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
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CONTENTS Foreword . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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Committee Roster . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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Summary of Changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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1 2 3 4 5 6 7 8 9 10
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Integrity Management Program Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consequences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gathering, Reviewing, and Integrating Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Risk Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Integrity Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Responses to Integrity Assessments and Mitigation (Repair and Prevention) . . . . . . . . . . . . . Integrity Management Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Performance Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Communications Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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1 2 7 9 11 17 21 27 29 34
11 12 13 14
Management of Change Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Quality Control Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Terms, Definitions, and Acronyms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References and Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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34 35 36 42
Nonmandatory Appendices A Threat Process Charts and Prescriptive Integrity Management Plans . . . . . . . . . . . . . . . . . . . . . B Direct Assessment Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C Preparation of Technical Inquiries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
45 63 64
Figures 2.1-1 2.1-2 3.2.4-1 7.2.1-1
Integrity Management Program Elements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Integrity Management Plan Process Flow Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Potential Impact Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Timing for Scheduled Responses: Time-Dependent Threats, Prescriptive Integrity Management Plan
3 4 8 25
Hierarchy of Terminology for Integrity Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Integrity Management Plan, External Corrosion Threat (Simplified Process: Prescriptive) . . . . . . Integrity Management Plan, Internal Corrosion Threat (Simplified Process: Prescriptive) . . . . . . Integrity Management Plan, Manufacturing Threat (Pipe Seam and Pipe; Simplified Process: Prescriptive) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Integrity Management Plan, Construction Threat (Pipe Girth Weld, Fabrication Weld, Wrinkle Bend or Buckle, Stripped Threads/Broken Pipe/Coupling; Simplified Process: Prescriptive) . . . . . . . . Integrity Management Plan, Equipment Threat (Gasket and O-Ring, Control/Relief, Seal/Pump Packing; Simplified Process: Prescriptive) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Integrity Management Plan, Third-Party Damage Threat [Third-Party Inflicted Damage (Immediate), Vandalism, Previously Damaged Pipe; Simplified Process: Prescriptive] . . . . . . . . . . . . . . . . .
36 46 48
13-1 A-2.1-1 A-3.1-1 A-5.1-1 A-6.1-1 A-7.1-1 A-8.1-1
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. . . .
. . . .
52 54 56 57
A-9.1-1 A-10.1-1
Tables 4.2.1-1 4.3-1 5.6.1-1 7.1-1 8.3.4-1 8.3.4-2 8.3.4-3 9.2.3-1 9.4-1 9.4-2 A-4.4-1 A-4.4.1-1
Integrity Management Plan, Incorrect Operations Threat (Simplified Process: Prescriptive) . . . . . Integrity Management Plan, Weather-Related and Outside Force Threat (Earth Movement, Heavy Rains or Floods, Cold Weather, Lightning; Simplified Process: Prescriptive) . . . . . . . . . . . . . .
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Data Elements for Prescriptive Pipeline Integrity Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . Typical Data Sources for Pipeline Integrity Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Integrity Assessment Intervals: Time-Dependent Threats, Internal and External Corrosion, Prescriptive Integrity Management Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Acceptable Threat Prevention and Repair Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Example of Integrity Management Plan for Hypothetical Pipeline Segment (Segment Data: Line 1, Segment 3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Example of Integrity Management Plan for Hypothetical Pipeline Segment (Integrity Assessment Plan: Line 1, Segment 3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Example of Integrity Management Plan for Hypothetical Pipeline Segment (Mitigation Plan: Line 1, Segment 3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Performance Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Performance Metrics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Overall Performance Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SCC Crack Severity Criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Actions Following Discovery of SCC During Excavation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9 10
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14 22 29 30 30 31 32 33 50 51
FOREWORD Pipeline system operators continuously work to improve the safety of their systems and operations. In the United States, 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. The gas pipeline industry needed to address many technical concerns before an integrity management standard could be written. A number of initiatives were undertaken by the industry to answer these questions; as a result of two years of intensive work by a number of technical experts in their fields, 20 reports were issued that provided the responses required to complete the 2001 edition of this Code. (The list of these reports is included in the reference section of this Code.) This Code is nonmandatory, and is designed to supplement B31.8, ASME Code for Pressure Piping, Gas Transmission and Distribution Piping Systems. Not all operators or countries will decide to implement this Code. This Code becomes mandatory if and when pipeline regulators include it as a requirement in their regulations. This Code is a process code that describes the process an operator may use to develop an integrity management program. It also provides two approaches for developing an integrity management program: a prescriptive approach and a performance- or risk-based approach. Pipeline operators in a number of countries are currently utilizing risk-based or risk-management principles to improve the safety of their systems. Some of the international standards issued on this subject were utilized as resources for writing this Code. Particular recognition is given to API and their liquids integrity management standard, API Std 1160, which was used as a model for the format of this Code. The intent of this Code is to provide a systematic, comprehensive, and integrated approach to managing the safety and integrity of pipeline systems. The task force that developed this Code hopes that it has achieved that intent. The 2004 Supplement was approved by the B31 Standards Committee and by the ASME Board on Pressure Technology Codes and Standards. The 2010 Supplement was approved by the B31 Standards Committee and by the ASME Board on Pressure Technology Codes and Standards. 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. 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. 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. This Edition was approved by ANSI on August 26, 2016.
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ASME B31 COMMITTEE Code for Pressure Piping (The following is the roster of the Committee at the time of approval of this Code.)
STANDARDS COMMITTEE OFFICERS J. E. Meyer, Chair J. W. Frey, Vice Chair A. Maslowski, Secretary
STANDARDS COMMITTEE PERSONNEL R. J. Appleby, ExxonMobil Pipeline Co. C. Becht IV, Becht Engineering Co. K. C. Bodenhamer, Willbros Professional Services, Engineering R. Bojarczuk, ExxonMobil Research and Engineering Co. C. J. Campbell, Air Liquide J. S. Chin, TransCanada Pipelines U.S. D. D. Christian, Victaulic R. P. Deubler, Fronek Power Systems, LLC C. H. Eskridge, Jr., Jacobs Engineering D. J. Fetzner, BP Exploration (Alaska), Inc. P. D. Flenner, Flenner Engineering Services J. W. Frey, Stress Engineering Services, Inc. D. R. Frikken, Becht Engineering Co. R. A. Grichuk, Fluor Enterprises, Inc. R. W. Haupt, Pressure Piping Engineering Associates, Inc. G. A. Jolly, Flowserve/Gestra USA A. Maslowski, The American Society of Mechanical Engineers W. J. Mauro, American Electric Power
J. E. Meyer, Louis Perry Group T. Monday, Team Industries, Inc. M. L. Nayyar, NICE G. R. Petru, Acapella Engineering Services, LLC D. W. Rahoi, CCM 2000 R. Reamey, Turner Industries Group, LLC E. H. Rinaca, Dominion Resources, Inc. M. J. Rosenfeld, Kiefner/Applus — RTD J. T. Schmitz, Southwest Gas Corp. S. K. Sinha, Lucius Pitkin, Inc. W. J. Sperko, Sperko Engineering Services, Inc. J. Swezy, Jr., Boiler Code Tech, LLC F. W. Tatar, FM Global K. A. Vilminot, Black & Veatch L. E. Hayden, Jr., Ex-Officio Member, Consultant A. J. Livingston, Ex-Officio Member, Kinder Morgan J. S. Willis, Ex-Officio Member, Page Southerland Page, Inc.
B31.8 EXECUTIVE COMMITTEE A. Maslowski, Secretary, The American Society of Mechanical Engineers D. D. Anderson, Columbia Pipeline Group R. J. Appleby, ExxonMobil Pipeline Co. K. B. Kaplan, KBR K. G. Leewis, Leewis and Associates, Inc.
E. K. Newton, Southern California Gas Co. B. J. Powell, NiSource, Inc. M. J. Rosenfeld, Kiefner/Applus — RTD W. J. Walsh, ArcelorMittal Global R&D J. Zhou, TransCanada Pipelines Ltd.
B31.8 GAS TRANSMISSION AND DISTRIBUTION PIPING SYSTEMS SECTION COMMITTEE R. J. Appleby, Chair, ExxonMobil Pipeline Co. D. D. Anderson, Vice Chair, Columbia Pipeline Group A. Maslowski, Secretary, The American Society of Mechanical Engineers R. C. Becken, Energy Experts International C. A. Bullock, Integrity Solutions, Ltd. J. S. Chin, TransCanada Pipelines U.S. S. C. Christensen, Consultant A. M. Clarke, Consultant P. M. Dickinson, Resolute Energy Corp. J. W. Fee, Consultant D. J. Fetzner, BP Exploration (Alaska), Inc. S. A. Frehse, Southwest Gas Corp. M. W. Gragg, ExxonMobil Production Co.
D. W. Haim, S&B Infrastructure Private, Ltd. M. E. Hovis, Energy Transfer R. D. Huriaux, Richard D. Huriaux, PE LLC M. D. Huston, ONEOK Partners, LP M. Israni, U.S. DOT — PHMSA D. L. Johnson, Energy Transfer K. B. Kaplan, KBR R. W. Kivela, Spectra Energy M. P. Lamontagne, Lamontagne Pipeline Assessment Corp. K. G. Leewis, Leewis and Associates, Inc. R. D. Lewis, Rosen USA W. J. Manegold, Pacific Gas and Electric Co. M. J. Mechlowicz, Southern California Gas Co. D. K. Moore, Consultant
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E. K. Newton, Southern California Gas Co. M. Nguyen, S&B Engineers and Constructors G. E. Ortega, BG Group B. J. Powell, NiSource, Inc. M. T. Reed, TransCanada Corp. E. J. Robichaux, Atmos Energy M. J. Rosenfeld, Kiefner/Applus — RTD R. A. Schmidt, Canadoil P. L. Vaughan, ONEOK Partners, LP F. R. Volgstadt, Volgstadt and Associates, Inc.
W. J. Walsh, ArcelorMittal Global R&D D. H. Whitley, EDG Consulting Engineering D. W. Wright, Wright Tech Services, LLC M. R. Zerella, National Grid J. Zhou, TransCanada Pipelines Ltd. J. S. Zurcher, Process Performance Improvement Consultants S. C. Gupta, Delegate, Bharat Petroleum Corp. Ltd. A. Soni, Delegate, Engineers India Ltd. R. W. Gailing, Contributing Member, BMT Fleet Technology, Ltd. J. K. Wilson, Contributing Member, Spectra
B31.8 SUBGROUP ON DESIGN, MATERIALS, AND CONSTRUCTION M. J. Rosenfeld, Chair, Kiefner/Applus — RTD R. J. Appleby, ExxonMobil Pipeline Co. R. C. Becken, Energy Experts International B. W. Bingham, T. D. Williamson, Inc. J. S. Chin, TransCanada Pipelines U.S. A. M. Clarke, Consultant P. M. Dickinson, Resolute Energy Corp. J. W. Fee, Consultant D. J. Fetzner, BP Exploration (Alaska), Inc. S. A. Frehse, Southwest Gas Corp. R. W. Gailing, BMT Fleet Technology, Ltd. D. Haim, S&B Infrastructure Private, Ltd. R. D. Huriaux, Richard D. Huriaux, PE LLC M. D. Huston, ONEOK Partners, LP K. B. Kaplan, KBR M. Kieba, U.S. DOT — PHMSA
M. J. Mechlowicz, Southern California Gas Co. W. E. Mojica, Pacific Gas and Electric E. K. Newton, Southern California Gas Co. M. Nguyen, S&B Engineers and Constructors G. E. Ortega, BG Group W. L. Raymundo, Raymundo Engineering E. J. Robichaux II, Atmos Energy R. A. Schmidt, Canadoil H. Tiwari, FMC Technologies, Inc. P. L. Vaughan, ONEOK Partners, LP F. R. Volgstadt, Volgstadt and Associates, Inc. W. J. Walsh, ArcelorMittal Global R&D D. H. Whitley, EDG Consulting Engineering J. Zhou, TransCanada Pipelines Ltd. H. M. Al-Muslim, Contributing Member, Saudi Aramco M. A. Boring, Contributing Member, Kiefner and Associates, Inc.
B31.8 SUBGROUP ON DISTRIBUTION E. K. Newton, Chair, Southern California Gas Co. B. J. Powell, Vice Chair, NiSource, Inc. S. A. Frehse, Southwest Gas Corp. J. M. Groot, Southern California Gas Co. M. Kieba, U.S. DOT — PHMSA W. J. Manegold, Pacific Gas and Electric Co.
M. J. Mechlowicz, Southern California Gas Co. E. J. Robichaux, Atmos Energy V. Romero, Southern California Gas Co. B. Tansey, American Gas Association F. R. Volgstadt, Volgstadt and Associates, Inc. M. R. Zerella, National Grid
B31.8 SUBGROUP ON EDITORIAL REVIEW K. G. Leewis, Chair, Leewis and Associates, Inc. R. C. Becken, Energy Experts International R. W. Gailing, BMT Fleet Technology, Ltd. D. Haim, S&B Infrastructure Private, Ltd.
K. B. Kaplan, KBR R. D. Lewis, Rosen USA D. K. Moore, Consultant
B31.8 SUBGROUP ON OFFSHORE PIPELINES K. B. Kaplan, Chair, KBR R. J. Appleby, ExxonMobil Pipeline Co. K. K. Emeaba, National Transportation Safety Board
M. W. Gragg, ExxonMobil Production Co. M. Nguyen, S&B Engineers and Constructors H. Tiwari, FMC Technologies, Inc.
B31.8 SUBGROUP ON OPERATION AND MAINTENANCE D. D. Anderson, Chair, Columbia Pipeline Group M. E. Hovis, Vice Chair, Energy Transfer R. P. Barry, ENSTAR Natural Gas Co. J. P. Brandt, BP Exploration (Alaska), Inc. C. A. Bullock, Integrity Solutions, Ltd. K. K. Emeaba, National Transportation Safety Board J. M. Groot, Southern California Gas Co.
J. Hudson, EN Engineering L. J. Huyse, Chevron M. Israni, U.S. DOT — PHMSA D. L. Johnson, Energy Transfer R. W. Kivela, Spectra Energy E. Kostelka, Enable Midstream Partners E. C. Kurilla, American Gas Association
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M. P. Lamontagne, Lamontagne Pipeline Assessment Corp. K. G. Leewis, Leewis and Associates, Inc. R. D. Lewis, Rosen USA C. Maier, DNV GL W. J. Manegold, Pacific Gas and Electric Co. D. K. Moore, Consultant M. Nguyen, S&B Engineers and Constructors B. J. Powell, NiSource, Inc.
M. T. Reed, TransCanada Corp. D. R. Thornton, The Equity Engineering Group J. K. Wilson, Spectra D. W. Wright, Wright Tech Services, LLC M. R. Zerella, National Grid J. S. Zurcher, Process Performance Improvement Consultants D. E. Adler, Contributing Member, Columbia Pipeline Group
B31.8 GAS TRANSMISSION AND DISTRIBUTION PIPING SYSTEMS, INDIA IWG N. B. Babu, Chair, Gujarat State Petronet Ltd. A. Karnatak, Vice Chair, Gail India Ltd. A. Maslowski, Secretary, The American Society of Mechanical Engineers J. George, GSPL India Transco, Ltd. A. Meghani, Petroleum and Natural Gas Regulatory Board V. Mittal, Engineers India Ltd.
S. Prakash, Petrofac Onshore Engineering and Construction K. P. Radhakrishnan, Gujarat State Petronet Ltd. V. T. Randeria, Gujarat Gas Co. Ltd. S. Sahani, TDW India Ltd. J. Sivaraman, Reliance Gas Transportation Infrastructure Ltd. R. Uprety, Oil Industry Safety Directorate M. Sharma, Contributing Member, ASME India PVT. Ltd.
B31.8 INTERNATIONAL REVIEW GROUP R. J. Appleby, Chair, ExxonMobil Pipeline Co. H. M. Al-Muslim, Vice Chair, Saudi Aramco A. Maslowski, Secretary, The American Society of Mechanical Engineers
Q. Feng, PetroChina Pipeline Co. W. Feng, PetroChina Pipeline Co. W. Wu, China Petroleum Pipeline Engineering Corp. Z. Yu, China Petroleum Pipeline Engineering Corp.
B31 CONFERENCE GROUP A. Bell, Bonneville Power Administration R. A. Coomes, State of Kentucky, Department of Housing/Boiler Section D. H. Hanrath, Consultant C. J. Harvey, Alabama Public Service Commission D. T. Jagger, Ohio Department of Commerce K. T. Lau, Alberta Boilers Safety Association R. G. Marini, New Hampshire Public Utilities Commission I. W. Mault, Manitoba Department of Labour A. W. Meiring, Fire and Building Safety Division/Indiana
R. F. Mullaney, British Columbia Boiler and Pressure Vessel Safety Branch P. Sher, State of Connecticut D. A. Starr, Nebraska Department of Labor D. J. Stursma, Iowa Utilities Board R. P. Sullivan, The National Board of Boiler and Pressure Vessel Inspectors J. E. Troppman, Division of Labor/State of Colorado Boiler Inspections W. A. West, Lighthouse Assistance, Inc. T. F. Wickham, Rhode Island Department of Labor
B31 EXECUTIVE COMMITTEE J. W. Frey, Chair, Stress Engineering Services, Inc. G. A. Antaki, Becht Engineering Co. R. J. Appleby, ExxonMobil Pipeline Co. D. D. Christian, Victaulic D. R. Frikken, Becht Engineering Co. R. A. Grichuk, Fluor Enterprises, Inc. L. E. Hayden, Jr., Consultant C. E. Kolovich, Keifner and Associates, Inc.
