guide for gas transmission, distribution and gathering ... · allan clarke, consultant . rodney...

American Gas Association 400 N. Capitol St., NW Washington, DC 20001

Michael Bellman GPTC Secretary (202) 824-7183

[email protected]

February 26, 2018 Dear Guide Purchaser, Enclosed is Addendum 9 to ANSI GPTC Z380.1, Guide for Gas Transmission, Distribution and Gathering Piping Systems, 2015 Edition. Addenda are formatted to enable the replacement of pages in your Guide with the updated enclosed pages. Please follow the enclosed page replacement instructions. On behalf of the Gas Piping Technology Committee and the American Gas Association, thank you for your purchase and interest in the Guide. Sincerely,

Secretary GPTC Z380

B L A N K

1

GPTC GUIDE FOR GAS TRANSMISSION, DISTRIBUTION, AND GATHERING PIPING SYSTEMS

2015 EDITION

ADDENDUM 9, January 2018

The changes in this addendum are marked by wide vertical lines inserted to the left of modified text, overwriting the left border of most tables, or a block symbol ( ▌) where needed. There were no Federal Regulation updates for this period. Three GPTC transactions affected 6 sections of the Guide. Editorial updates include application of the Editorial Guidelines, adjustments to page numbering, and adjustment of text on pages. While only significant editorial updates are marked, all affected pages carry the current addendum footnote. Editorial updates as indicated “EU” affected 3 sections of the Guide (plus other sections impacted by page adjustments, etc.). The table shows the affected sections, the pages to be removed, and their replacement pages.

Key to Reasons for Change Amdt.19X-XXX or docket number: federal regulation amendment TRYY-XX: GPTC transaction with new or updated guide material EU: editorial update

Guide Section Reason for Change Pages to be Removed

Replacement Pages

Title Page EU i/ii i/ii

GPTC Membership listed by Committee

EU

xvii/xviii thru xxxi/xxxii xvii/xviii thru xxxi/xxxii GPTC Membership listed by member participation

EU

Editorial Conventions Included as Publication Requirement, no action required

Editorial Notes

Part 192

Subpart J 192.505 TR 13-34 219/220 219/220

Subpart L 192.613 TR 16-12 253/254 253/254

Subpart L 192.616 TR 16-12 281/282 281/282

Subpart O 192.925 TR 12-46 435/436, 437/438 435/436, 437/438

Subpart O 192.925 TR 12-46 455/456 455/456

GMA G-192-1 TR 12-46 561/562 563/564 561/562 563/564

GMA G-192-1 TR 12-46 573/574 573/574

GMA G-192-9 TR13-34 663/664 663/664

GMA G-192-10 TR13-34 669/670 669/670

i

Guide for Gas Transmission, Distribution, and Gathering

Piping Systems

2015 Edition

Addendum 9, January 2018

An American National Standard

Author:

Gas Piping Technology Committee (GPTC) Z380 Accredited by ANSI

Secretariat:

American Gas Association

Approved by

American National Standards Institute (ANSI) Date: February 16, 2018

ANSI GPTC Z380.1-2015, Addendum No 9 - 2018

Catalog Number: Z3801159

GPTC GUIDE FOR GAS TRANSMISSION, DISTRIBUTION, AND GATHERING PIPING SYSTEMS: 2015 Edition

iii

PLEASE NOTE

Addenda to this Guide will also be issued periodically to enable users to keep the Guide up-to-date by replacing the pages that have been revised with the new pages. It is advisable, however, that pages which have been revised be retained so that the chronological development of the Federal Regulations and the Guide is maintained.

CAUTION

As part of document purchase, GPTC (using AGA as Secretariat) will try to keep purchasers informed on the current Federal Regulations as released by the Department of Transportation (DOT). This is done by periodically issuing addenda to update both the Federal Regulations and the guide material. It is the responsibility of the purchaser to obtain a copy of any addenda. Addenda are posted on the Committee’s webpage at www.aga.org/gptc. The GPTC assumes no responsibility in the event the purchaser does not obtain addenda. The purchaser is reminded that the changes to the Regulations can be found on the Federal Register's web site.

