of frost line (f) year of installation A-9. in order to Where the operator is missing data. (b) number of audits/reviews conducted (c) number of findings per audit/review. These data are collected in support of reviewing records required by procedures. and methods of integrity assessment (g) where the soil is subject to liquefaction and mitigation. floods. not to exceed 100% SMYS) mented for the incorrect operations threat. integrity Pipeline incident analysis has identified weather.. assumptions shall be used when performing the risk mation of the inspection interval: assessment or. and Integrating Data During the inspection activities. (d) profile of ground acceleration near fault zones dures and additional training of personnel. or similar methodologies may be used.8S-2016 A-9. the threat shall be evaluated. for weather-related and outside force (h) where ground acceleration exceeds 0. and related and outside force damage among the causes of evaluations.6 Other Data A-10. At locations where facilities are prone to light- and also covers some specific issues. the segment shall be prior- (a) number of leaks or failures caused by incorrect itized in a higher category based on the expected worst operations case of the missing data.1 Scope (e) where blasting near the pipeline is occurring Section A-10 provides an integrity management plan to (f) when the pipe is at or above the frost line address the threat. Additional or more-frequent inspections may be necessary. It is appropriate to use this information more or additional activities. diameter. Reviewing. soil liquefactions Assessment shall be performed periodically and is susceptibility) recommended to be performed annually. COLD WEATHER. assessments. LIGHTNING) (d) where the pipeline is subject to extreme surface loads that cause settlement to underlying soils A-10. when conducting risk assessments for third-party (a) joint method (mechanical coupling. total stress The following performance measures shall be docu.2g acceleration) management is addressed in section 11. arc weld) (b) topography and soil conditions (unstable slopes. water proximity. are normally conducted per the requirements past incidents. depending on leak and failure information. or where the river bottom is moving OR FLOODS. when be conducted. it is discovered performing risk assessment and for special considera- that there have been several unreported encroachments tions. equipment) This section outlines the integrity management process At locations meeting any of the above.1-1). alternatively. heavy rains or structures or between structures (e.2g concerns. For seismic threats. such as identifying severe situations requiring by third parties. acetylene weld. classified by A-10. evaluated.8 Performance Measures (g) pipe grade. cold weather. HEAVY RAINS water. including inspections. of the O&M procedures. buildings. A-9. and wall thickness (internal stress calculation added to external loading. damage.3 Criteria and Risk Assessment ð16Þ severity (d) number of changes to procedures due to audits/ Pipe may be susceptible to extreme loading at the reviews following locations: (a) where the pipeline crosses a fault line (b) where the pipeline traverses steep slopes A-10 WEATHER-RELATED AND OUTSIDE FORCE (c) where the pipeline crosses water or is adjacent to THREAT (EARTH MOVEMENT. 60 . ning strikes.4 Integrity Assessment Pipelines. Change (greater than 0. For weather-related and outside force threats.7 Assessment Interval water crossings. Guidelines for the Seismic Design and Assessment of Natural Gas and Liquid Hydrocarbon A-10. Weather-related and outside force is defined (i) where the pipeline transitions between soils and in this context as earth movement. the threat shall be for weather-related and outside force threats in general. examinations.2 Gathering. and lightning (see Figure A-10. conservative establish the effectiveness of the program and for confir. ASME B31.g. For example. (c) earthquake fault Changes to the segment may drive revision of proce. PR 268-9823. the operator may The following minimal data sets should be collected for discover other data that should be used when performing each segment and reviewed before a risk assessment can risk assessments for other threats. If no changes are experienced.5 Responses and Mitigation A-10. party damage threat.1-1 Integrity Management Plan. stabilization of the pipe or pipe joints. pipeline integrity.7 Assessment Interval line patrolling should be used to perform surface assess. the operator may with the ASME B31. 61 . Changes to the segment. A-10. Cold Weather. and protection of mation when conducting risk assessments for the third- aboveground facilities from lightning. or the land use around the ments. risk assessments for other threats. such as known slide areas or segment. If a pipeline falls within the listed susceptibilities. when a lization of the soil. Heavy Rains or Floods.8S-2016 ð16Þ Figure A-10. Other methods of mitigation may include stabi. Change management is addressed in section 11. ASME B31. Prevention activities are most appropriate for this threat. ment is not required. pipeline is patrolled.8 Code and other applicable industry discover other data that should be used when performing standards. lowering of the pipeline below ment may be discovered. It is appropriate to use this infor- the frost line for cold-weather situations. In certain locations. may drive reassessment if the changes affect areas of ongoing subsidence. Simplified Process: Prescriptive) A-10. Lightning. For example.6 Other Data Repairs or replacement of pipe shall be in accordance During the inspection activities. evidence of third-party encroach- relocation of the pipeline. Weather-Related and Outside Force Threat (Earth Movement. the progress of the move. reassess- ment should be monitored. ASME B31.8S-2016 A-10.8 Performance Measures (a) number of leaks that are weather-related or due to outside force The following performance