H. Kutz, Johnson Controls Corp. A. J. Livingston, Kinder Morgan W. J. Mauro, American Electric Power J. E. Meyer, Louis Perry Group M. L. Nayyar, NICE S. K. Sinha, Lucius Pitkin, Inc. J. S. Willlis, Page Southerland Page, Inc.
B31 FABRICATION AND EXAMINATION COMMITTEE J. Swezy, Jr., Chair, Boiler Code Tech, LLC U. D’Urso, Secretary, The American Society of Mechanical Engineers R. D. Campbell, Bechtel Corp. R. D. Couch, Electric Power Research Institute R. J. Ferguson, Metallurgist P. D. Flenner, Flenner Engineering Services S. Gingrich, AECOM
J. Hainsworth, Consultant A. D. Nalbandian, Thielsch Engineering, Inc. R. J. Silvia, Process Engineers and Constructors, Inc. W. J. Sperko, Sperko Engineering Services, Inc. P. L. Vaughan, ONEOK Partners, LP K. Wu, Stellar Energy Systems
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B31 MATERIALS TECHNICAL COMMITTEE R. A. Grichuk, Chair, Fluor Enterprises, Inc. C. E. O’Brien, Secretary, The American Society of Mechanical Engineers B. T. Bounds, Bechtel Corp. W. P. Collins, WPC Solutions, LLC R. P. Deubler, Fronek Power Systems, LLC C. H. Eskridge, Jr., Jacobs Engineering A. A. Hassan, PGESCo
G. A. Jolly, Flowserve/Gestra USA C. J. Melo, Technip USA, Inc. M. L. Nayyar, NICE M. B. Pickell, Willbros Engineers, Inc. D. W. Rahoi, CCM 2000 R. A. Schmidt, Canadoil J. L. Smith, Consultant Z. Djilali, Contributing Member, Sonatrach
B31 MECHANICAL DESIGN TECHNICAL COMMITTEE G. A. Antaki, Chair, Becht Engineering Co. J. E. Meyer, Vice Chair, Louis Perry Group R. Lucas, Secretary, The American Society of Mechanical Engineers D. Arnett, Chevron ETC C. Becht IV, Becht Engineering Co. R. Bethea, Huntington Ingalls Industries, Newport News Shipbuilding P. Cakir-Kavcar, Bechtel Corp. — Oil, Gas and Chemicals N. F. Consumo, Sr., Consultant J. P. Ellenberger, Consultant M. Engelkemier, Stanley Consultants, Inc. D. J. Fetzner, BP Exploration (Alaska), Inc. D. A. Fraser, NASA Ames Research Center J. A. Graziano, Consultant J. D. Hart, SSD, Inc.
R. W. Haupt, Pressure Piping Engineering Associates, Inc. B. P. Holbrook, Babcock Power, Inc. W. J. Koves, Pi Engineering Software, Inc. R. A. Leishear, Leishear Engineering, LLC G. D. Mayers, Alion Science and Technology J. F. McCabe, General Dynamics Electric Boat T. Q. McCawley, TQM Engineering PC J. Minichiello, Bechtel National, Inc. A. Paulin, Paulin Research Group R. A. Robleto, KBR M. J. Rosenfeld, Kiefner/Applus — RTD T. Sato, Japan Power Engineering and Inspection Corp. G. Stevick, Berkeley Engineering and Research, Inc. E. C. Rodabaugh, Honorary Member, Consultant
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ASME B31.8S-2016 SUMMARY OF CHANGES Following approval by the ASME B31 Committee and ASME, and after public review, ASME B31.8S-2016 was approved by the American National Standards Institute on August 26, 2016. ASME B31.8S-2016 includes the following changes identified by a margin note, (16).
Page 3 7 8 10 17
Location 2.2 3.2.1 Figure 3.2.4-1 4.4 6.1
Change Subparagraph (b) revised Revised Revised Third paragraph revised Second paragraph revised
19 27 36 36 42
6.3 7.7 13 Figure 13-1 14
Second paragraph revised Revised Definition of resident threat added Revised Updated
45
A-1
46 48 50 51 52 54 55 56 57 59 60 61 63
Figure A-2.1-1 Figure A-3.1-1 Table A-4.4-1 Table A-4.4.1-1 Figure A-5.1-1 Figure A-6.1-1 A-6.6 Figure A-7.1-1 Figure A-8.1-1 Figure A-9.1-1 A-10.3 Figure A-10.1-1 B-1
Designator added, and subsequent paragraphs redesignated Designator editorially revised Designator editorially revised Designator editorially revised Designator editorially revised Designator editorially revised Designator editorially revised Revised Designator editorially revised Designator editorially revised Designator editorially revised Subparagraph (i) added Designator editorially revised Designator added, and subsequent paragraphs redesignated
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ASME B31.8S-2016
MANAGING SYSTEM INTEGRITY OF GAS PIPELINES on the pipeline condition required by the prescriptivebased program. The level of assurance of a performance-based program or an alternative international standard must meet or exceed that of a prescriptive program. The requirements for prescriptive-based and performance-based integrity management programs are provided in each of the sections in this Code. In addition, Nonmandatory Appendix A provides specific activities by threat categories that an operator shall follow in order to produce a satisfactory prescriptive integrity management program. This Code is intended for use by individuals and teams charged with planning, implementing, and improving a pipeline integrity management program. Typically, a team will include managers, engineers, operating personnel, technicians, and/or specialists with specific expertise in prevention, detection, and mitigation activities.
1 INTRODUCTION 1.1 Scope This Code applies to onshore pipeline systems constructed with ferrous materials and that transport gas. The principles and processes embodied in integrity management are applicable to all pipeline systems. This Code is specifically designed to provide the operator (as defined in section 13) with the information necessary to develop and implement an effective integrity management program utilizing proven industry practices and processes. The processes and approaches described within this Code are applicable to the entire pipeline.
1.2 Purpose and Objectives Managing the integrity of a gas pipeline system is the primary goal of every pipeline system operator. Operators want to continue providing safe and reliable delivery of natural gas to their customers without adverse effects on employees, the public, customers, or the environment. Incident-free operation has been and continues to be the gas pipeline industry’s goal. The use of this Code as a supplement to the ASME B31.8 Code will allow pipeline operators to move closer to that goal. A comprehensive, systematic, and integrated integrity management program provides the means to improve the safety of pipeline systems. Such an integrity management program provides the information for an operator to effectively allocate resources for appropriate prevention, detection, and mitigation activities that will result in improved safety and a reduction in the number of incidents. This Code describes a process that an operator of a pipeline system can use to assess and mitigate risks in order to reduce both the likelihood and consequences of incidents. It covers both a prescriptive-based and a performancebased integrity management program. The prescriptive process, when followed explicitly, will provide all the inspection, prevention, detection, and mitigation activities necessary to produce a satisfactory integrity management program. This does not preclude conformance with the requirements of ASME B31.8. The performance-based integrity management program alternative utilizes more data and more extensive risk analyses, which enables the operator to achieve a greater degree of flexibility in order to meet or exceed the requirements of this Code specifically in the areas of inspection intervals, tools used, and mitigation techniques employed. An operator cannot proceed with the performance-based integrity program until adequate inspections are performed that provide the information
1.3 Integrity Management Principles A set of principles is the basis for the intent and specific details of this Code. They are enumerated here so that the user of this Code can understand the breadth and depth to which integrity shall be an integral and continuing part of the safe operation of a pipeline system. Functional requirements for integrity management shall be engineered into new pipeline systems from initial planning, design, material selection, and construction. Integrity management of a pipeline starts with sound design, material selection, and construction of the pipeline. Guidance for these activities is primarily provided in ASME B31.8. There are also a number of consensus standards that may be used, as well as pipeline jurisdictional safety regulations. If a new line is to become a part of an integrity management program, the functional requirements for the line, including prevention, detection, and mitigation activities, shall be considered in order to meet this Code. Complete records of material, design, and construction for the pipeline are essential for the initiation of a good integrity management program. System integrity requires commitment by all operating personnel using comprehensive, systematic, and integrated processes to safely operate and maintain pipeline systems. In order to have an effective integrity management program, the program shall address the operator’s organization, processes, and the physical system. An integrity management program is continuously evolving and must be flexible. An integrity management program should be customized to meet each operator’s unique conditions. The program shall be periodically 1
ASME B31.8S-2016
evaluated and modified to accommodate changes in pipeline operation, changes in the operating environment, and the influx of new data and information about the system. Periodic evaluation is required to ensure the program takes appropriate advantage of improved technologies and that the program utilizes the best set of prevention, detection, and mitigation activities that are available for the conditions at that time. Additionally, as the integrity management program is implemented, the effectiveness of the activities shall be reassessed and modified to ensure the continuing effectiveness of the program and all its activities. Information integration is a key component for managing system integrity. A key element of the integrity management framework is the integration of all pertinent information when performing risk assessments. Information that can impact an operator’s understanding of the important risks to a pipeline system comes from a variety of sources. The operator is in the best position to gather and analyze this information. By analyzing all of the pertinent information, the operator can determine where the risks of an incident are the greatest, and make prudent decisions to assess and reduce those risks. Risk assessment is an analytical process by which an operator determines the types of adverse events or conditions that may impact pipeline integrity. Risk assessment also determines the likelihood or probability of those events or conditions that will lead to a loss of integrity, and the nature and severity of the consequences that may occur following a failure. This analytical process involves the integration of design, construction, operating, maintenance, testing, inspection, and other information about a pipeline system. Risk assessments, which are the very foundation of an integrity management program, can vary in scope or complexity and use different methods or techniques. The ultimate goal of assessing risks is to identify the most significant risks so that an operator can develop an effective and prioritized prevention/ detection/mitigation plan to address the risks. Assessing risks to pipeline integrity is a continuous process. The operator shall periodically gather new or additional information and system operating experience. These shall become part of revised risk assessments and analyses that in turn may require adjustments to the system integrity plan. New technology should be evaluated and implemented as appropriate. Pipeline system operators should avail themselves of new technology as it becomes proven and practical. New technologies may improve an operator’s ability to prevent certain types of failures, detect risks more effectively, or improve the mitigation of risks. Performance measurement of the system and the program itself is an integral part of a pipeline integrity management program. Each operator shall choose significant performance measures at the beginning of the program and then periodically evaluate the results of
these measures to monitor and evaluate the effectiveness of the program. Periodic reports of the effectiveness of an operator’s integrity management program shall be issued and evaluated in order to continuously improve the program. Integrity management activities shall be communicated to the appropriate stakeholders. Each operator shall ensure that all appropriate stakeholders are given the opportunity to participate in the risk assessment process and that the results are communicated effectively.
2 INTEGRITY MANAGEMENT PROGRAM OVERVIEW 2.1 General This section describes the required elements of an integrity management program. These program elements collectively provide the basis for a comprehensive, systematic, and integrated integrity management program. The program elements depicted in Figure 2.1-1 are required for all integrity management programs. This Code requires that the operator document how its integrity management program will address the key program elements. This Code utilizes recognized industry practices for developing an integrity management program. The process shown in Figure 2.1-2 provides a common basis to develop (and periodically re-evaluate) an operator-specific program. In developing the program, a pipeline operator shall consider his company’s specific integrity management goals and objectives, and then apply the processes to ensure that these goals are achieved. This Code details two approaches to integrity management: a prescriptive method and a performance-based method. The prescriptive integrity management method requires the least amount of data and analysis, and can be successfully implemented by following the steps provided in this Code and Nonmandatory Appendix A. The prescriptive method incorporates expected worstcase indication growth to establish intervals between successive integrity assessments in exchange for reduced data requirements and less extensive analysis. The performance-based integrity management method requires more knowledge of the pipeline, and consequently mored) GENERAL NOTE (Cont'd): Seal/Pack Strip/BP TPD(IF) Vand WB/B
= = = = =
seal/pump packing failure stripped thread/broken pipe damage inflicted by first, second, or third parties (instantaneous/immediate failure) vandalism wrinkle bend or buckle
ASME B31.8S-2016
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Figure 7.2.1-1 Timing for Scheduled Responses: Time-Dependent Threats, Prescriptive Integrity Management Plan
GENERAL NOTE: Predicted failure pressure, Pf, is calculated using a proven engineering method for evaluating the remaining strength of corroded pipe. The failure pressure ratio is used to categorize a defect as immediate, scheduled, or monitored.
times the MAOP shall be examined and evaluated according to a schedule established by Figure 7.2.1-1. Any defect found to require repair or removal shall be promptly remediated by repair or removal unless the operating pressure is lowered to mitigate the need to repair or remove the defect. Monitored indications are the least severe and will not require examination and evaluation until the next scheduled integrity assessment interval stipulated by the integrity management plan, provided that they are not expected to grow to critical dimensions prior to the next scheduled assessment.
7.2.3 Metal Loss and Caliper Tools for Third-Party Damage and Mechanical Damage. Indications requiring immediate response are those that might be expected to cause immediate or near-term leaks or ruptures based on their known or perceived effects on the strength of the pipeline. These could include dents with gouges. The operator shall examine these indications within a period not to exceed 5 days following determination of the condition. Indications requiring a scheduled response would include any indication on a pipeline operating at or above 30% of specified minimum yield strength (SMYS) of a plain dent that exceeds 6% of the nominal pipe diameter, mechanical damage with or without concurrent visible indentation of the pipe, dents with cracks, dents that affect ductile girth or seam welds if the depth is in excess of 2% of the nominal pipe diameter, and dents of any depth that affect nonductile welds. (For additional information, see ASME B31.8, para. 851.4.) The operator shall expeditiously examine these indications within a period not to exceed 1 yr following determination of the condition. After examination and evaluation, any defect found to require repair or removal shall be promptly remediated by repair or removal, unless the operating pressure is lowered to mitigate the need to repair or remove the defect.
7.2.2 Crack Detection Tools for Stress Corrosion Cracking. It is the responsibility of the operator to develop and document appropriate assessment, response, and repair plans when in-line inspection (ILI) is used for the detection and sizing of indications of stress corrosion cracking (SCC). In lieu of developing assessment, response, and repair plans, an operator may elect to treat all indications of stress corrosion cracks as requiring immediate response, including examination or pressure reduction within a period not to exceed 5 days following determination of the condition. After examination and evaluation, any defect found to require repair or removal shall be promptly remediated by repair, removal, or lowering the operating pressure until such time as removal or repair is completed.
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(1) a documented hydrostatic retest program with a technically justifiable interval, or (2) an engineering critical assessment to evaluate the risk and identify further mitigation methods (b) If a failure occurred due to SCC, the operator shall perform the following: (1) implement a documented hydrostatic retest program for the subject segment, and (2) technically justify the retest interval in the written retest program
7.2.4 Limitations to Response Times for PrescriptiveBased Program. When time-dependent anomalies such as internal corrosion, external corrosion, or stress corrosion cracking are being evaluated, an analysis utilizing appropriate assumptions about growth rates shall be used to ensure that the defect will not attain critical dimensions prior to the scheduled repair or next inspection. GRI-00/ 0230 (see section 14) contains additional guidance for these analyses. When determining repair intervals, the operator should consider that certain threats to specific pipeline operating conditions may require a reduced examination and evaluation interval. This may include third-party damage or construction threats in pipelines subject to pressure cycling or external loading that may promote increased defect growth rates. For prescriptive-based programs, the inspection intervals are conservative for potential defects that could lead to a rupture; however, this does not alleviate operators of the responsibility to evaluate the specific conditions and changes in operating conditions to ensure the pipeline segment does not warrant special consideration (see GRI-01/0085). If the analysis shows that the time to failure is too short in relation to the time scheduled for the repair, the operator shall apply temporary measures, such as pressure reduction, until a permanent repair is completed. In considering projected repair intervals and methods, the operator should consider potential delaying factors, such as access, environmental permit issues, and gas supply requirements.
7.3.3 Manufacturing and Related Defect Threats. A subsequent pressure test for the manufacturing threat is not required unless the MAOP of the pipeline has been raised or when the operating pressure has been raised above the historical operating pressure (highest pressure recorded in 5 yr prior to the effective date of this Supplement).
7.4 Responses to Direct Assessment Inspections 7.4.1 External Corrosion Direct Assessment (ECDA). For the ECDA prescriptive program for pipelines operating above 30% SMYS, if the operator chooses to examine and evaluate all the indications found by inspection, and repairs all defects that could grow to failure in 10 yr, then the reinspection interval shall be 10 yr. If the operator elects to examine, evaluate, and repair a smaller set of indications, then the interval shall be 5 yr, provided an analysis is performed to ensure all remaining defects will not grow to failure in 10 yr. The interval between determination and examination shall be consistent with Figure 7.2.1-1. For the ECDA prescriptive program for pipeline segments operating up to but not exceeding 30% SMYS, if the operator chooses to examine and evaluate all the indications found by inspections and repair all defects that could grow to failure in 20 yr, the reinspection interval shall be 20 yr. If the operator elects to examine, evaluate, and repair a smaller set of indications, then the interval shall be 10 yr, provided an analysis is performed to ensure all remaining defects will not grow to failure in 20 yr (at an 80% confidence level). The interval between determination and examination shall be consistent with Figure 7.2.1-1.