No part of this document may be reproduced in any form, in an electronic retrieval system or otherwise, without the prior written permission of the American Gas Association. Participation by state and federal agency representative(s) or person(s) affiliated with industry is not to be interpreted as government or industry endorsement of the guide material in this Guide. Conversions of figures to electronic format courtesy of ViaData Incorporated. Cover photos of meters and pipeline with gauge provided by permission of the Laclede Gas Company; cover photo of welder provided by permission of the Southern California Gas Company.

Copyright 2015 THE AMERICAN GAS ASSOCIATION

400 N. Capitol St., NW Washington, DC 20001

All Rights Reserved Printed in U.S.A.


Addendum 9, January 2018 xvii

GAS PIPING TECHNOLOGY COMMITTEE MEMBERSHIP1

Listed by Committee

Officers Leticia Quezada, Chair Southern Company Gas

Lee Reynolds, 1st Vice Chair NiSource Gas Distribution Philip Sher, 2nd Vice Chair

Philip Sher Pipeline Consultant Mike Bellman, Secretary American Gas Association

Main Body (Consensus) Purpose is to act as the final decision making body within the GPTC structure.

(Voting unless otherwise noted)

Leticia Quezada, Southern Company Gas, Chair Lee Reynolds, NiSource Gas Distribution, 1st Vice Chair Philip Sher, Philip Sher Pipeline Consultant, 2nd Vice Chair Mike Bellman, American Gas Association, Secretary 2 Glen Armstrong, EN Engineering Stephen Bateman, Retired Frank Bennett, UGI Utilities David Bull, ViaData LP DeWitt Burdeaux, TRC Solutions John Butler, EQT Midstream Robert Cadorin, TransCanada Corporation Willard Carey, Energy Experts International John Chin, TransCanada Corporation Amerigo Del Buono, Weldbend Corporation Rodney Dyck, U.S. Department of Transportation – PHMSA Mary Friend, Public Service Commission of West Virginia Steven Groeber, Gas Operations Consultant Richard Huriaux, Richard Huriaux, Consulting Engineer Randy Knapp, Plastics Pipe Institute John Kottwitz, Missouri Public Service Commission

Douglas Lee, Consultant George Lomax, Heath Consultants Incorporated John Lueders, DTE Gas Company James McKenzie, Atmos Energy Corporation Theron McLaren, U.S. Department of Transportation - PHMSA Lane Miller, TRC Solutions Robert Naper, Energy Experts International Joseph Opert, BGE, An Exelon Company Eugene Palermo, Palermo Plastics Pipe Consulting Kenneth Peters, Kinder Morgan Inc. Alice Ratcliffe, Crestwood Midstream Robert Schmidt, Canadoil Forge Patrick Seamands, Retired Walter Siedlecki, AEGIS Insurance Services, Inc. Richard Slagle, Southern Company Gas Jerome Themig, Retired Alfredo Ulanday, EN Engineering Ram Veerapaneni, DTE Gas Company Frank Volgstadt, Volgstadt & Associates

Executive Section Responsible for the expedient and efficient handling of the business of the GPTC in all routine and ongoing matters.

Lee Reynolds, NiSource Gas Distribution, Chair Mike Bellman, American Gas Association, Secretary 2 David Bull, ViaData LP John Kottwitz, Missouri Public Service Commission John Lueders, DTE Gas Company Jamie McKenzie, Atmos Energy Corp. Joseph Opert, BGE, An Exelon Company Eugene Palermo, Palermo Plastics Pipe Consulting

Kenneth Peters, Kinder Morgan Inc. Leticia Quezada, Southern Company Gas Alice Ratcliffe, Crestwood Midstream Philip Sher, Philip Sher Pipeline Consultant Richard Slagle, Southern Company Gas Jerome Themig, Retired Ram Veerapaneni, DTE Gas Company

________________________ 1 Membership as of 1/31/18 2 Non voting



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Editorial Section Responsible for maintaining consistent format and high structural standards for Guide Material and in ANSI Technical Reports.

John Kottwitz, Missouri Public Service Commission, Chair Lane Miller, TRC Solutions, Secretary Richard Abraham, Retired Stephen Bateman, Retired John Butler, EQT Midstream Steven Gauthier, Energy Experts International

Steven Groeber, Gas Operations Consultant John Groot, Southern California Gas Company Christine Maynard, NiSource, Inc. Paul Oleksa, Oleksa and Associates, Inc. Ram Veerapaneni, DTE Gas Company

Liaison Section Responsible for presenting GPTC actions to the appropriate government bodies and other groups in an effective manner.