measures shall be docu- (b) number of repair, replacement, or relocation mented for the weather-related and outside force actions due to weather-related or outside force threats threat, in order to establish the effectiveness of the program and for confirmation of the inspection interval: 62 ASME B31.8S-2016 NONMANDATORY APPENDIX B DIRECT ASSESSMENT PROCESS ð16Þ B-1 GENERAL B-3 INTERNAL CORROSION DIRECT ASSESSMENT This Appendix provides information about the direct This section has been removed with publication of assessment process. Direct assessment is one integrity NACE SP0206 DG-ICDA. Operators are encouraged to assessment methodology that can be used within the use NACE SP0206 DG-ICDA or an alternate and technically integrity management program. justified methodology. B-2 EXTERNAL CORROSION DIRECT ASSESSMENT This section has been removed with publication of NACE SP0502 ECDA. Operators are encouraged to use NACE SP0502 ECDA or an alternate and technically justi- fied methodology. 63 ASME B31.8S-2016 NONMANDATORY APPENDIX C PREPARATION OF TECHNICAL INQUIRIES C-1 INTRODUCTION (b) Background. State the purpose of the inquiry, which would be either to obtain an interpretation of Code rules The ASME B31 Committee, Code for Pressure Piping, or to propose consideration of a revision to the present will consider written requests for interpretations and rules. Provide concisely the information needed for the revisions of the Code rules, and develop new rules if Committee’s understanding of the inquiry, being sure dictated by technological development. The to include reference to the applicable Code Section, Committee’s activities in this regard are limited strictly Edition, Addenda, paragraphs, figures, and tables. If to interpretations of the rules or to the consideration sketches are provided, they shall be limited to the of revisions to the present rules on the basis of new scope of the inquiry. data or technology. As a matter of published policy, (c) Inquiry Structure ASME does not approve, certify, rate, or endorse any (1) Proposed Question(s). The inquiry shall be stated item, construction, proprietary device, or activity, and, in a condensed and precise question format, omitting accordingly, inquiries requiring such consideration will superfluous background information, and, where appro- be returned. Moreover, ASME does not act as a consultant priate, composed in such a way that “yes” or “no” (perhaps on specific engineering problems or on the general appli- with provisos) would be an acceptable reply. The inquiry cation or understanding of the Code rules. If, based on the statement should be technically and editorially correct. inquiry information submitted, it is the opinion of the (2) Proposed Reply(ies). Provide a proposed reply Committee that the inquirer should seek professional stating what it is believed that the Code requires. If, in assistance, the inquiry will be returned with the recom- the inquirer’s opinion, a revision to the Code is mendation that such assistance be obtained. needed, recommended wording shall be provided in addi- Inquiries that do not provide the information needed for tion to information justifying the change. the Committee’s full understanding will be returned. C-3 SUBMITTAL C-2 REQUIREMENTS Inquiries should be submitted in typewritten form; Inquiries shall be limited strictly to interpretations of however, legible handwritten inquiries will be considered. the rules or to the consideration of revisions to the present They shall include the name and mailing address of the rules on the basis of new data or technology. Inquiries inquirer, and be mailed to the following address: shall meet the following requirements: Secretary (a) Scope. Involve a single rule or closely related rules ASME B31 Committee in the scope of the Code. An inquiry letter concerning unre- Two Park Avenue lated subjects will be returned. New York, NY 10016-5990 64 .9-2014 Building Services Piping B31.8S-2016 Managing System Integrity of Gas Pipelines B31. B31 B31.12-2014 Hydrogen Piping and Pipelines B31E-2008 Standard for the Seismic Design and Retrofit of Above-Ground Piping Systems B31G-2012 Manual for Determining the Remaining Strength of Corroded Pipelines: Supplement to ASME B31 Code for Pressure Piping B31G-2012 Manual para la determinación de la resistencia remanente de tuberiás corroídas B31J-2008 (R2013) Standard Test Method for Determining Stress Intensification Factors (i-Factors) for Metallic Piping Components B31J-2008 (R2013) Método de prueba estándar para determinar factores de intensificación de esfuerzo (Factores i) para components de tuberiás metálicas B31Q-2016 Pipeline Personnel Qualification B31Q-2010 Calificación del personal de líneas de tuberiás B31T-2015 Standard Toughness Requirements for Piping The ASME Publications Catalog shows a complete list of all the Standards published by the Society. or the latest information about our publications. For a complimentary catalog.8-2016 Gas Transmission and Distribution Piping Systems B31.3-2010 Tuberías de Proceso B31.3-2014 Process Piping B31. ASME CODE FOR PRESSURE PIPING.4-2016 Pipeline Transportation Systems for Liquids and Slurries B31.1-2016 Power Piping B31.8S-2010 Gestión de Integridad de Sistemas de Gasoductos B31.5-2016 Refrigeration Piping and Heat Transfer Components B31. call 1-800-THE-ASME (1-800-843-2763). ASME Services ASME is committed to developing and delivering technical information.org 150 Clove Road. . Additional procedures for inquiries may be listed within. we make every effort to answer your questions and expedite your orders. At ASME’s Customer Care. Information as to whether or not technical inquiries are issued to this code or standard is shown on the copyright page. Simply mail. fax. Mail Call Toll Free Fax—24 hours E-Mail—24 hours ASME US & Canada: 800-THE-ASME 973-882-1717 customercare@asme. 6th Floor (800-843-2763) 973-882-5155 Little Falls. 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