7.2.5 Extending Response Times for PerformanceBased Program. An engineering critical assessment (ECA) of some defects may be performed to extend the repair or reinspection interval for a performance-based program. ECA is a rigorous evaluation of the data that reassesses the criticality of the anomaly and adjusts the projected growth rates on site-specific parameters. The operator’s integrity management program shall include documentation that describes grouping of specific defect types and the ECA methods used for such analyses.
7.3 Responses to Pressure Testing Any defect that fails a pressure test shall be promptly remediated by repair or removal.
7.4.2 Internal Corrosion Direct Assessment (ICDA). For the ICDA prescriptive program, examination and evaluation of all selected locations must be performed within 1 yr of selection. The interval between subsequent examinations shall be consistent with Figure 7.2.1-1.
7.3.1 External and Internal Corrosion Threats. The interval between tests for the external and internal corrosion threats shall be consistent with Table 5.6.1-1. 7.3.2 Stress Corrosion Cracking Threat. The interval between pressure tests for stress corrosion cracking shall be as follows: (a) If no failures occurred due to SCC, the operator shall use one of the following options to address the long-term mitigation of SCC:
7.4.3 Stress Corrosion Cracking Direct Assessment (SCCDA). For the SCCDA prescriptive program, examination and evaluation of all selected locations must be performed within 1 yr of selection. ILI or pressure testing (hydrotesting) may not be warranted if significant and extensive cracking is not present on a pipeline system. 26
ASME B31.8S-2016
The interval between subsequent examinations shall provide similar safe interval between periodic integrity assessments consistent with Figure 7.2.1-1 and section A-4. Figure 7.2.1-1 and section A-4 are applicable to prescriptive-based programs. The intervals may be extended for a performance-based program as provided in para. 7.2.5.
7.8 Prevention Options An operator’s integrity management program shall include applicable activities to prevent and minimize the consequences of unintended releases. Prevention activities do not necessarily require justification through additional inspection data. Prevention actions can be identified during normal pipeline operation, risk assessment, implementation of the inspection plan, or during repair. The predominant prevention activities presented in section 7 include information on the following: (a) preventing third-party damage (b) controlling corrosion (c) detecting unintended releases (d) minimizing the consequences of unintended releases (e) operating pressure reduction There are other prevention activities that the operator may consider. A tabulation of prevention activities and their relevance to the threats identified in section 2 is presented in Table 7.1-1.
7.5 Timing for Scheduled Responses Figure 7.2.1-1 contains three plots of the allowed time to respond to an indication, based on the predictive failure pressure, Pf, divided by the MAOP of the pipeline. The three plots correspond to (a) pipelines operating at pressures above 50% of SMYS (b) pipelines operating at pressures above 30% of SMYS but not exceeding 50% of SMYS (c) pipelines operating at pressures not exceeding 30% of SMYS The figure is applicable to the prescriptive-based program. The intervals may be extended for the performance-based program as provided in para. 7.2.5.
8 INTEGRITY MANAGEMENT PLAN
7.6 Repair Methods
8.1 General
Table 7.1-1 provides acceptable repair methods for each of the 21 threats. Each operator’s integrity management program shall include documented repair procedures. All repairs shall be made with materials and processes that are suitable for the pipeline operating conditions and meet ASME B31.8 requirements. ð16Þ
The integrity management plan is developed after gathering the data (see section 4) and completing the risk assessment (see section 5) for each threat and for each pipeline segment or system. An appropriate integrity assessment method shall be identified for each pipeline system or segment. Integrity assessment of each system can be accomplished through a pressure test, an in-line inspection using a variety of tools, direct assessment, or use of other proven technologies (see section 6). In some cases, a combination of these methods may be appropriate. The highest-risk segments shall be given priority for integrity assessment. Following the integrity assessment, mitigation activities shall be undertaken. Mitigation consists of two parts. The first part is the repair of the pipeline. Repair activities shall be made in accordance with ASME B31.8 and/or other accepted industry repair techniques. Repair may include replacing defective piping with new pipe, installation of sleeves, coating repair, or other rehabilitation. These activities shall be identified, prioritized, and scheduled (see section 7). Once the repair activities are determined, the operator shall evaluate prevention techniques that prevent future deterioration of the pipeline. These techniques may include providing additional cathodic protection, injecting corrosion inhibitors and pipeline cleaning, or changing the operating conditions. Prevention plays a major role in reducing or eliminating the threats from third-party damage, external corrosion, internal corrosion, stress corrosion cracking, cold-weather-related failures, earth
7.7 Prevention Strategy/Methods Prevention is an important proactive element of an integrity management program. Integrity management program prevention strategies should be based on data gathering, threat identification, and risk assessments conducted per the requirements of sections 2, 3, 4, and 5. Prevention measures shown to be effective in the past should be continued in the integrity management program. Prevention strategies (including intervals) should also consider the classification of identified threats as time-dependent, resident, or time-independent in order to ensure that effective prevention methods are utilized. Operators who opt for prescriptive programs should use, at a minimum, the prevention methods indicated in Nonmandatory Appendix A. For operators who choose performance-based programs, both the preventive methods and time intervals employed for each threat/segment should be determined by analysis using system attributes, information about existing conditions, and industry-proven risk assessment methods.
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movement failures, problems caused by heavy rains and floods, and failures caused by incorrect operations. All threats cannot be dealt with through inspection and repair; therefore, prevention for these threats is a key element in the plan. These activities may include, for example, prevention of third-party damage and monitoring for outside force damage. A performance-based integrity management plan, containing the same structure as the prescriptivebased plan, requires more detailed analyses based upon more complete data or information about the line. Using a risk assessment model, a pipeline operator can exercise a variety of options for integrity assessments and prevention activities, as well as their timing. Prior integrity assessments and mitigation activities should only be included in the plan if they were as rigorous as those identified in this Code.
step is repeated after integrity assessment and mitigation activities have been implemented, and as new operation and maintenance information about the pipeline system or segment is gathered. This information review shall be contained in the plan or in a database that is part of the plan. All data will be used to support future risk assessments and integrity evaluations. Data gathering is covered in section 4. 8.3.2 Assess Risk. Risk assessment should be performed periodically to include new information, consider changes made to the pipeline system or segment, incorporate any external changes, and consider new scientific techniques that have been developed and commercialized since the last assessment. It is recommended that this be performed annually but shall be performed after substantial changes to the system are made and before the end of the current interval. The results of this assessment are to be reflected in the mitigation and integrity assessment activities. Changes to the acceptance criteria will also necessitate reassessment. The integrity management plan shall contain specifics about how risks are assessed and the frequency of reassessment. The specifics for assessing risk are covered in section 5.
8.2 Updating the Plan Data collected during the inspection and mitigation activities shall be analyzed and integrated with previously collected data. This is in addition to other types of integrity management-related data that is constantly being gathered through normal operations and maintenance activities. The addition of this new data is a continuous process that, over time, will improve the accuracy of future risk assessments via its integration (see section 4). This ongoing data integration and periodic risk assessment will result in continual revision to the integrity assessment and mitigation aspects of the plan. In addition, changes to the physical and operating aspects of the pipeline system or segment shall be properly managed (see section 11). This ongoing process will most likely result in a series of additional integrity assessments or review of previous integrity assessments. A series of additional mitigation activities or follow-up to previous mitigation activities may also be required. The plan shall be updated periodically as additional information is acquired and incorporated. It is recognized that certain integrity assessment activities may be one-time events and focused on elimination of certain threats, such as manufacturing, construction, and equipment threats. For other threats, such as time-dependent threats, periodic inspection will be required. The plan shall remain flexible and incorporate any new information.
8.3.3 Integrity Assessment. Based on the assessment of risk, the appropriate integrity assessments shall be implemented. Integrity assessments shall be conducted using in-line inspection tools, pressure testing, and/or direct assessment. For certain threats, use of these tools may be inappropriate. Implementation of prevention activities or more frequent maintenance activities may provide a more effective solution. Integrity assessment method selection is based on the threats for which the inspection is being performed. More than one assessment method or more than one tool may be required to address all the threats. After each integrity assessment, this portion of the plan shall be modified to reflect all new information obtained and to provide for future integrity assessments at the required intervals. The plan shall identify required integrity assessment actions and at what established intervals the actions will take place. All integrity assessments shall be prioritized and scheduled. Table 5.6.1-1 provides the integrity assessment schedules for the external corrosion and internal corrosion time-dependent threats for prescriptive plans. The assessment schedule for the stress corrosion cracking threat is discussed in para. A-4.4. The assessment schedules for all other threats are identified in appropriate paragraphs of Nonmandatory Appendix A titled “Assessment Interval.”A current prioritization listing and schedule shall be contained in this section of the integrity management plan. The specifics for selecting integrity assessment methods and performing the inspections are covered in section 6.
8.3 Plan Framework The integrity management plan shall contain detailed information regarding each of the following elements for each threat analyzed and each pipeline segment or system. 8.3.1 Gathering, Reviewing, and Integrating Data. The first step in the integrity management process is to collect, integrate, organize, and review all pertinent and available data for each threat and pipeline segment. This process 28
ASME B31.8S-2016
Table 8.3.4-1 Example of Integrity Management Plan for Hypothetical Pipeline Segment (Segment Data: Line 1, Segment 3) Segment Data Pipe attributes
Design/construction
Operational
Type
Example
Pipe grade
API 5L-X42 (290 MPa)
Size
NPS 24 (DN 600)
Wall thickness
0.250 in. (6.35 mm)
Manufacturer
A. O. Smith
Manufacturer process
Low frequency
Manufacturing date
1965
Seam type
Electric resistance weld
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
Compressor discharge temperature
120°F (49°C)
Pipe wall temperature
65°F (18°C)
Gas quality
Good
Flow rate
50 MMSCFD (1.42 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 provide alternative integrity assessment, repair, and prevention methods with different implementation times than those required under the prescriptive program. These decisions shall be fully documented.
fied as new information is obtained and shall be a real-time aspect of the plan (see section 7). Tables 8.3.4-1, 8.3.4-2, and 8.3.4-3 provide an example of an integrity management plan in a spreadsheet format for a hypothetical pipeline segment (line 1, segment 3). This spreadsheet shows the segment data, the integrity assessment plan devised based on the risk assessment, and the mitigation plan that would be implemented including the reassessment interval.
8.3.4 Responses to Integrity Assessment, Mitigation (Repair and Prevention), and Intervals. The plan shall specify how and when the operator will respond to integrity assessments. The responses shall be immediate, scheduled, or monitored. The mitigation element of the plan consists of two parts. The first part is the repair of the pipeline. Based on the results of the integrity assessments and the threat being addressed, appropriate repair activities shall be determined and conducted. These repairs shall be performed in accordance with accepted standards and operating practices. The second part of mitigation is prevention. Prevention can stop or slow down future deterioration of the pipeline. Prevention is also an appropriate activity for time-independent threats. All mitigation activities shall be prioritized and scheduled. The prioritization and schedule shall be modi-
9 PERFORMANCE PLAN 9.1 Introduction This section provides the performance plan requirements that apply to both prescriptive-based and performance-based integrity management programs. Integrity management plan evaluations shall be performed at least annually to provide a continuing measure of integrity management program effectiveness over time. Such evaluations should consider both threat-specific and aggregate improvements. Threat-specific evaluations may apply to a particular area of concern, while
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Table 8.3.4-2 Example of Integrity Management Plan for Hypothetical Pipeline Segment (Integrity Assessment Plan: Line 1, Segment 3) Integrity Assessment
Interval, yr
Threat
Criteria/Risk Assessment
External corrosion
Some external corrosion history, no in-line inspection
Conduct hydrostatic test, perform in-line inspection, or perform direct assessment
Replace/repair locations where CFP below 1.25 times the MAOP
10
Internal corrosion
No history of IC issues, no inline inspection
Conduct hydrostatic test, perform in-line inspection, or perform direct assessment
Replace/repair locations where CFP below 1.25 times the MAOP
10
SCC
Have found SCC of near critical dimension
Conduct hydrostatic test
Replace pipe at test failure locations
3–5
Manufacturing
ERW pipe, joint factor <1.0, no hydrostatic test
Conduct hydrostatic test
Replace pipe at test failure locations
N/A
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- or outside-forcerelated issues
None required
N/A
N/A
overall measures apply to all pipelines under the integrity management program. Program evaluation will help an operator answer the following questions: (a) Were all integrity management program objectives accomplished? (b) Were pipeline integrity and safety effectively improved through the integrity management program?
Mitigation
Table 8.3.4-3 Example of Integrity Management Plan for Hypothetical Pipeline Segment (Mitigation Plan: Line 1, Segment 3) Example
Any hydrostatic test failure will be repaired by replacement of the entire joint of pipe.
Prevention
Prevention activities will include further monitoring for SCC at susceptible locations, review of the cathodic protection design and levels, and monitoring for selective seam corrosion when the pipeline is exposed.
9.2 Performance Measures Characteristics Performance measures focus attention on the integrity management program results that demonstrate improved safety has been attained. The measures provide an indication of effectiveness but are not absolute. Performance measure evaluation and trending can also lead to recognition of unexpected results that may include the recognition of threats not previously identified. All performance measures shall be simple, measurable, attainable, relevant, and permit timely evaluations. Proper selection and evaluation of performance measures is an essential activity in determining integrity management program effectiveness. Performance measures should be selected carefully to ensure that they are reasonable program effectiveness indicators. Change shall be monitored so the measures will remain effective over time as the plan matures. The time required to obtain sufficient data for analysis shall also be considered when selecting performance measures. Methods shall be implemented to permit both short- and long-term performance measure evaluations. Integrity management program performance measures can generally be categorized into groups.
Description
Repair
Interval for The interval for reinspection will be 3 yr reinspection if there was a failure caused by SCC. The interval will be 5 yr if the test was successful. Data integration
Test failures for reasons other than external or internal corrosion, SCC, or seam defect must be considered when performing risk assessment for the associated threat.
GENERAL NOTE: For this pipeline segment, hydrostatic testing will be conducted. Selection of this method is appropriate due to its ability to address the internal and external corrosion threats as well as the manufacturing threat and the SCC threat. The test pressure will be at 1.39 times the MAOP.
9.2.1 Process or Activity Measures. Process or activity measures can be used to evaluate prevention or mitigation activities. These measures determine how well an operator is implementing various elements of the integrity management program. Measures relating to process or activity shall be selected carefully to permit performance evaluation within a realistic time frame. 9.2.2 Operational Measures. Operational measures include operational and maintenance trends that measure how well the system is responding to the integrity management program. An example of such a measure 30
ASME B31.8S-2016
Table 9.2.3-1 Performance Measures Measurement Category
Lagging Measures
Leading Measures
Process/activity measures
Pipe damage found per location excavated
Number of excavation notification requests, number of patrol detects
Operational measures
Number of significant ILI corrosion anomalies
New rectifiers and ground beds installed, CP current demand change, reduced CIS fault detects
Direct integrity measures
Leaks per mile (km) in an integrity management program
Change in leaks per mile (km)
might be the changes in corrosion rates due to the implementation of a more effective CP program. The number of third-party pipeline hits after the implementation of prevention activities, such as improving the excavation notification process within the system, is another example.
(2) number of immediate repairs completed as a result of the integrity management inspection program (the total number of immediate actionable anomaly repairs made to a pipeline as a consequence of the integrity management plan inspections, anywhere on the pipeline. Only repairs physically made to the pipe are considered repairs. For this metric, coating repairs are not considered repairs. Each actionable anomaly repaired shall be counted when a repair method is used that repairs multiple anomalies in a single repair area.) (3) number of scheduled repairs completed as a result of the integrity management inspection program [the total number of scheduled actionable anomaly repairs. See explanation for (2).] (4) number of leaks, failures, and incidents (classified by cause) (c) For operators implementing performance-based programs, the threat-specific metrics shown in Nonmandatory Appendix A shall be considered, although others may be used that are more appropriate to the specific performance-based program. In addition to the four metrics above, the operator should choose three or four metrics that measure the effectiveness of the performance-based program. Table 9.4-2 provides a suggested list; however, the operator may develop their own set of metrics. It may be appropriate and useful for operators to normalize the findings, events, and occurrences listed in Table 9.4-2 utilizing normalization factors meaningful to the operator for that event and their system, and that would help them evaluate trends. Such normalization factors may include covered pipeline length, number of customers, time, or a combination of these or others. Since performance-based inspection intervals will be utilized in a performance-based integrity management program, it is essential that sufficient metric data be collected to support those inspection intervals. Program evaluation shall be performed on at least an annual basis. (d) In addition to performance metric data collected directly from segments covered by the integrity management program, internal benchmarking can be conducted that may compare a segment against another adjacent segment or those from a different area of the same pipeline system. The information obtained may be used to evaluate the effectiveness of prevention activities, mitigation
9.2.3 Direct Integrity Measures. Direct integrity measures include leaks, ruptures, injuries, and fatalities. In addition to the above categories, performance measures can be categorized as leading measures or lagging measures. Lagging measures are reactive in that they provide an indication of past integrity management program performance. Leading measures are proactive; they provide an indication of how the plan may be expected to perform. Several examples of performance measures classified as described above are illustrated in Table 9.2.3-1.