Joseph Opert, BGE, An Exelon Company, Chair Steven Troch, BGE, An Exelon Company

Regulations Section Responsible for developing GPTC responses to Notices of Proposed Rulemaking (NPRMs) and to other regulatory Notices.

Alice Ratcliffe, Crestwood Midstream, Chair Frank Bennett, UGI Utilities, Inc. David Bull, ViaData LP Allan Clarke, Consultant Leo Cody, Liberty Utilities

Gregory Goble, R.W. Lyall & Company, Inc. James McKenzie, Atmos Energy Corporation Robert Naper, Energy Experts International Eugene Palermo, Palermo Plastics Pipe Consulting Steven Troch, BGE, An Exelon Company

Distribution Division Responsible for technical review of all materials and take appropriate action before the material goes to the Main Body.

John Lueders, DTE Gas Company, Chair Lane Miller, TRC Solutions, Secretary Richard Abraham, Retired Glen Armstrong, EN Engineering Randy Bareither, Avista Utilities Stephen Bateman, Retired Andrew Benedict, Opvantek Inc. Michelle Blanchard, Alliant Energy David Bonner, PECO Energy, An Exelon Company David Bull, ViaData LP Brian Camfield, PECO Energy, An Exelon Company Willard Carey, Energy Experts International Leo Cody, Liberty Utilities Mark Conners, UGI Utilities, Inc. Denise Dolezal, Metropolitan Utilities District Kalu Kelly Emeaba, National Transportation Safety Board John Erickson, American Public Gas Association Matthew Esmacher, Washington Gas Light Co Chris Foley, RCP Inc. Mark Forster, Southern California Gas Lloyd Freeman, Southern California Gas Anthony Fuhrman, Public Service Electric & Gas

Jamie Garland, Maine Natural Gas John Goetz, Meade Steven Groeber, Gas Operations Consultant John Groot, Southern California Gas Company Matt Hill, Vectren John Kottwitz, Missouri Public Service Commission Brent Koym, CenterPoint Energy Sean Lynn, Xcel Energy Inc. Thomas Marlow, PRCI Joel Martell, Southwest Gas Christine Maynard, NiSource, Inc. James McKenzie, Atmos Energy Corporation Theron McLaren, U.S. Department of Transportation - PHMSA Rich Medcalf, Indiana Utility Regulatory Commission Jeffrey Meyers, Black & Veatch Corporation Robert Naper, Energy Experts International Paul Oleksa, Oleksa and Associates, Inc. Joseph Opert, BGE, An Exelon Company Christopher Pioli, Jacobs Consultancy Charles Rayot, Ameren Illinois Patrick Seamands, Retired Parashar Sheth, National Grid

(Continued)



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Distribution Division (Continued)

Walter Siedlecki, AEGIS Insurance Services, Inc. Richard Slagle, Southern Company Gas David Spangler, NPL

Jerome Themig, Retired Steven Troch, BGE, An Exelon Company Alfredo Ulanday, EN Engineering Thomas Webb, Peoples Gas Light & Coke

Manufacturers Division

Responsible for technical review of all materials and take appropriate action before the material goes to the Main Body Eugene Palermo, Palermo Plastics Pipe Consulting, Chair Frank Volgstadt, Volgstadt & Associates, Secretary DeWitt Burdeaux, TRC Solutions Heath Casteel, Performance Pipe Allison Crabtree, DuraLine Amerigo Del Buono, Weldbend Corporation Steven Gauthier, Energy Experts International Gregory Goble, R.W. Lyall & Company, Inc. Richard Huriaux, Consulting Engineer

James Johnston Jr., McElroy Manufacturing, Inc. Randy Knapp, Plastics Pipe Institute George Lomax, Heath Consultants Incorporated William Luff, JANA Corp. Mary Lee McDonald, Performance Pipe Daniel O'Leary, Timberline Tool Robert Schmidt, Canadoil Forge David Wartluft, Continental Industries

Transmission Division

Responsible for technical review of all materials and take appropriate action before the material goes to the Main Body. Kenneth Peters, Kinder Morgan Inc., Chair Robert Cadorin, TransCanada Corporation, Secretary Erik Anderson, Northwestern Energy Aaron Bass, Interstate Energy Company Stephen Beatty, LG&E-KU, PPL Companies Robert Becken, Energy Experts International Frank Bennett, UGI Utilities, Inc. John Butler, EQT Midstream John Chin, TransCanada Corporation Allan Clarke, Consultant Rodney Dyck, U.S. Department of Transportation – PHMSA Michael Falk, Xcel Energy Robert Fassett, E2 Consulting Engineers Mary Friend, Public Service Commission of West Virginia Narinder Grewal, AG Square, Inc.