9.3 Performance Measurement Methodology An operator can evaluate a system’s integrity management program performance within their own system and also by comparison with other systems on an industrywide basis.
9.4 Performance Measurement: Intrasystem (a) Performance metrics shall be selected and applied on a periodic basis for the evaluation of both prescriptivebased and performance-based integrity management programs. Such metrics shall be suitable for evaluation of local and threat-specific conditions, and for evaluation of overall integrity management program performance. (b) For operators implementing prescriptive programs, performance measurement shall include all of the threat-specific metrics for each threat in Nonmandatory Appendix A (see Table 9.4-1). Additionally, the following overall program measurements shall be determined and documented: (1) number of miles (kilometers) of pipeline inspected versus program requirements [the total miles (kilometers) of pipeline inspected during the reporting period, including pipeline miles (kilometers) that were inspected as part of the integrity management plan but were not required to be inspected]
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Table 9.4-1 Performance Metrics Threats External corrosion
Performance Metrics for Prescriptive Programs 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, classified by severity
Weather-related and outside forces
Number of leaks that are weather related or due to outside force Number of repair, replacement, or relocation actions due to weather-related or outside-force threats
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Table 9.4-2 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, near misses, 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, or performance validation. Such comparisons can provide a basis to substantiate metric analyses and identify areas for improvements in the integrity management program. (e) Another technique that will provide effective information is internal auditing. Operators shall conduct periodic audits to validate the effectiveness of their integrity management programs and ensure that they have been conducted in accordance with the written plan. An audit frequency shall be established, considering the established performance metrics and their particular time base in addition to changes or modifications made to the integrity management program as it evolves. Audits may be performed by internal staff, preferably by personnel not directly involved in the administration of the integrity management program, or other resources. A list of essential audit items is provided below as a starting point in developing a company audit program. (1) A written integrity management policy and program for all the elements in Figure 2.1-2 shall be in place. (2) Written integrity management plan procedures and task descriptions are up to date and readily available. (3) Activities are performed in accordance with the plan. (4) A responsible individual has been assigned for each element. (5) Appropriate references are available to responsible individuals. (6) Individuals have received proper qualification, which has been documented. (7) The integrity management program meets the requirements of this document. (8) Required activities are documented. (9) Action items or nonconformances are closed in a timely manner. (10) The risk criteria used have been reviewed and documented.
(11) Prevention, mitigation, and repair criteria have been established, met, and documented. (f) Data developed from program-specific performance metrics, results of internal benchmarking, and audits shall be used to provide an effective basis for evaluation of the integrity management program.
9.5 Performance Measurement: Industry Based In addition to intrasystem comparisons, external comparisons can provide a basis for performance measurement of the integrity management program. This can include comparisons with other pipeline operators, industry data sources, and jurisdictional data sources. Benchmarking with other gas pipeline operators can be useful; however, any performance measure or evaluation derived from such sources shall be carefully evaluated to ensure that all comparisons made are valid. Audits conducted by outside entities can also provide useful evaluation data.
9.6 Performance Improvement The results of the performance measurements and audits shall be utilized to modify the integrity management program as part of a continuous improvement process. Internal and external audit results are performance measures that should be used to evaluate effectiveness in addition to other measures stipulated in the integrity management program. Recommendations for changes and/or improvements to the integrity management program shall be based on analysis of the performance measures and audits. The results, recommendations, and resultant changes made to the integrity management program shall be documented.
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committees, jurisdictional emergency planning offices, etc. (2) company name and contact numbers, both routine and emergency (3) local maps (4) facility description and commodity transported (5) how to recognize, report, and respond to a leak (6) general information about the operator’s prevention and integrity measures, and how to obtain a summary of the integrity management plan (7) station locations and descriptions (8) summary of operator’s emergency capabilities (9) coordination of operator’s emergency preparedness with local officials (d) General Public (1) information regarding operator’s efforts to support excavation notification and other damage prevention initiatives (2) company name, contact, and emergency reporting information, including general business contact It is expected that some dialogue may be necessary between the operator and the public in order to convey the operator’s confidence in the integrity of the pipeline, as well as to convey the operator’s expectations of the public as to where they can help maintain integrity. Such opportunities should be welcomed in order to help protect assets, people, and the environment.
10 COMMUNICATIONS PLAN 10.1 General The operator shall develop and implement a communications plan in order to keep appropriate company personnel, jurisdictional authorities, and the public informed about their integrity management efforts and the results of their integrity management activities. The information may be communicated as part of other required communications. Some of the information should be communicated routinely. Other information may be communicated upon request. Use of industry, jurisdictional, and company websites may be an effective way to conduct these communication efforts. Communications should be conducted as often as necessary to ensure that appropriate individuals and authorities have current information about the operator’s system and their integrity management efforts. It is recommended that communications take place periodically and as often as necessary to communicate significant changes to the integrity management plan. API RP 1162, Public Awareness Programs for Pipeline Operators, provides additional guidance.
10.2 External Communications The following items should be considered for communication to the various interested parties: (a) Landowners and Tenants Along the Rights-of-Way (1) company name, location, and contact information (2) general location information and where more specific location information or maps can be obtained (3) commodity transported (4) how to recognize, report, and respond to a leak (5) contact phone numbers, both routine and emergency (6) general information about the pipeline operator’s prevention, integrity measures, and emergency preparedness, and how to obtain a summary of the integrity management plan (7) damage prevention information, including excavation notification numbers, excavation notification center requirements, and who to contact if there is any damage (b) Public Officials Other Than Emergency Responders (1) periodic distribution to each municipality of maps and company contact information (2) summary of emergency preparedness and integrity management program (c) Local and Regional Emergency Responders (1) operator should maintain continuing liaison with all emergency responders, including local emergency planning commissions, regional and area planning
10.3 Internal Communications Operator management and other appropriate operator personnel must understand and support the integrity management program. This should be accomplished through the development and implementation of an internal communications aspect of the plan. Performance measures reviewed on a periodic basis and resulting adjustments to the integrity management program should also be part of the internal communications plan.
11 MANAGEMENT OF CHANGE PLAN (a) Formal management of change procedures shall be developed in order to identify and consider the impact of changes to pipeline systems and their integrity. These procedures should be flexible enough to accommodate both major and minor changes, and must be understood by the personnel that use them. Management of change shall address technical, physical, procedural, and organizational changes to the system, whether permanent or temporary. The process should incorporate planning for each of these situations and consider the unique circumstances of each. A management of change process includes the following: (1) reason for change (2) authority for approving changes
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(3) analysis of implications (4) acquisition of required work permits (5) documentation (6) communication of change to affected parties (7) time limitations (8) qualification of staff (b) The operator shall recognize that system changes can require changes in the integrity management program and, conversely, results from the program can cause system changes. The following are examples that are gas-pipeline specific but are by no means all-inclusive. (1) If a change in land use would affect either the consequence of an incident, such as increases in population near the pipeline, or a change in likelihood of an incident, such as subsidence due to underground mining, the change must be reflected in the integrity management plan and the threats re-evaluated accordingly. (2) If the results of an integrity management program inspection indicate the need for a change to the system, such as changes to the CP program or, other than temporary reductions in operating pressure, these shall be communicated to operators and reflected in an updated integrity management program. (3) If an operator decides to increase pressure in the system from its historical operating pressure to, or closer to, the allowable MAOP, that change shall be reflected in the integrity plan and the threats shall be re-evaluated accordingly. (4) If a line has been operating in a steady-state mode and a new load on the line changes the mode of operation to a more cyclical load (e.g., daily changes in operating pressure), fatigue shall be considered in each of the threats where it applies as an additional stress factor. (c) Along with management, the review procedure should require involvement of staff that can assess safety impact and, if necessary, suggest controls or modifications. The operator shall have the flexibility to maintain continuity of operation within established safe operating limits. (d) Management of change ensures that the integrity management process remains viable and effective as changes to the system occur and/or new, revised, or corrected data becomes available. Any change to equipment or procedures has the potential to affect pipeline integrity. Most changes, however small, will have a consequent effect on another aspect of the system. For example, many equipment changes will require a corresponding technical or procedural change. All changes shall be identified and reviewed before implementation. Management of change procedures provides a means of maintaining order during periods of change in the system and helps to preserve confidence in the integrity of the pipeline. (e) In order to ensure the integrity of a system, a documented record of changes should be developed and maintained. This information will provide a better
understanding of the system and possible threats to its integrity. It should include the process and design information both before and after the changes were put into place. (f) Communication of the changes carried out in the pipeline system to any affected parties is imperative to the safety of the system. As provided in section 10, communications regarding the integrity of the pipeline should be conducted periodically. Any changes to the system should be included in the information provided in communication from the pipeline operator to affected parties. (g) System changes, particularly in equipment, may require qualification of personnel for the correct operation of the new equipment. In addition, refresher training should be provided to ensure that facility personnel understand and adhere to the facility’s current operating procedures. (h) The application of new technologies in the integrity management program and the results of such applications should be documented and communicated to appropriate staff and stakeholders.
12 QUALITY CONTROL PLAN This section describes the quality control activities that shall be part of an acceptable integrity management program.
12.1 General Quality control as defined for this Code is the documented proof that the operator meets all the requirements of their integrity management program. Pipeline operators that have a quality control program that meets or exceeds the requirements in this section can incorporate the integrity management program activities within their existing plan. For those operators who do not have a quality program, this section outlines the basic requirements of such a program.
12.2 Quality Management Control (a) Requirements of a quality control program include documentation, implementation, and maintenance. The following six activities are usually required: (1) Identify the processes that will be included in the quality program. (2) Determine the sequence and interaction of these processes. (3) Determine the criteria and methods needed to ensure that both the operation and control of these processes are effective. (4) Provide the resources and information necessary to support the operation and monitoring of these processes. (5) Monitor, measure, and analyze these processes. (6) Implement actions necessary to achieve planned results and continued improvement of these processes. 35
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ð16Þ
Figure 13-1 Hierarchy of Terminology for Integrity Assessment
(b) Specifically, activities to be included in the quality control program are as follows: (1) The operator shall determine the documentation required and include it in the quality program. These documents shall be controlled and maintained at appropriate locations for the duration of the program. Examples of documented activities include risk assessments, the integrity management plan, integrity management reports, and data documents. (2) The responsibilities and authorities under this program shall be clearly and formally defined. (3) Results of the integrity management program and the quality control program shall be reviewed at predetermined intervals, and making recommendations for improvement. (4) The personnel involved in the integrity management program shall be competent, aware of the program and all of its activities, and be qualified to execute the activities within the program. Documentation of such competence, awareness, and qualification, and the processes for their achievement shall be part of the quality control plan. (5) The operator shall determine how to monitor the integrity management program to show that it is being
implemented according to plan and document these steps. These control points, criteria, and/or performance metrics shall be defined. (6) Periodic internal audits or independent thirdparty reviews of the integrity management program and its quality plan are required. (7) Corrective actions to improve the integrity management program or quality plan shall be documented and the effectiveness of their implementation monitored. (c) When an operator chooses to use outside resources to conduct any process (for example, pigging) that affects the quality of the integrity management program, the operator shall ensure control of such processes and document them within the quality program.
13 TERMS, DEFINITIONS, AND ACRONYMS See Figure 13-1 for the hierarchy of terminology for integrity assessment. actionable anomalies: anomalies that may exceed acceptable limits based on the operator’s anomaly and pipeline data analysis. 36
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active corrosion: corrosion that is continuing or not arrested.
cathodic protection (CP): technique to reduce the corrosion of a metal surface by making that surface the cathode of an electromechanical cell.
annular filled saddle: an external steel fabrication similar to a sleeve except one half is pierced and forged to provide a close fit around a hot tap “T.” The other half away from the “T” is joined with seam welds like a type A sleeve. The annular space between the pressure-containing pipes and the saddle is filled with an incompressible material to provide mechanical support to the welded “T.”
certification: written testimony of qualification. characterize: to qualify the type, size, shape, orientation, and location of an anomaly. close interval survey (CIS): inspection technique that includes a series of aboveground pipe-to-soil potential measurements taken at predetermined increments of a few to several feet (meters) along the pipeline and used to provide information on the effectiveness of the cathodic protection system.
anomaly: an unexamined deviation from the norm in pipe material, coatings, or welds. anomaly and pipeline data analysis: the process through which anomaly and pipeline data are integrated and analyzed to further classify and characterize anomalies.
coating: liquid, liquefiable, or mastic composition that, after application to a surface, is converted into a solid protective, decorative, or functional adherent film. Coating also includes tape wrap.
arc welding or arc weld: group of welding processes that produces coalescence by heating them with an arc. The processes are used with or without the application of pressure and with or without filler metal.
coating system: complete number and types of coats applied to a substrate in a predetermined order. (When used in a broader sense, surface preparation, pretreatments, dry film thickness, and manner of application are included.)
backfill: material placed in a hole or trench to fill excavated space around a pipeline or other appurtenances. batch: a volume of liquid that flows en masse in a pipeline physically separated from adjacent volume(s) of liquid or gas. [Sealing (batching) pigs are typically used for separation.]
component or pipeline component: an individual item or element fitted in line with pipe in a pipeline system, such as, but not limited to, valves, elbows, tees, flanges, and closures.
bell hole: excavation that minimizes surface disturbance yet provides sufficient room for examination or repair of buried facilities.
composite repair sleeve: permanent repair method using composite sleeve material, which is applied with an adhesive.
buckle: condition in which the pipeline has undergone sufficient plastic deformation to cause permanent wrinkling in the pipe wall or excessive cross-sectional deformation caused by bending, axial, impact, and/or torsional loads acting alone or in combination with hydrostatic pressure.
consequence: impact that a pipeline failure could have on the public, employees, property, and the environment. corrosion: deterioration of a material, usually a metal, that results from an electrochemical reaction with its environment.
butt joint: a joint between two members aligned approximately in the same plane. See Figs. 1(A), 2(A), 3, 51(A), and 51(B) in AWS A3.0.
corrosion inhibitor: chemical substance or combination of substances that, when present in the environment or on a surface, prevents or reduces corrosion.
butt weld: a nonstandard term for a weld in a butt joint.
corrosion rate: rate at which corrosion proceeds.
calibration dig: exploratory excavation to validate findings of an in-line inspection tool with the purpose of improving data interpretation.
crack: very narrow, elongated defect caused by mechanical splitting into two parts.
caliper tool or geometry tool: an instrumented in-line inspection tool designed to record conditions, such as dents, wrinkles, ovality, bend radius, and angle, by sensing the shape of the internal surface of the pipe.
data analysis: the evaluation process through which inspection indications are classified and characterized.
current: flow of electric charge.
defect: a physically examined anomaly with dimensions or characteristics that exceed acceptable limits.
carbon dioxide: a heavy, colorless gas that does not support combustion, dissolves in water to form carbonic acid, and is found in some natural gas streams.
dent: permanent deformation of the circular cross section of the pipe that produces a decrease in the diameter and is concave inward.
cast iron: unqualified term “cast iron” shall apply to gray cast iron, which is a cast ferrous material in which a major part of the carbon content occurs as free carbon in the form of flakes interspersed throughout the metal.
detect: to sense or obtain measurable wall loss indications from an anomaly in a steel pipeline using in-line inspection or other technologies.
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diameter or nominal outside diameter: as-produced or asspecified outside diameter of the pipe, not to be confused with the dimensionless NPS (DN). For example, NPS 12 (DN 300) pipe has a specified outside diameter of 12.750 in. (323.85 mm), NPS 8 (DN 200) pipe has a specified outside diameter of 8.625 in. (219.08 mm), and NPS 24 (DN 600) pipe has a specified outside diameter of 24.000 in. (609.90 mm).
epoxy: type of resin formed by the reaction of aliphatic or aromatic polyols (like bisphenol) with epichlorohydrin and characterized by the presence of reactive oxirane end groups. evaluation: a review following the characterization of an actionable anomaly to determine whether the anomaly meets specified acceptance criteria. examination: direct physical inspection of a pipeline that may include the use of nondestructive examination (NDE) techniques or methods.
direct current voltage gradient (DCVG): inspection technique that includes aboveground electrical measurements taken at predetermined increments along the pipeline and is used to provide information on the effectiveness of the coating system.
experience: work activities accomplished in a specific NDT method under the direction of qualified supervision including the performance of the NDT method and related activities but not including time spent in organized training programs.
discontinuity: an interruption of the typical structure of a material, such as a lack of homogeneity in its mechanical, metallurgical, or physical characteristics. A discontinuity is not necessarily a defect.
failure: general term used to imply that a part in service has become completely inoperable; is still operable but is incapable of satisfactorily performing its intended function; or has deteriorated seriously to the point that it has become unreliable or unsafe for continued use.
documented: condition of being in written form. double submerged-arc welded pipe (DSAW pipe): pipe that has a straight longitudinal or helical seam containing filler metal deposited on both sides of the joint by the submerged-arc welded process.
fatigue: process of development of or enlargement of a crack as a result of repeated cycles of stress.
ductility: measure of the capability of a material to be deformed plastically before fracturing.
feature: any physical object detected by an in-line inspection system. Features may be anomalies, components, nearby metallic objects, welds, or some other item.
electric-resistance-welded pipe (ERW pipe): pipe that has a straight longitudinal seam produced without the addition of filler metal by the application of pressure and heat obtained from electrical resistance. ERW pipe forming is distinct from flash welded pipe and furnace buttwelded pipe as a result of being produced in a continuous forming process from coils of flat plate.
film: thin, not necessarily visible layer of material. galvanic corrosion: accelerated corrosion of a metal because of an electrical contact with a more noble metal and/or a more noble localized section of the metal or nonmetallic conductor in a corrosive electrolyte. gas: as used in this Code, any gas or mixture of gases suitable for domestic or industrial fuel and transmitted or distributed to the user through a piping system. The common types are natural gas, manufactured gas, and liquefied petroleum gas distributed as a vapor, with or without the admixture of air.
electrolyte: medium containing ions that migrate in an electric field. engineering assessment: a documented assessment, using engineering principles, of the effect of relevant variables upon service or integrity of a pipeline system, using engineering principles, and conducted by, or under the supervision of, a competent person with demonstrated understanding and experience in the application of the engineering and risk management principles related to the issue being assessed.
gas processing plant: facility used for extracting commercial products from gas. gathering system: one or more segments of pipeline, usually interconnected to form a network, that transports gas from one or more production facilities to the inlet of a gas processing plant. If no gas processing plant exists, the gas is transported to the most downstream of either of the following: (a) the point of custody transfer of gas suitable for delivery to a distribution system (b) the point where accumulation and preparation of gas from separate geographic production fields in reasonable proximity has been completed
engineering critical assessment: an analytical procedure, based upon fracture mechanics, that allows determination of the maximum tolerable sizes for imperfections, and conducted by, or under the supervision of, a competent person with demonstrated understanding and experience in the application of the engineering principles related to the issue being assessed. environment: surroundings or conditions (physical, chemical, mechanical) in which a material exists.
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geographic information system (GIS): system of computer software, hardware, data, and personnel to help manipulate, analyze, and present information that is tied to a geographic location.
integrity: defined herein as the capability of the pipeline to withstand all anticipated loads (including hoop stress due to operating pressure) plus the margin of safety established by this section.
girth weld: complete circumferential butt weld joining pipe or components.
integrity assessment: process that includes inspection of pipeline facilities, evaluating the indications resulting from the inspections, examining the pipe using a variety of techniques, evaluating the results of the examinations, characterizing the evaluation by defect type and severity, and determining the resulting integrity of the pipeline through analysis.
global positioning system (GPS): system used to identify the latitude and longitude of locations using GPS satellites. gouge: mechanically induced metal loss that causes localized elongated grooves or cavities in a metal pipeline. high-pressure distribution system: gas distribution piping system that operates at a pressure higher than the standard service pressure delivered to the customer. In such a system, a service regulator is required on each service line to control the pressure delivered to the customer.
launcher: pipeline facility used to insert a pig into a pressurized pipeline, sometimes referred to as a “pig trap.” leak: unintentional escape of gas from the pipeline. The source of the leak may be holes, cracks (include propagating and nonpropagating, longitudinal, and circumferential), separation or pullout, and loose connections.
hydrogen-induced damage: form of degradation of metals caused by exposure to environments (liquid or gas) that allows absorption of hydrogen into the material. Examples of hydrogen-induced damage are formation of internal cracks, blisters, or voids in steels; embrittlement (i.e., loss of ductility); and high-temperature hydrogen attack (i.e., surface decarburization and chemical reaction with hydrogen).
length: a piece of pipe of the length delivered from the mill. Each piece is called a length, regardless of its actual dimension. This is sometimes called a “joint,” but “length” is preferred. liquefied petroleum gas(es) (LPG): liquid petroleum gases composed predominantly of the following hydrocarbons, either by themselves or as mixtures: butane (normal butane or isobutane), butylene (including isomers), propane, propylene, and ethane. LPG can be stored as liquids under moderate pressures [approximately 80 psig to 250 psig (550 kPa to 1 720 kPa)] at ambient temperatures.
hydrogen sulfide (H2S): toxic gaseous impurity found in some well gas streams. It also can be generated in situ as a result of microbiologic activity. hydrostatic test or hydrotest: a pressure test using water as the test medium. imperfection: an anomaly with characteristics that do not exceed acceptable limits.
inclusion: nonmetallic phase such as an oxide, sulfide, or silicate particle in a metal pipeline.
low-pressure distribution system: gas distribution piping system in which the gas pressure in the mains and service lines is substantially the same as that delivered to the customer’s appliances. In such a system, a service regulator is not required on the individual service lines.
indication: finding of a nondestructive testing technique or method that deviates from the expected. It may or may not be a defect.
low-stress pipeline: pipeline that is operated in its entirety at a hoop stress level of 20% or less of the specified minimum yield strength of the line pipe.
in-line inspection (ILI): steel pipeline inspection technique that uses devices known in the industry as intelligent or smart pigs. These devices run inside the pipe and provide indications of metal loss, deformation, and other defects.
magnetic flux leakage (MFL): an in-line inspection technique that induces a magnetic field in a pipe wall between two poles of a magnet. Sensors record status in leakage in this magnetic flux (flow) outside the pipe wall, which can be correlated to metal loss.
incident: unintentional release of gas due to the failure of a pipeline.
in-line inspection tools: any instrumented device or vehicle that records data and uses nondestructive test methods or other techniques to inspect the pipeline from the inside. These tools are also known as intelligent pigs or smart pigs.
magnetic particle inspection (MPI): a nondestructive test method utilizing magnetic leakage fields and suitable indicating materials to disclose surface and near-surface discontinuity indications. management of change: process that systematically recognizes and communicates to the necessary parties changes of a technical, physical, procedural, or organizational nature that can impact system integrity.
in-service pipeline: defined herein as a pipeline that contains natural gas to be transported. The gas may or may not be flowing. inspection: use of a nondestructive testing technique or method.
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maximum allowable operating pressure (MAOP): maximum pressure at which a pipeline system may be operated in accordance with the provisions of the ASME B31.8 Code.
pipeline: all parts of physical facilities through which gas moves in transportation, including pipe, valves, fittings, flanges (including bolting and gaskets), regulators, pressure vessels, pulsation dampeners, relief valves, appurtenances attached to pipe, compressor units, metering facilities, pressure-regulating stations, pressure-limiting stations, pressure relief stations, and fabricated assemblies. Included within this definition are gas transmission and gathering lines, which transport gas from production facilities to onshore locations, and gas storage equipment of the closed-pipe type that is fabricated or forged from pipe or fabricated from pipe and fittings.
mechanical damage: type of metal damage in a pipe or pipe coating caused by the application of an external force. Mechanical damage can include denting, coating removal, metal removal, metal movement, cold working of the underlying metal, puncturing, and residual stresses. metal loss: types of anomalies in pipe in which metal has been removed from the pipe surface, usually due to corrosion or gouging.
pipeline facility: new and existing pipelines, rights-of-way, and any equipment, facility, or building used in the transportation of gas or in the treatment of gas during the course of transportation.
microbiologically influenced corrosion (MIC): corrosion or deterioration of metals resulting from the metabolic activity of microorganisms. Such corrosion may be initiated or accelerated by microbial activity.
pipeline section: continuous run of pipe between adjacent compressor stations, between a compressor station and a block valve, or between adjacent block valves.
mitigation: limitation or reduction of the probability of occurrence or expected consequence for a particular event.
pipe-to-soil potential: electric potential difference between the surface of a buried or submerged metallic structure and the electrolyte that is measured with reference to an electrode in contact with the electrolyte.
municipality: city, county, or any other political subdivision of a state. nondestructive examination (NDE) or nondestructive testing (NDT): testing method, such as radiography, ultrasonic, magnetic testing, liquid penetrant, visual, leak testing, eddy current, and acoustic emission, or a testing technique, such as magnetic flux leakage, magnetic particle inspection, shear-wave ultrasonic, and contact compression-wave ultrasonic.
piping and instrumentation diagram (P&ID): drawing showing the piping and instrumentation for a pipeline or pipeline facility.
operating stress: stress in a pipe or structural member under normal operating conditions.
predicted failure pressure, Pf : an internal pressure that is used to prioritize a defect as immediate, scheduled, or monitored. See the detail explanation with Figure 7.2.1-1. The failure pressure is calculated utilizing ASME B31G or similar method when the design factor, F, is set to unity.
pitting: localized corrosion of a metal surface that is confined to a small area and takes the form of cavities called pits.
operator or operating company: individual, partnership, corporation, public agency, owner, agent, or other entity currently responsible for the design, construction, inspection, testing, operation, and maintenance of the pipeline facilities.
prescriptive integrity management program: integrity management process that follows preset conditions that result in fixed inspection and mitigation activities and timelines.
performance-based integrity management program: integrity management process that utilizes risk management principles and risk assessments to determine prevention, detection, and mitigation actions and their timing.
pressure: unless otherwise stated, pressure is expressed in pounds per square inch (kilopascals) above atmospheric pressure (i.e., gage pressure), and is abbreviated as psig (kPa).
pig: device run inside a pipeline to clean or inspect the pipeline, or to batch fluids. pigging: use of any independent, self-contained device, tool, or vehicle that moves through the interior of the pipeline for inspecting, dimensioning, cleaning, or drying.
pressure test: means by which the integrity of a piece of equipment (pipe) is assessed, in which the item is filled with a fluid, sealed, and subjected to pressure. It is used to validate integrity and detect construction defects and defective materials.
pipe: a tubular product, including tubing, made for sale as a production item, used primarily for conveying a fluid and sometimes for storage. Cylinders formed from plate during the fabrication of auxiliary equipment are not pipe as defined herein.
probability: likelihood of an event occurring. qualification: demonstration and documented knowledge, skills, and abilities, along with documented training and/ or experience required for personnel to properly perform the duties of a specific job or task.
pipe grade: portion of the material specification for pipe, which includes specified minimum yield strength. 40
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receiver: pipeline facility used for removing a pig from a pressurized pipeline; sometimes referred to as a “pig trap.”
rupture: complete failure of any portion of the pipeline that allows the product to escape to the environment.
resident threat: a manufacturing-, welding/fabrication-, or equipment-related imperfection that if not acted upon by a time-dependent or time-independent threat, remains dormant and does not deteriorate with time.
rust: corrosion product consisting of various iron oxides and hydrated iron oxides (this term properly applies only to iron and ferrous alloys). seam weld: longitudinal or helical seam in pipe that is made in the pipe mill for the purpose of making a complete circular cross section.
residual stress: stress present in an object in the absence of any external loading, typically resulting from manufacturing or construction processes.
segment: length of pipeline or part of the system that has unique characteristics in a specific geographic location.
resistivity: (a) resistance per unit length of a substance with uniform cross section (b) measure of the ability of an electrolyte (e.g., soil) to resist the flow of electric charge (e.g., cathodic protection current) Resistivity data are used to design a groundbed for a cathodic protection system.
sensors: devices that receive a response to a stimulus (e.g., an ultrasonic sensor detects ultrasound). shall: “shall” and “shall not” are used to indicate that a provision is mandatory. shielding: preventing or diverting the flow of cathodic protection current from its natural path.
rich gas: gas that contains significant amounts of hydrocarbons or components that are heavier than methane and ethane. Rich gases decompress in a different fashion than pure methane or ethane.
should: “should,” “should not,” and “it is recommended” are used to indicate that a provision is not mandatory but recommended as good practice. sizing accuracy: given by the interval within which a fixed percentage of all metal-loss features will be sized. The fixed percentage is stated as the confidence level.
right-of-way (ROW): strip of land on which pipelines, railroads, power lines, roads, highways, and other similar facilities are constructed. The ROW agreement secures the right to pass through property owned by others. ROW agreements generally allow the right of ingress and egress for the operation and maintenance of the facility, and the installation of the facility. The ROW width can vary with the construction and maintenance requirements of the facility’s operator and is usually determined based on negotiation with the affected landowner, by legal action, or by permitting authority.
smart pig: see in-line inspection tools. soil liquefaction: soil condition, typically caused by dynamic cyclic loading (e.g., earthquake, waves) where the effective shear strength of the soil is reduced such that the soil exhibits the properties of a liquid. specified minimum yield strength (SMYS): expressed in pounds per square inch (MPa), minimum yield strength prescribed by the specification under which pipe is purchased from the manufacturer.
risk: measure of potential loss in terms of both the incident probability (likelihood) of occurrence and the magnitude of the consequences.
storage field: geographic field containing a well or wells that are completed for and dedicated to subsurface storage of large quantities of gas for later recovery, transmission, and end use.
risk assessment: systematic process in which potential hazards from facility operation are identified, and the likelihood and consequences of potential adverse events are estimated. Risk assessments can have varying scopes, and can be performed at varying levels of detail depending on the operator’s objectives (see section 5).
strain: change in length of a material in response to an applied force, expressed on a unit length basis (e.g., inches per inch or millimeters per millimeter). stress: internal resistance of a body to an external applied force, expressed in units of force per unit area (psi or MPa). It may also be termed “unit stress.”
risk management: overall program consisting of identifying potential threats to an area or equipment; assessing the risk associated with those threats in terms of incident likelihood and consequences; mitigating risk by reducing the likelihood, the consequences, or both; and measuring the risk reduction results achieved.
stress corrosion cracking (SCC): form of environmental attack of the metal involving an interaction of a local corrosive environment and tensile stresses in the metal, resulting in formation and growth of cracks.
root cause analysis: family of processes implemented to determine the primary cause of an event. These processes all seek to examine a cause-and-effect relationship through the organization and analysis of data. Such processes are often used in failure analyses.
stress level: level of tangential or hoop stress, usually expressed as a percentage of specified minimum yield strength. subject matter experts: individuals that have expertise in a specific area of operation or engineering.
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submerged arc welding: arc welding process that uses an arc or arcs between a bare metal electrode or electrodes and the weld pool. The arc and molten metal are shielded by a blanket of granular flux on the workpieces. The process is used without pressure and with filler metal from the electrode and sometimes from a supplemental source (welding rod, flux, or metal granules).
wrinkle bend: pipe bend produced by field machine or controlled process that may result in prominent contour discontinuities on the inner radius. The wrinkle is deliberately introduced as a means of shortening the inside meridian of the bend. Note that this definition does not apply to a pipeline bend in which incidental minor, smooth ripples are present.
survey: measurements, inspections, or observations intended to discover and identify events or conditions that indicate a departure from normal operation or undamaged condition of the pipeline.
14 REFERENCES AND STANDARDS The following is a list of publications that support or are referenced in this Standard. The references shall be to the specific editions cited below, except the user may use the latest published edition of ANSI-approved standards unless specifically prohibited by this Standard, and provided the user has reviewed the latest edition of the standard to ensure that the integrity of the pipeline system is not compromised. If a newer or amended edition of a standard is not ANSI approved, then the user shall use the specific edition reference date shown herein. An asterisk (*) is used to indicate that the specific edition of the standard has been accepted as an American National Standard by the American National Standards Institute (ANSI).
system or pipeline system: either the operator’s entire pipeline infrastructure or large portions of that infrastructure that have definable starting and stopping points. temperature: expressed in degrees Fahrenheit (°F) [degrees Celsius (°C)]. tensile stress: applied pulling force divided by the original cross-sectional area. third-party damage: damage to a gas pipeline facility by an outside party other than those performing work for the operator. For the purposes of this Code, this also includes damage caused by the operator’s personnel or the operator’s contractors.
*ANSI/GPTC-Z380-TR-1 (November 2001), Review of Integrity Management for Natural Gas Transmission Pipelines Publisher: Gas Piping Technology Committee (GPTC) of the American Gas Association (AGA), 400 North Capitol Street, NW, Washington, DC 20001 (www.aga.org)
tool: generic term signifying any type of instrumented tool or pig. training: organized program developed to impart the knowledge and skills necessary for qualification. transmission line: segment of pipeline installed in a transmission system or between storage fields.
*ANSI/ISO/ASQ Q9004-2009,Quality Management Systems: Managing for the Sustained Success of an Organization Juran’s Quality Handbook (sixth edition, 2010) Publisher: American Society for Quality (ASQ), 600 North Plankinton Avenue, Milwaukee, WI 53203 (www.asq.org)
transmission system: one or more segments of pipeline, usually interconnected to form a network, that transports gas from a gathering system, the outlet of a gas processing plant, or a storage field to a high- or low-pressure distribution system, a large-volume customer, or another storage field. transportation of gas: gathering, transmission, or distribution of gas by pipeline or the storage of gas.
*API RP 1110 (sixth edition, February 2013), Recommended Practice for the Pressure Testing of Steel Pipelines for the Transportation of Gas, Petroleum Gas, Hazardous Liquids, Highly Volatile Liquids, or Carbon Dioxide API RP 1162 (second edition, December 2010), Recommended Practice, Public Awareness Programs for Pipeline Operators *API Std 1160 (first edition, November 2001; reaffirmed November 2008), Managing System Integrity for Hazardous Liquid Pipelines *API Std 1163 (second edition, April 2013), In-Line Inspection Systems Qualification Publisher: American Petroleum Institute (API), 1220 L Street, NW, Washington, DC 20005 (www.api.org)
ultrasonic: high-frequency sound. Ultrasonic examination is used to determine wall thickness and to detect the presence of defects. uprating: qualifying of an existing pipeline or main for a higher maximum allowable operating pressure. weld: localized coalescence of metals or nonmetals produced by heating the materials to the welding temperature, with or without the application of pressure, or by the application of pressure alone and with or without the use of filler material. welding procedures: detailed methods and practices involved in the production of a weldment.