George Hamaty, TransCanada / Columbia Pipeline Group Renee Hermiller, Marathon Petroleum Corporation Steven Huntington, System One Services Douglas Lee, Consultant Ray Lewis, Retired Thomas Marlow, PRCI Erin McKay, Hilcorp Alaska, LLC Alice Ratcliffe, Crestwood Midstream Timothy Strommen, WE Energies David Terzian, National Grid Erich Trombley, Southwest Gas Corporation Ram Veerapaneni, DTE Gas Company Jim Walton, JW’s Pipeline Integrity Services Gary White, PI Confluence, Inc. Brian Wolf, Hatch Mott MacDonald Anson Wong, Southern California Gas Company

Damage Prevention / Emergency Response Task Group Responsible for developing Guide Material, ANSI Technical Reports, and other technical material as directed by the Main Body.

David Bull, ViaData LP, Chair Christine Maynard, NiSource, Inc., Secretary Richard Abraham, Retired Glen Armstrong, EN Engineering Randy Bareither, Avista Utilities Stephen Bateman, Retired Frank Bennett, UGI Utilities, Inc. Brian Camfield, PECO Energy Willard Carey, Energy Experts International John Chin, TransCanada Corporation Leo Cody, Liberty Utilities Kalu Kelly Emeaba, National Transportation Safety Board John Erickson, American Public Gas Association

Michael Falk, Excel Energy Mark Forster, Southern California Gas Lloyd Freeman, Southern California Gas Mary Friend, Public Service Commission of West Virginia Jamie Garland, Maine Natural Gas Steven Groeber, Gas Operations Consultant George Hamaty, TransCanada / Columbia Pipeline Group Renee Hermiller, Marathon Petroleum Corporation Matt Hill, Vectren John Kottwitz, Missouri Public Service Commission George Lomax, Heath Consultants Incorporated Sean Lynn, Xcel Energy Inc.

(Continued)



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Damage Prevention / Emergency Response Task Group (Continued) Joel Martell, Southwest Gas Erin McKay, Hilcorp Alaska, LLC Robert Naper, Energy Experts International Daniel O’Leary, Timberline Tool Christopher Pioli, Jacobs Consultancy Alice Ratcliffe, Crestwood Midstream Charles Rayot, Ameren Illinois Patrick Seamands, Retired Walter Siedlecki, AEGIS Insurance Services, Inc. Richard Slagle, Southern Company Gas

David Spangler, NPL Timothy Strommen, WE Energies Jerome Themig, Retired Alfredo Ulanday, EN Engineering Ram Veerapaneni, DTE Gas Company Jim Walton, JW’s Pipeline Integrity Services David Wartluft, Continental Industries Brian Wolf, Hatch Mott MacDonald Anson Wong, Southern California Gas Company

Design Task Group

Responsible for developing Guide Material, ANSI Technical Reports, and other technical material as directed by the Main Body. James McKenzie, Atmos Energy Corporation, Chair Douglas Lee, Consultant, Secretary Erik Anderson, Northwestern Energy Stephen Beatty, LG&E-KU, PPL Companies Robert Becken, Energy Experts International Andrew Benedict, Opvantek Michelle Blanchard, Alliant Energy DeWitt Burdeaux, TRC Solutions John Butler, EQT Midstream Heath Casteel, Performance Pipe John Chin, TransCanada Corporation Allan Clarke, Consultant Mark Connors, UGI Utilities, Inc. Allison Crabtree, DuraLine Denise Dolezal, Metropolitan Utilities District Rodney Dyck, U.S. Department of Transportation - PHMSA Matthew Esmacher, Washington Gas Light Co Robert Fassett, E2 Consulting Engineers Chris Foley, RCP Inc. Anthony Fuhrman, Public Service Electric & Gas