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*ASME B31.8-2012, Gas Transmission and Distribution Piping Systems *ASME B31G-2012, Manual for Determining the Remaining Strength of Corroded Pipelines: Supplement to ASME B31 Code for Pressure Piping ASME CRTD-Vol. 40-1, Risk-Based Inservice Testing — Development of Guidelines, Volume 1: General Document (2000) ASME Research Report, History of Line Pipe Manufacturing in North America (1996) ASME STP-PT-011, Integrity Management of Stress Corrosion Cracking in Gas Pipeline High Consequence Areas, October 31, 2008 IPC2002-27131, “Qualification of Procedures for Welding Onto In-Service Pipelines,” Proceedings of IPC2002, 4th International Pipeline Conference, September 2002 IPC2006-10163, “Method for Establishing Hydrostatic ReTest Intervals for Pipelines With Stress-Corrosion Cracking,” Proceedings of IPC2006, 6th International Pipeline Conference, September 2006 IPC2006-10299, “Comparison of Methods for Predicting Safe Parameters for Welding Onto In-Service Pipelines,” Proceedings of IPC2006, 6th International Pipeline Conference, September 2006 IPC2008-64353, “Improved Burnthrough Prediction 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 ,” Proceedings of IPC2008, 7th International Pipeline Conference, September 2008 Publisher: The American Society of Mechanical Engineers (ASME), Two Park Avenue, New York, NY 10016-5990 (www.asme.org)
GRI-00/0228 (2000), Cost of Periodically Assuring Pipeline Integrity in High Consequence Areas by InLine Inspection, Pressure Testing and Direct Assessment GRI-00/0230 (2000), Periodic Re-Verification Intervals for High-Consequence Areas GRI-00/0231 (2000), Direct Assessment and Validation GRI-00/0232 (2000), Leak Versus Rupture Considerations for Steel Low-Stress Pipelines GRI-00/0233 (2000), Quantifying Pipeline Design at 72% SMYS as a Precursor to Increasing the Design Stress Level GRI-00/0246 (2000), Implementation Plan for Periodic Re-Verification Intervals for High-Consequence Areas GRI-00/0247 (2000), Introduction to Smart Pigging in Natural Gas Pipelines GRI-01/0027 (2001), Pipeline Open Data Standard (PODS) GRI-01/0083 (2001), Review of Pressure Retesting for Gas Transmission Pipelines GRI-01/0084 (2001), Proposed New Guidelines for ASME B31.8 on Assessment of Dents and Mechanical Damage GRI-01/0085 (2001), Schedule of Responses to CorrosionCaused Metal Loss Revealed by Integrity-Assessment Results GRI-01/0111 (2001), Determining the Full Cost of a Pipeline Incident GRI-01/0154 (2001), Natural Gas Pipeline Integrity Management Committee Process Overview Report GRI-04/0178 (2004), Effect of Pressure Cycles on Gas Pipelines GRI-95/0228.1 (1995), Natural Gas Pipeline Risk Management, Volume I: Selected Technical Terminology GRI-95/0228.2 (1995), Natural Gas Pipeline Risk Management, Volume II: Search of Literature Worldwide on Risk Assessment/Risk Management for Loss of Containment GRI-95/0228.3 (1995), Natural Gas Pipeline Risk Management, Volume III: Industry Practices Analysis GRI-95/0228.4 (1995), Natural Gas Pipeline Risk Management, Volume IV: Identification of Risk Management Methodologies Publisher: Gas Technology Institute (GTI), 1700 South Mount Prospect Road, Des Plaines, IL 60018 (www.gastechnology.org)
*AWS A3.0:2001 (including 2001 Errata), Standard Welding Terms and Definitions, Including Terms for Adhesive Bonding, Brazing, Soldering, Thermal Cutting, and Thermal Spraying Publisher: American Welding Society (AWS), 8669 NW 36 Street, No. 130, Miami, FL 33166 (www.aws.org) Common Ground Alliance, Best Practices Version 10.0, 2013 Publisher: Common Ground Alliance (CGA), 2200 Wilson Boulevard, Suite 120–172, Arlington, VA 22201 (www.commongroundalliance.com) GRI-00/0076 (2000), Evaluation of Pipeline Design Factors GRI-00/0077 (2000), Safety Performance of Natural Gas Transmission and Gathering Systems Regulated by Office of Pipeline Safety GRI-00/0189 (2000), Model for Sizing High Consequence Areas Associated With Natural Gas Pipelines GRI-00/0192 (2000), GRI Guide for Locating and Using Pipeline Industry Research GRI-00/0193 (2000), Natural Gas Transmission Pipelines: Pipeline Integrity — Prevention, Detection & Mitigation Practices
Integrity Characteristics of Vintage Pipelines (2005) Publisher: The INGAA Foundation, Inc. (INGAA), 20 F Street, NW, Washington, DC 20001 (www.ingaa.org) NACE SP0106-2006, Control of Internal Corrosion in Steel Pipelines and Piping Systems NACE SP0169-2007, Control of External Corrosion on Underground or Submerged Metallic Piping Systems NACE SP0204-2008, Stress Corrosion Cracking (SCC) Direct Assessment Methodology 43
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NACE SP0206-2006, Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas (DG-ICDA) *NACE SP0502-2010,Pipeline External Corrosion Direct Assessment Methodology Publisher: National Association of Corrosion Engineers (NACE International), 15835 Park Ten Place, Houston, TX 77084 (www.nace.org)
PR-218-9801 (2001), Analysis of DOT Reportable Incidents for Gas Transmission and Gathering System Pipelines, 1985–1997 PR-268-9823 (2004), Guidelines for the Seismic Design and Assessment of Natural Gas and Liquid Hydrocarbon Pipelines Publisher: Pipeline Research Council International, Inc. (PRCI), 3141 Fairview Park Drive, Suite 525, Falls Church, VA 22042 (www.prci.org)
Pipeline Risk Management Manual (third edition, 2004) Publisher: Gulf Publishing Company, P.O. Box 2608, Houston, TX 77252 (www.gulfpub.com)
TTO Number 13, Integrity Management Program, Delivery Order DTRS5602-D-70036, Potential Impact Radius Formulae for Flammable Gases Other Than Natural Gas Subject to 49 CFR 192 (June 2005) TTO Number 14, Integrity Management Program, Delivery Order DTRS56-02-D-70036, Derivation of Potential Impact Radius Formulae for Vapor Cloud Dispersion Subject to 49 CFR 192 (January 2005) Publisher: Pipeline and Hazardous Materials Safety Administration (PHMSA), U.S. Department of Transportation, 1200 New Jersey Avenue, SE, Washington, DC 20590 (www.phmsa.dot.gov)
Plant Guidelines for Technical Management of Chemical Process Safety (revised edition) 1992 Publisher: Center for Chemical Process Safety (CCPS) of the American Institute of Chemical Engineers (AIChE), 120 Wall Street, Floor 23, New York, NY 10005 (www.aiche.org) PR-218-08350 (2008), Pipeline Facility Incident Data Review and Statistical Analysis
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NONMANDATORY APPENDIX A THREAT PROCESS CHARTS AND PRESCRIPTIVE INTEGRITY MANAGEMENT PLANS ð16Þ
(n) past hydrostatic test information For this threat, the data are used primarily for prioritization of integrity assessment and/or mitigation activities. Where the operator is missing data, conservative assumptions shall be used when performing the risk assessment or, alternatively, the segment shall be prioritized higher.
A-1 INTRODUCTION This Appendix provides process charts and the essentials of a prescriptive integrity management plan for the nine categories of threats listed in the main body of this Code. The required activities and intervals are not applicable for severe conditions that the operator may encounter. In those instances, more rigorous analysis and more frequent inspection may be necessary.
A-2.3 Criteria and Risk Assessment For new pipelines or pipeline segments, the operator may wish to use the original material selection, design conditions, and construction inspections, as well as the current operating history, to establish the condition of the pipe. For this situation, the operator must determine that the construction inspections have an equal or greater rigor than that provided by the prescribed integrity assessment in this Code. In no case shall the interval between construction and the first required reassessment of integrity exceed 10 yr for pipe operating above 60% SMYS, 13 yr for pipe operating above 50% SMYS and at or below 60% SMYS, 15 yr for pipe operating at or above 30% SMYS and at or below 50% SMYS, and 20 yr for pipe operating below 30% SMYS. For all pipeline segments older than those stated above, integrity assessment shall be conducted using a methodology, within the specified response interval, as provided in para. A-2.5. Previous integrity assessments can be considered as meeting these requirements, provided the inspections have equal or greater rigor than that provided by the prescribed inspections in this Code. The interval between the previous integrity assessment and the next integrity assessment cannot exceed the interval stated in this Code.
A-2 EXTERNAL CORROSION THREAT A-2.1 Scope Section A-2 provides an integrity management plan to address the threat, and methods of integrity assessment and mitigation, of external corrosion (see Figure A-2.1-1). External corrosion is defined in this context to include galvanic corrosion and microbiologically influenced corrosion (MIC). This section outlines the integrity management process for external corrosion in general and also covers some specific issues. Pipeline incident analysis has identified external corrosion among the causes of past incidents.
A-2.2 Gathering, Reviewing, and Integrating Data The following minimal data sets should be collected for each segment and reviewed before a risk assessment can be conducted. These data are collected in support of performing risk assessment and for special considerations, such as identifying severe situations requiring more or additional activities. (a) year of installation (b) coating type (c) coating condition (d) years with adequate cathodic protection (e) years with questionable cathodic protection (f) years without cathodic protection (g) soil characteristics (h) pipe inspection reports (bell hole) (i) MIC detected (yes, no, or unknown) (j) leak history (k) wall thickness (l) diameter (m) operating stress level (% SMYS)
A-2.4 Integrity Assessment The operator has a choice of three integrity assessment methods: in-line inspection with a tool capable of detecting wall loss, such as an MFL tool; performing a pressure test; or conducting direct assessment. (a) In-Line Inspection. The operator shall consult section 6, which defines the capability of various ILI devices and provides criteria for running of the tool.
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ð16Þ
Figure A-2.1-1 Integrity Management Plan, External Corrosion Threat (Simplified Process: Prescriptive)
Gathering, reviewing, and integrating data
Criteria and risk assessment
Determine assessment interval
Integrity assessment (ILI, DA, hydrotest, or other)
Responses and mitigation (repair and/or prevent)
Other information to other threats
Performance metrics
(a) In-Line Inspection. The response is dependent on the severity of corrosion as determined by calculating critical failure pressure of indications (see ASME B31G or equivalent) and a reasonably anticipated or scientifically proven rate of corrosion. Refer to section 7 for responses to integrity assessment. (b) Direct Assessment. The response is dependent on the number of indications examined, evaluated, and repaired. Refer to section 7 for responses to integrity assessment. (c) Pressure Testing. The interval is dependent on the test pressure. If the test pressure was at least 1.39 times MAOP, the interval shall be 10 yr. If the test pressure was at least 1.25 times MAOP, the interval shall be 5 yr (see section 7).
The operator selects the appropriate tools and he/she or his/her representative performs the inspection. (b) Pressure Test. The operator shall consult section 6, which defines how to conduct tests for both post-construction and in-service pipelines. The operator selects the appropriate test and he/she or his/her representative performs the test. (c) Direct Assessment. The operator shall consult section 6, which defines the process, tools, and inspections. The operator selects the appropriate tools and he/she or his/her representative performs the inspections.
A-2.5 Responses and Mitigation Responses to integrity assessments are detailed below.
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If the actual operating pressure is less than MAOP, the factors shown above can be applied to the actual operating pressure in lieu of MAOP for ensuring integrity at the reduced pressure only. The operator shall select the appropriate repair methods as outlined in section 7. The operator shall select the appropriate prevention practices as outlined in section 7.
internal microbiologically influenced corrosion (MIC; see Figure A-3.1-1). Section A-3 provides a general overview of the integrity management process for internal corrosion in general and also covers some specific issues. Pipeline incident analysis has identified internal corrosion among the causes of past incidents.
A-3.2 Gathering, Reviewing, and Integrating Data A-2.6 Other Data
The following minimal data sets should be collected for each segment and reviewed before a risk assessment can be conducted. This data are collected in support of performing risk assessment and for special considerations, such as identifying severe situations requiring more or additional activities. (a) year of installation (b) pipe inspection reports (bell hole) (c) leak history (d) wall thickness (e) diameter (f) past hydrostatic test information (g) gas, liquid, or solid analysis (particularly hydrogen sulfide, carbon dioxide, oxygen, free water, and chlorides) (h) bacteria culture test results (i) corrosion detection devices (coupons, probes, etc.) (j) operating parameters (particularly pressure and flow velocity and especially periods where there is no flow) (k) operating stress level (% SMYS) For this threat, the data are used primarily for prioritization of integrity assessment and/or mitigation activities. Where the operator is missing data, conservative assumptions shall be used when performing the risk assessment or, alternatively, the segment shall be prioritized higher.
During the inspection activities, the operator may discover other data that should be used when performing risk assessments for other threats. For example, when conducting an ILI with an MFL tool, dents may be detected on the top half of the pipe. This may have been caused by third-party damage. It is appropriate then to use this information when conducting risk assessment for the thirdparty damage threat.
A-2.7 Assessment Interval The operator is required to assess integrity periodically. The interval for assessments is dependent on the responses taken as outlined in para. A-2.5. These intervals are maximum intervals. The operator must incorporate new data into the assessment as data becomes available and that may require more frequent integrity assessments. For example, a leak on the segment that may be caused by external corrosion should necessitate immediate reassessment. Changes to the segment may also require reassessment. Change management is addressed in this Code in section 11.
A-2.8 Performance Measures The following performance measures shall be documented for the external corrosion threat, in order to establish the effectiveness of the program and for confirmation of the integrity assessment interval: (a) number of hydrostatic test failures caused by external corrosion (b) number of repair actions taken due to in-line inspection results, immediate and scheduled (c) number of repair actions taken due to direct assessment results, immediate and scheduled (d) number of external corrosion leaks (for low-stress pipelines it may be beneficial to compile leaks by leak classification)
A-3.3 Criteria and Risk Assessment For new pipelines or pipeline segments, the operator may wish to use the original material selection, design conditions, and construction inspections, as well as the current operating history, to establish the condition of the pipe. For this situation, the operator must determine that the construction inspections have an equal or greater rigor than that provided by the prescribed integrity assessments in this Code. In addition, the operator shall determine that a corrosive environment does not exist. In no case may the interval between construction and the first required reassessment of integrity exceed 10 yr for pipe operating above 60% SMYS, 13 yr for pipe operating above 50% SMYS and at or below 60% SMYS, and 15 yr for pipe operating at or below 50% SMYS. For all pipeline segments older than those stated above, integrity assessment shall be conducted using a methodology within the specified response interval, as provided in para. A-3.5.
A-3 INTERNAL CORROSION THREAT A-3.1 Scope Section A-3 provides an integrity management plan to address the threat, and methods of integrity assessment and mitigation, of internal corrosion. Internal corrosion is defined in this context to include chemical corrosion and 47
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Figure A-3.1-1 Integrity Management Plan, Internal Corrosion Threat (Simplified Process: Prescriptive)
Gathering, reviewing, and integrating data
Criteria and risk assessment
Determine assessment interval
Integrity assessment (ILI, DA, hydrotest, or other)
Responses and mitigation
Other information to other threats
Performance metrics
Previous integrity assessments can be considered as meeting these requirements, provided the inspections have equal or greater rigor than that provided by the prescribed inspections in this Code. The interval between the previous integrity assessment and the next integrity assessment cannot exceed the interval stated in this Code.
for running of the tool. The operator selects the appropriate tools and he/she or his/her representative performs the inspection. (b) Pressure Test. The operator shall consult section 6, which defines how to conduct tests for both post-construction and in-service pipelines. The operator selects the appropriate test and he/she or his/her representative performs the test. (c) Direct Assessment. The operator shall consult section 6, which defines the process, tools, and inspections. The operator selects the appropriate tools and he/she or his/her representative performs the inspections.
A-3.4 Integrity Assessment The operator has a choice of three integrity assessment methods: in-line inspection with a tool capable of detecting wall loss, such as an MFL tool; performing a pressure test; or conducting direct assessment. (a) In-Line Inspection. For in-line inspection, the operator must consult section 6, which defines the capability of various ILI devices and provides criteria
A-3.5 Responses and Mitigation Responses to integrity assessments are detailed below.
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(a) In-Line Inspection. The response is dependent on the severity of corrosion, as determined by calculating critical failure pressure of indications (see ASME B31G or equivalent) and a reasonably anticipated or scientifically proven rate of corrosion. Refer to section 7 for responses to integrity assessments. (b) Direct Assessment. The response is dependent on the number of indications examined, evaluated, and repaired. Refer to section 7 for responses to integrity assessment. An acceptable method to address dry gas internal corrosion is NACE SP0206. (c) Pressure Testing. The interval is dependent on the hydrostatic test pressure. If the test pressure was at least 1.39 times MAOP, the interval is 10 yr. If the test pressure was at least 1.25 times MAOP, the interval is 5 yr (see section 7). If the actual operating pressure is less than MAOP, the factors shown above can be applied to the actual operating pressure in lieu of MAOP for the purposes of ensuring integrity at the reduced pressure only. The operator shall select the appropriate repair methods as outlined in section 7. The operator shall select the appropriate prevention practices as outlined in section 7. Data confirming that a corrosive environment exists should prompt the design of a mitigation plan of action and immediate implementation should occur. Data suggesting that a corrosive environment may exist should prompt an immediate reevaluation. If the data shows that no corrosive condition or environment exists, then the operator should identify the conditions that would prompt reevaluation.
A-3.8 Performance Metrics The following performance metrics shall be documented for the internal corrosion threat, in order to establish the effectiveness of the program and for confirmation of the integrity assessment interval: (a) number of hydrostatic test failures caused by internal corrosion (b) number of repair actions taken due to in-line inspection results, immediate and scheduled (c) number of repair actions taken due to direct assessment results, immediate and scheduled (d) number of internal corrosion leaks (for low-stress pipelines, it may be beneficial to compile leaks by leak grade)
A-4 STRESS CORROSION CRACKING THREAT A-4.1 Scope Section A-4 provides an integrity management plan to address the threat, and methods of integrity assessment and mitigation, for stress corrosion cracking (SCC) of gas line pipe. Methods of assessment include hydrostatic testing, in-line inspection, and SCC direct assessment (SCCDA). Engineering Assessment can be used to evaluate the extent and severity of the threat, to identify and select examination and testing strategies, and/or to develop technically defensible plans that demonstrate satisfactory pipeline safety performance. Included in this section is a description of a process utilizing Engineering Assessment that can be used to select an integrity assessment method or to customize one of the methods for a specific pipeline. This process is applicable to both near-neutral pH and high pH SCC. Integrity assessment and mitigation plans for both phenomena are discussed in published research literature. This section does not address all possible means of inspecting for mitigation of SCC. As new tools and technologies are developed, they can be evaluated and be available for use by the operator. Additional guidance for management of SCC can be found in ASME STP-PT-011, Integrity Management of Stress Corrosion Cracking in Gas Pipeline High Consequence Areas.
A-3.6 Other Data During the inspection activities, the operator may discover other data that should be used when performing risk assessments for other threats. For example, when conducting an ILI with an MFL tool, dents may be called out on the top half of the pipe. This may have been caused by third-party damage. It is appropriate then to use this data when conducting integrity assessment for the third-party damage threat.
A-3.7 Assessment Interval The operator is required to assess integrity periodically. The interval for assessment is dependent on the responses taken, as outlined in A-3.5. These intervals are maximum intervals. The operator shall incorporate new data into the assessment as data becomes available, and that may require more frequent integrity assessments. For example, a leak on the segment that may be caused by internal corrosion would necessitate immediate reassessment. Changes to the segment may also drive reassessment. This change management is addressed in section 11.
A-4.2 Gathering, Reviewing, and Integrating Data The following minimal data sets should be collected for each segment and reviewed before a threat assessment can be conducted. Additionally, these data are collected for special considerations, such as identifying severe situations requiring more or additional activities. (a) age of pipe NOTE: Age of pipe coating may be used if the pipeline segment has been assessed for SCC.
(b) operating stress level (% SMYS) (c) operating temperature
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Table A-4.4-1 SCC Crack Severity Criteria
ð16Þ Category
Crack Severity
Remaining Life
0
Crack of any length having depth <10% WT, or crack with 2 in. (51 mm) maximum length and depth less than <30% WT
Exceeds 15 yr
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 compressor station (e) coating type (f) past hydrotest information Where the operator is missing data, conservative assumptions shall be used when performing the risk analysis or, alternatively, the segment shall be prioritized higher.
not met and if the segment does not have a history of SCC, no action is required.
A-4.4 Integrity Assessment If conditions for SCC are present (i.e., meet the criteria in para. A-4.3), a written inspection, examination, and evaluation plan shall be prepared. The plan should give consideration to integrity assessment for other threats and prioritization among other segments that are at risk for SCC. If the pipeline experiences an in-service leak or rupture that is attributed to SCC, the particular segment shall be subjected to a hydrostatic test (as described below) within 12 months. A documented hydrostatic retest program shall be developed for this segment. Note that hydrostatic pressure testing is required. Use of test media other than water is not permitted. Acceptable inspection and mitigation methods for addressing pipe segments at risk for SCC are covered in paras. A-4.4.1 through A-4.4.4. The severity of SCC indications is characterized by Table A-4.4-1. Several alternative fracture mechanics approaches exist for operators to use for crack severity assessment. The values in Table A-4.4-1 have been developed for typical pipeline attributes and representative SCC growth rates, using widely accepted fracture mechanics analysis methods.
A-4.3 Criteria and Threat Assessment A-4.3.1 Possible Threat of Near-Neutral pH SCC. Each segment should be assessed for the possible threat of near-neutral pH SCC if all of the following criteria are present: (a) operating stress level >60% SMYS (b) age of pipe >10 yr NOTE: Age of pipe coating may be used if the pipeline segment has been assessed for SCC.
(c) all corrosion coating systems other than plantapplied or field-applied fusion bonded epoxy (FBE) or liquid epoxy (when abrasive surface preparation was used during field coating application). Field joint coating systems should also be considered for their susceptibility using the criteria in this section. A-4.3.2 Possible Threat of High pH SCC. Each segment should be assessed for the possible threat of high pH SCC if the three criteria in para. A-4.3.1 are present and the following two criteria are also present: (a) operating temperature >100°F (38°C) (b) distance from compressor station discharge ≤20 mi (32 km)
A-4.4.1 Bell Hole Examination and Evaluation Method. Magnetic particle inspection methods (MPI), or other equivalent nondestructive evaluation methods, shall be used when disbonded coating or bare pipe is encountered during integrity-related excavation of pipeline segments susceptible to SCC. Excavations where the pipe is not completely exposed (e.g., encroachments, exothermically welded attachments, and foreign line crossings where the operator may need only to remove soil from the top portion of the pipe) are not subject to the MPI requirement as described unless there is a prior history of SCC in the segment. Coating condition should be assessed and documented. All SCC inspection activities shall be conducted using documented procedures. Any indications of SCC shall be addressed using guidance from Tables A-4.4-1 and A-4.4.1-1.
A-4.3.3 Additional Considerations. In addition, each segment in which one or more service incidents or one or more hydrostatic test breaks or leaks has been caused by one of the two types of SCC shall be evaluated, unless the conditions that led to the SCC have been corrected. For this threat, the threat assessment consists of comparing the data elements to the criteria. If the conditions of the criteria are met or if the segment has a previous SCC history (i.e., bell hole inspection indicating the presence of SCC, hydrotest failures caused by SCC, inservice failures caused by SCC, or leaks caused by SCC), the pipe is considered to be at risk for the occurrence of SCC. Otherwise, if one of the conditions of the criteria is 50
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Table A-4.4.1-1 Actions Following Discovery of SCC During Excavation
ð16Þ
Crack Severity No SCC or Category 0 Category 1
Response Requirement Schedule SCCDA as appropriate. A single excavation for SCC is adequate. Conduct a minimum of two additional excavations. If the largest flaw is Category 1, conduct next assessment in 3 yr. If the largest flaw is Category 2, 3, or 4, follow the response requirement applicable to that category.
Category 2
Consider temporary pressure reduction until hydrotest, ILI, or MPI completed. Assess the segment using hydrotest, ILI, or 100% MPI examination, or equivalent, within 2 yr. The type and timing of further assessment(s) depend on the results of hydrotest, ILI, or MPI.
Category 3
Immediate pressure reduction and assessment of the segment using one of the following: (a) hydrostatic test (b) ILI (c) 100% MPI, or equivalent, examination
Category 4
Immediate pressure reduction and assessment of the segment using one of the following: (a) hydrostatic test (b) ILI (c) 100% MPI, or equivalent, examination
The response requirements applicable to the SCC crack severity categories are provided in Table A-4.4.1-1. The response requirements in Table A-4.4.1-1 incorporate conservative assumptions regarding remaining flaw sizes. Alternatively, an engineering critical assessment may be conducted to evaluate the threat.
10163, Method for Establishing Hydrostatic Re-Test Intervals for Pipelines With Stress Corrosion Cracking. A-4.4.3 In-Line Inspection for SCC. Industry experience has indicated some successful use of in-line inspection (ILI) for SCC in gas pipelines. Refer to para. 7.2.2 for appropriate response to indications of SCC identified by in-line inspection. Table A-4.4-1 can be used to establish a reassessment interval for ILI, provided that the entire segment has been inspected.
A-4.4.2 Hydrostatic Testing for SCC. Hydrostatic testing conditions for SCC mitigation have been developed through industry research to optimize the removal of critical-sized flaws while minimizing growth of subcritical-sized flaws. Hydrostatic testing utilizing the criteria in this section is considered an integrity assessment for SCC. Recommended hydrostatic test criteria are as follows: (a) High-point test pressure equivalent to a minimum of 100% SMYS. (b) Target test pressure shall be maintained for a minimum period of 10 min. (c) Upon returning the pipeline to gas service, an instrumented leak survey (e.g., a flame ionization survey) shall be performed. (Alternatives may be considered for hydrostatic test failure events due to causes other than SCC.) (d) Results (1) No SCC Hydrostatic Test Leak or Rupture. If no leaks or ruptures due to SCC occurred, the operator shall use one of the following two options to address long-term mitigation of SCC: (-a) Implement a written hydrostatic retest program with a technically justifiable interval. (-b) Perform engineering assessment to evaluate the threat and identify further mitigation methods. (2) SCC Hydrostatic Test Leak or Rupture. If a leak or rupture due to SCC occurred, the operator shall establish a written hydrostatic retest program and procedure with justification for the retest interval. An example of an SCC hydrostatic retest approach is found in IPC2006-
A-4.4.4 Stress Corrosion Cracking Direct Assessment (SCCDA). SCCDA is a formal process to assess a pipe segment for the presence and severity of SCC, primarily by examining with MPI or equivalent technology selected joints of pipe within that segment after systematically gathering and analyzing data for pipe having similar operational characteristics and residing in a similar physical environment. The SCCDA process includes guidance for operators to select appropriate sites to conduct excavations for the purposes of conducting an SCC integrity assessment. Detailed guidance for this process is provided in NACE SP0204, Stress Corrosion Cracking (SCC) Direct Assessment Methodology.
A-4.5 Other Data During the integrity assessment and mitigation activities, the operator may discover other data that may be pertinent to other threats. These data should be used where appropriate for performing risk assessments for other threats.
A-4.6 Performance Measures The following performance measures shall be documented for the SCC threat, in order to establish the effectiveness of the program and for confirmation of the inspection interval: (a) number of in-service leaks/failures due to SCC
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ð16Þ
Figure A-5.1-1 Integrity Management Plan, Manufacturing Threat (Pipe Seam and Pipe; Simplified Process: Prescriptive)
(b) number of repairs or replacements due to SCC (c) number of hydrostatic test failures due to SCC
This section outlines the integrity management process for manufacturing concerns in general and also covers some specific issues. Pipeline incident analysis has identified manufacturing among the causes of past incidents.
A-5 MANUFACTURING THREAT (PIPE SEAM AND PIPE)
A-5.2 Gathering, Reviewing, and Integrating Data
A-5.1 Scope
The following minimal data sets should be collected for each segment and reviewed before a risk assessment can be conducted. These data are collected for performing risk assessment and for special considerations such as identifying severe situations requiring more or additional activities. (a) pipe material (b) year of installation
Section A-5 provides an integrity management plan to address the threat, and methods of integrity assessment and mitigation, for manufacturing concerns. Manufacturing is defined in this context as pipe seam and pipe (see Figure A-5.1-1).
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(c) manufacturing process (age of manufacture as alternative; see note below) (d) seam type (e) joint factor (f) operating pressure history Where the operator is missing data, conservative assumptions shall be used when performing the risk assessment or, alternatively, the segment shall be prioritized higher.
For steel pipe, any section that fails the pressure test must be replaced. The operator shall select the appropriate prevention practices. For this threat, the operator should develop pipe specifications to be used when ordering pipe that meets or exceeds the requirements of ASME B31.8.
A-5.6 Other Data During the inspection activities, the operator may discover other data that should be used when performing risk assessments for other threats. For example, certain seam types may be more susceptible to accelerated corrosion. It is appropriate to use this information when conducting risk assessments for external or internal corrosion.
NOTE: When pipe data is unknown, the operator may refer to History of Line Pipe Manufacturing in North America by J. F. Kiefner and E. B. Clark, 1996, ASME.
A-5.3 Criteria and Risk Assessment For cast iron pipe, steel pipe manufactured prior to 1952, mechanically coupled pipelines, or pipelines joined by means of acetylene girth welds, where low temperatures are experienced or where the pipe is exposed to movement such as land movement or removal of supporting backfill, examination of the terrain is required. If land movement is observed or can reasonably be anticipated, a pipeline movement monitoring program should be established and appropriate intervention activities undertaken. If the pipe has a joint factor of less than 1.0 (such as lapwelded pipe, hammer-welded pipe, and butt-welded pipe) or if the pipeline is composed of low-frequency-welded ERW pipe or flash-welded pipe, a manufacturing threat is considered to exist. Fatigue along longitudinal pipe seams due to operating pressure cycles has not been a significant issue for natural gas pipelines. However, if the pipeline segment operates with significant pressure fluctuations, seam fatigue shall be considered by the operator as an additional integrity threat. GRI Report GRI-04/0178, Effects of Pressure Cycles on Gas Pipelines, may be a useful reference regarding fatigue due to pressure cycling.
A-5.7 Assessment Interval Periodic integrity assessment is not required. Changes to the segment may drive reassessment, such as uprating the pipeline’s operating pressure, or changes in operating conditions, such as significant pressure cycling. Change management is addressed in section 11.
A-5.8 Performance Measures The following performance measures shall be documented for the manufacturing threat, in order to establish the effectiveness of the program and for confirmation of the inspection interval: (a) number of hydrostatic test failures caused by manufacturing defects (b) number of leaks due to manufacturing defects
A-6 CONSTRUCTION THREAT (PIPE GIRTH WELD, FABRICATION WELD, WRINKLE BEND OR BUCKLE, STRIPPED THREADS/BROKEN PIPE/ COUPLING)
A-5.4 Integrity Assessment
A-6.1 Scope
For cast iron pipe, the assessment should include evaluation as to whether or not the pipe is subject to land movement or subject to removal of support. For steel pipe seam concerns, when raising the MAOP of a pipeline or when raising the operating pressure above the historical operating pressure (highest pressure recorded in the past 5 yr), pressure testing must be performed to address the seam issue. Pressure testing shall be in accordance with ASME B31.8, to at least 1.25 times the MAOP. ASME B31.8 defines how to conduct tests for both post-construction and in-service pipelines.
Section A-6 provides an integrity management plan to address the threat, and methods of integrity assessment and mitigation, for construction concerns. Construction is defined in this context as pipe girth weld, fabrication weld, wrinkle bend or buckle, stripped threads, broken pipe, or coupling (see Figure A-6.1-1). This section outlines the integrity management process for construction concerns in general, and also covers some specific issues. Pipeline incident analysis has identified construction among the causes of past incidents.
A-6.2 Gathering, Reviewing, and Integrating Data The following minimal data sets should be collected for each segment and reviewed before a risk assessment can be conducted. This data are collected to support performing risk assessment and for special
A-5.5 Responses and Mitigation For cast iron pipe, mitigation options include replacement of pipe or stabilization of pipe. 53
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ð16Þ
Figure A-6.1-1 Integrity Management Plan, Construction Threat (Pipe Girth Weld, Fabrication Weld, Wrinkle Bend or Buckle, Stripped Threads/Broken Pipe/Coupling; Simplified Process: Prescriptive)
considerations, such as identifying severe situations requiring more or additional activities. (a) pipe material (b) wrinkle bend identification (c) coupling identification (d) post-construction coupling reinforcement (e) welding procedures (f) post-construction girth weld reinforcement (g) NDT information on welds (h) hydrostatic test information (i) pipe inspection reports (bell hole) (j) potential for outside forces (see section A-10) (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
(n) operating pressure history and expected operation, including significant pressure cycling and fatigue mechanism Where the operator is missing data, conservative assumptions shall be used when performing the risk assessment or, alternatively, the segment shall be prioritized higher.
A-6.3 Criteria and Risk Assessment For girth welds, a review of the welding procedures and NDT information is required to ascertain that the welds are adequate.
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For fabrication welds, a review of the welding procedures and NDT information, as well as a review of forces due to ground settlement or other outside loads, is required to ascertain that the welds are adequate. For wrinkle bends and buckles as well as couplings, reports of visual inspection should be reviewed to ascertain their continued integrity. Potential movement of the pipeline may cause additional lateral and/or axial stresses. Information relative to pipe movement should be reviewed, such as temperature range, bend radius, degree of bend, depth of cover, and soil properties. These are important factors in determining whether or not bends are being subjected to injurious stresses or strains. The existence of these construction-related threats alone does not pose an integrity issue. The presence of these threats in conjunction with the potential for outside forces significantly increases the likelihood of an event. The data must be integrated and evaluated to determine where these construction characteristics coexist with external or outside force potential.
A-6.8 Performance Measures The following performance measures shall be documented for the construction threat, in order to establish the effectiveness of the program: (a) number of leaks or failures due to construction defects (b) number of girth welds/couplings reinforced/ removed (c) number of wrinkle bends removed (d) number of wrinkle bend inspections (e) number of fabrication welds repaired/removed
A-7 EQUIPMENT THREAT (GASKETS AND ORINGS, CONTROL/RELIEF, SEAL/PUMP PACKING) A-7.1 Scope Section A-7 provides an integrity management plan to address the threat, and methods of integrity assessment and mitigation, for pipeline equipment failure. Equipment is defined in this context as pipeline facilities other than pipe and pipe components. Meter/regulator and compressor stations are typical equipment locations (see Figure A-7.1-1). This section outlines the integrity management process for equipment in general and also covers some specific issues. Pipeline incident analysis has identified pressure control and relief equipment, gaskets and O-rings, and seal/pump packing among the causes of past incidents.
A-6.4 Integrity Assessment For construction threats, the inspection should be by data integration, examination, and evaluation for threats that are coincident with the potential for ground movement or outside forces that will impact the pipe.
A-6.5 Responses and Mitigation The operator shall select the appropriate prevention practices. For this threat, the operator should develop excavation protocols to ensure the pipe is not moved and additional stresses introduced. In addition, the operator should conduct examinations and evaluations every time the pipe is exposed. Potential threats should be mitigated by proactive procedures that require inspection, repair, replacement, or reinforcement when the need to inspect the pipeline for other maintenance reasons occurs. ð16Þ
A-7.2 Gathering, Reviewing, and Integrating Data The following minimal data sets should be collected for each segment and reviewed before a risk assessment can be conducted. These data are collected in support of performing risk assessment and for special considerations, such as identifying severe situations requiring more or additional activities. (a) year of installation of failed equipment (b) regulator valve failure information (c) relief valve failure information (d) flange gasket failure information (e) regulator set point drift (outside of manufacturer’s tolerances) (f) relief set point drift (g) O-ring failure information (h) seal/packing information Where the operator is missing data, conservative assumptions shall be used when performing the risk assessment or, alternatively, the segment shall be prioritized higher.
A-6.6 Other Data During the inspection activities, the operator may discover other data that should be used when performing risk assessments for other threats. For example, reviewing the hydrostatic test information might reveal previous failures due to pipe seam defects. It is appropriate to use this information when conducting risk assessments for manufacturing threats.
A-6.7 Assessment Interval Periodic assessment is not required. Changes to the segment or changes in land use may drive reassessment. Change management is addressed in section 11.
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ð16Þ
Figure A-7.1-1 Integrity Management Plan, Equipment Threat (Gasket and O-Ring, Control/Relief, Seal/Pump Packing; Simplified Process: Prescriptive)
tions may be necessary if the equipment has a leak and failure history.
A-7.3 Criteria and Risk Assessment Certain relief and regulator valves are known to have their set points drift. These equipment types may require extra scrutiny. Certain gasket types are prone to premature degradation. These equipment types may require more-frequent leak checks.
A-7.5 Responses and Mitigation Replacement or repair of the equipment may be required.
A-7.6 Other Data
A-7.4 Integrity Assessment
During the inspection activities, the operator may discover other data that should be used when performing risk assessments for other threats. For example, when inspecting gaskets at aboveground facilities, it is discovered that there has been a lightning strike. It is appropriate to use this information when conducting risk assessments for the weather-related and outside force threat.
The inspections for this threat are normally conducted per the requirements of the O&M procedures. These procedures detail when inspections and maintenance of equipment shall be performed and what specific action is required. Additional or more frequent inspec-
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ð16Þ
Figure A-8.1-1 Integrity Management Plan, Third-Party Damage Threat [Third-Party Inflicted Damage (Immediate), Vandalism, Previously Damaged Pipe; Simplified Process: Prescriptive]
(d) number of leaks due to equipment failures
A-7.7 Assessment Interval The interval for assessment is contained within the operation and maintenance procedure for the specific types of equipment. Changes to the segment may drive reassessment. This change management is addressed in section 11.
A-8 THIRD-PARTY DAMAGE THREAT [THIRDPARTY INFLICTED DAMAGE (IMMEDIATE), VANDALISM, PREVIOUSLY DAMAGED PIPE] A-8.1 Scope
A-7.8 Performance Measures
Section A-8 provides an integrity management plan to address the threat, and methods of integrity assessment and mitigation, for third-party damage. Third-party damage is defined in this context as third-party inflicted damage with immediate failure, vandalism, and previously damaged pipe (see Figure A-8.1-1).
The following performance measures shall be documented for the equipment threat, in order to establish the effectiveness of the program and for confirmation of the inspection interval: (a) number of regulator valve failures (b) number of relief valve failures (c) number of gasket or O-ring failures 57
ASME B31.8S-2016
This section outlines the integrity management process for third-party damage in general and also covers some specific issues. Pipeline incident analysis has identified third-party damage among the causes of past incidents.
tion activities may be warranted as provided in section 7, such as development of a damage prevention plan.
A-8.6 Other Data During the inspection and examination activities, the operator may discover other data that should be used when performing risk assessments for other threats. For example, when monitoring an encroachment, exposed pipe may indicate active external corrosion. It is appropriate to use this information when conducting risk assessments for external corrosion.
A-8.2 Gathering, Reviewing, and Integrating Data The following minimal data sets should be collected for each segment and reviewed before a risk assessment can be conducted. These data are collected in support of performing risk assessment and for special considerations, such as identifying severe situations requiring more or additional activities. (a) vandalism incidents (b) pipe inspection reports (bell hole) where the pipe has been hit (c) leak reports resulting from immediate damage (d) incidents involving previous damage (e) in-line inspection results for dents and gouges at top half of pipe (f) one-call records (g) encroachment records
A-8.7 Assessment Interval Assessment shall be performed periodically. It is recommended that it be performed annually. Changes to the segment may drive reassessment. Change management is addressed in section 11.
A-8.8 Performance Measures The following performance measures shall be documented for the third-party threat in order to establish the effectiveness of the program and for confirmation of the inspection interval: (a) number of leaks or failures caused by third-party damage (b) number of leaks or failures caused by previously damaged pipe (c) number of leaks or failures caused by vandalism (d) number of repairs implemented as a result of thirdparty damage prior to a leak or failure
A-8.3 Criteria and Risk Assessment Review of data may show susceptibility to certain types of third-party inflicted damage. Deficiencies in these areas require mitigation as outlined below. Because third-party damage is a time-independent threat, even with the absence of any of these indicators, third-party damage can occur at any time and strong prevention measures are necessary, especially in areas of concern. Specific land uses, such as agricultural lands with shallow depth of cover, may be more susceptible to third-party damage.
A-9 INCORRECT OPERATIONS THREAT A-9.1 Scope
A-8.4 Integrity Assessment
Section A-9 provides an integrity management plan to address the threat, and methods of integrity assessment and mitigation, for incorrect operations. Incorrect operations are defined in this context as incorrect operating procedures or failure to follow a procedure (see Figure A-9.1-1). This section outlines the integrity management process for incorrect operations in general and also covers some specific issues. Pipeline incident analysis has identified incorrect operations among the causes of past incidents.
Observance of encroachments or third-party damage is accomplished during patrols and leak surveys conducted as required by the operations and maintenance procedures. However, in the case of incidents involving previously damaged pipe, it is frequently found after the fact that the defect was revealed indirectly even though it may have been adequately described by a previous inspection such as an in-line inspection. Therefore, the operator should investigate suspicious indications discovered by inspections that cannot be directly interpreted, but may be correlated with known excavation activities revealed by one-call records or other encroachment records.
A-9.2 Gathering, Reviewing, and Integrating Data The following minimal data sets should be collected for each segment and reviewed before a risk assessment can be conducted. These data are collected in support of performing risk assessment and for special considerations, such as identifying severe situations requiring more or additional activities. (a) procedure review information (b) audit information
A-8.5 Responses and Mitigation Mitigation of third-party damage is through preventive actions or repair of damage found as a result of inspections, examinations, or tests performed. The operator shall ensure that third-party damage prevention programs are in place and functioning. Additional preven58
ASME B31.8S-2016
ð16Þ
Figure A-9.1-1 Integrity Management Plan, Incorrect Operations Threat (Simplified Process: Prescriptive)
(c) failures caused by incorrect operation
A-9.5 Responses and Mitigation Mitigation in this instance is prevention. The operator shall ensure that procedures are current, the personnel are adequately qualified, and that the following of procedures is enforced. The operator should have a program to qualify operation and maintenance personnel for each activity that they perform. This program should include initial qualification and periodic reassessment of qualification. Certification by recognized organizations may be included in this program. In addition, a strong internal review or audit program by in-house experts or third-party experts is necessary.
A-9.3 Criteria and Risk Assessment If the data shows the operation and maintenance are performed in accordance with operation and maintenance procedures, the procedures are correct, and that operating personnel are adequately qualified to fulfill the requirements of the procedure, no additional assessment is required. Deficiencies in these areas require mitigation as outlined below.
A-9.4 Integrity Assessment The audits and reviews are normally conducted on an ongoing basis. These inspections are conducted by company personnel and/or by third-party experts.
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A-9.6 Other Data
A-10.2 Gathering, Reviewing, and Integrating Data
During the inspection activities, the operator may discover other data that should be used when performing risk assessments for other threats. For example, when reviewing records required by procedures, it is discovered that there have been several unreported encroachments by third parties. It is appropriate to use this information when conducting risk assessments for third-party damage.
The following minimal data sets should be collected for each segment and reviewed before a risk assessment can be conducted. These data are collected in support of performing risk assessment and for special considerations, such as identifying severe situations requiring more or additional activities. (a) joint method (mechanical coupling, acetylene weld, arc weld) (b) topography and soil conditions (unstable slopes, water crossings, water proximity, soil liquefactions susceptibility) (c) earthquake fault (d) profile of ground acceleration near fault zones (greater than 0.2g acceleration) (e) depth of frost line (f) year of installation (g) pipe grade, diameter, and wall thickness (internal stress calculation added to external loading; total stress not to exceed 100% SMYS) Where the operator is missing data, conservative assumptions shall be used when performing the risk assessment or, alternatively, the segment shall be prioritized in a higher category based on the expected worst case of the missing data.
A-9.7 Assessment Interval Assessment shall be performed periodically and is recommended to be performed annually. Changes to the segment may drive revision of procedures and additional training of personnel. Change management is addressed in section 11.
A-9.8 Performance Measures The following performance measures shall be documented for the incorrect operations threat, in order to establish the effectiveness of the program and for confirmation of the inspection interval: (a) number of leaks or failures caused by incorrect operations (b) number of audits/reviews conducted (c) number of findings per audit/review, classified by severity (d) number of changes to procedures due to audits/ reviews
A-10.3 Criteria and Risk Assessment Pipe may be susceptible to extreme loading at the following locations: (a) where the pipeline crosses a fault line (b) where the pipeline traverses steep slopes (c) where the pipeline crosses water or is adjacent to water, or where the river bottom is moving (d) where the pipeline is subject to extreme surface loads that cause settlement to underlying soils (e) where blasting near the pipeline is occurring (f) when the pipe is at or above the frost line (g) where the soil is subject to liquefaction (h) where ground acceleration exceeds 0.2g (i) where the pipeline transitions between soils and structures or between structures (e.g., buildings, equipment) At locations meeting any of the above, the threat shall be evaluated. At locations where facilities are prone to lightning strikes, the threat shall be evaluated.
A-10 WEATHER-RELATED AND OUTSIDE FORCE THREAT (EARTH MOVEMENT, HEAVY RAINS OR FLOODS, COLD WEATHER, LIGHTNING) A-10.1 Scope Section A-10 provides an integrity management plan to address the threat, and methods of integrity assessment and mitigation, for weather-related and outside force concerns. Weather-related and outside force is defined in this context as earth movement, heavy rains or floods, cold weather, and lightning (see Figure A-10.1-1). This section outlines the integrity management process for weather-related and outside force threats in general, and also covers some specific issues. For seismic threats, PR 268-9823, Guidelines for the Seismic Design and Assessment of Natural Gas and Liquid Hydrocarbon Pipelines, or similar methodologies may be used. Pipeline incident analysis has identified weatherrelated and outside force damage among the causes of past incidents.
A-10.4 Integrity Assessment For weather-related and outside force threats, integrity assessments, including inspections, examinations, and evaluations, are normally conducted per the requirements of the O&M procedures. Additional or more-frequent inspections may be necessary, depending on leak and failure information.
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ð16Þ
Figure A-10.1-1 Integrity Management Plan, Weather-Related and Outside Force Threat (Earth Movement, Heavy Rains or Floods, Cold Weather, Lightning; Simplified Process: Prescriptive)
A-10.5 Responses and Mitigation
A-10.6 Other Data
Repairs or replacement of pipe shall be in accordance with the ASME B31.8 Code and other applicable industry standards. Other methods of mitigation may include stabilization of the soil, stabilization of the pipe or pipe joints, relocation of the pipeline, lowering of the pipeline below the frost line for cold-weather situations, and protection of aboveground facilities from lightning. Prevention activities are most appropriate for this threat. If a pipeline falls within the listed susceptibilities, line patrolling should be used to perform surface assessments. In certain locations, such as known slide areas or areas of ongoing subsidence, the progress of the movement should be monitored.
During the inspection activities, the operator may discover other data that should be used when performing risk assessments for other threats. For example, when a pipeline is patrolled, evidence of third-party encroachment may be discovered. It is appropriate to use this information when conducting risk assessments for the thirdparty damage threat.
A-10.7 Assessment Interval Changes to the segment, or the land use around the segment, may drive reassessment if the changes affect pipeline integrity. If no changes are experienced, reassessment is not required. Change management is addressed in section 11. 61
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(a) number of leaks that are weather-related or due to outside force (b) number of repair, replacement, or relocation actions due to weather-related or outside force threats
A-10.8 Performance Measures The following performance measures shall be documented for the weather-related and outside force threat, in order to establish the effectiveness of the program and for confirmation of the inspection interval:
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NONMANDATORY APPENDIX B DIRECT ASSESSMENT PROCESS ð16Þ
B-1 GENERAL
B-3 INTERNAL CORROSION DIRECT ASSESSMENT
This Appendix provides information about the direct assessment process. Direct assessment is one integrity assessment methodology that can be used within the integrity management program.
This section has been removed with publication of NACE SP0206 DG-ICDA. Operators are encouraged to use NACE SP0206 DG-ICDA or an alternate and technically 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 justified methodology.
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NONMANDATORY APPENDIX C PREPARATION OF TECHNICAL INQUIRIES (b) Background. State the purpose of the inquiry, which would be either to obtain an interpretation of Code rules or to propose consideration of a revision to the present rules. Provide concisely the information needed for the Committee’s understanding of the inquiry, being sure to include reference to the applicable Code Section, Edition, Addenda, paragraphs, figures, and tables. If sketches are provided, they shall be limited to the scope of the inquiry. (c) Inquiry Structure (1) Proposed Question(s). The inquiry shall be stated in a condensed and precise question format, omitting superfluous background information, and, where appropriate, composed in such a way that “yes” or “no” (perhaps with provisos) would be an acceptable reply. The inquiry statement should be technically and editorially correct. (2) Proposed Reply(ies). Provide a proposed reply stating what it is believed that the Code requires. If, in the inquirer’s opinion, a revision to the Code is needed, recommended wording shall be provided in addition to information justifying the change.
C-1 INTRODUCTION The ASME B31 Committee, Code for Pressure Piping, will consider written requests for interpretations and revisions of the Code rules, and develop new rules if dictated by technological development. The Committee’s activities in this regard are limited strictly to interpretations of the rules or to the consideration of revisions to the present rules on the basis of new data or technology. As a matter of published policy, ASME does not approve, certify, rate, or endorse any item, construction, proprietary device, or activity, and, accordingly, inquiries requiring such consideration will be returned. Moreover, ASME does not act as a consultant on specific engineering problems or on the general application or understanding of the Code rules. If, based on the inquiry information submitted, it is the opinion of the Committee that the inquirer should seek professional assistance, the inquiry will be returned with the recommendation that such assistance be obtained. Inquiries that do not provide the information needed for the Committee’s full understanding will be returned.
C-3 SUBMITTAL
C-2 REQUIREMENTS
Inquiries should be submitted in typewritten form; however, legible handwritten inquiries will be considered. They shall include the name and mailing address of the inquirer, and be mailed to the following address: Secretary ASME B31 Committee Two Park Avenue New York, NY 10016-5990
Inquiries shall be limited strictly to interpretations of the rules or to the consideration of revisions to the present rules on the basis of new data or technology. Inquiries shall meet the following requirements: (a) Scope. Involve a single rule or closely related rules in the scope of the Code. An inquiry letter concerning unrelated subjects will be returned.
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ASME CODE FOR PRESSURE PIPING, B31
B31.1-2016
Power Piping
B31.3-2014
Process Piping
B31.3-2010
Tuberías de Proceso
B31.4-2016
Pipeline Transportation Systems for Liquids and Slurries
B31.5-2016
Refrigeration Piping and Heat Transfer Components
B31.8-2016
Gas Transmission and Distribution Piping Systems
B31.8S-2016 B31.8S-2010 B31.9-2014 B31.12-2014
Managing System Integrity of Gas Pipelines Gestión de Integridad de Sistemas de Gasoductos Building Services Piping 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
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ASME B31.8S-2016