Gregory Goble, R.W. Lyall & Company, Inc. Narinder Grewal, AG Square, Inc. John Groot, Southern California Gas Company Richard Huriaux, Consulting Engineer Randy Knapp, Plastics Pipe Institute Brent Koym, CenterPoint Energy John Lueders, DTE Gas Company William Luff, JANA Corp. Thomas Marlow, PRCI Theron McLaren, U.S. Department of Transportation - PHMSA Jeffrey Meyers, Black & Veatch Corporation Paul Oleksa, Oleksa and Associates, Inc. Eugene Palermo, Palermo Plastics Pipe Consulting Kenneth Peters, Kinder Morgan Inc. Robert Schmidt, Canadoil Forge Parashar Sheth, National Grid David Terzian, National Grid Erich Trombley, Southwest Gas Corporation Frank Volgstadt, Volgstadt & Associates

Integrity Management / Corrosion Task Group

Responsible for developing Guide Material, ANSI Technical Reports, and other technical material as directed by the Main Body. Ram Veerapaneni, DTE Gas Company, Chair James McKenzie, Atmos Energy Corporation, Secretary Glen Armstrong, EN Engineering Aaron Bass, Interstate Energy Company Frank Bennett, UGI Utilities, Inc. John Chin, TransCanada Corporation Allan Clarke, Consultant Kalu Kelly Emeaba, National Transportation Safety Board Robert Fassett, E2 Consulting Engineers Anthony Fuhrman, Public Service Electric & Gas Narinder Grewal, AG Square, Inc. Brent Koym, CenterPoint Energy Ray Lewis, ROSEN USA

Thomas Marlow, Vectren Corporation Theron McLaren, U.S. Department of Transportation - PHMSA Lane Miller, TRC Solutions Daniel O'Leary, Timberline Tool Paul Oleksa, Oleksa and Associates, Inc. Christopher Pioli, Jacobs Consultancy Timothy Strommen, WE Energies Steven Troch, BGE, An Exelon Company Erich Trombley, Southwest Gas Corporation Jim Walton, JW’s Pipeline Integrity Services David Wartluft, Continental Industries Gary White, PI Confluence, Inc. Brian Wolf, Hatch Mott MacDonald Anson Wong, Southern California Gas Company



xxi

Operations & Maintenance / Operator Qualification Task Group Jerome Themig, Retired, Chair Douglas Lee, KLJ Progress Solutions, Secretary Erik Anderson, Northwestern Energy Randy Bareither, Avista Utilities Stephen Bateman, Retired Stephen Beatty, LG&E-KU, PPL Companies Robert Becken, Energy Experts International Andrew Benedict, Opvantek Inc. Michelle Blanchard, Alliant Energy David Bonner, PECO Energy, An Exelon Company David Bull, ViaData LP John Butler, EQT Midstream Robert Cadorin, TransCanada Corporation Brain Camfield, PECO Energy, An Exelon Company Willard Carey, Energy Experts International Leo Cody, Liberty Utilities Mark Connors, UGI Utilities, Inc. Denise Dolezal, Metropolitan Utilities District John Erickson, American Public Gas Association Matthew Esmacher, Washington Gas Light Co Michael Falk, Xcel Energy Chris Foley, RCP Inc. Mark Forster, Southern California Gas Lloyd Freeman, Southern California Gas Mary Friend, Public Service Commission of West Virginia

Steven Groeber, Gas Operations Consultant John Groot, Southern California Gas Company George Hamaty, TransCanada / Columbia Pipeline Group Renee Hermiller, Marathon Petroleum Corporation Matt Hill, Vectren Steven Huntington, System One Services James Johnston, McElroy Manufacturing, Inc. John Kottwitz, Missouri Public Service Commission George Lomax, Heath Consultants Incorporated Jamie Garland, Maine Natural Gas John Goetz, Meade John Lueders, DTE Gas Company Sean Lynn, Xcel Energy Inc. Christine Maynard, NiSource, Inc. Erin McKay, Hilcorp Alaska, LLC Rich Medcalf, Indiana Utility Regulatory Commission Robert Naper, Energy Experts International Joseph Opert, BGE, An Exelon Company Kenneth Peters, Kinder Morgan Inc. Alice Ratcliffe, Crestwood Midstream Charles Rayot, Ameren Illinois Walter Siedlecki, AEGIS Insurance Services, Inc. David Spangler, NPL Alfredo Ulanday, EN Engineering Thomas Webb, Peoples Gas Light & Coke

Plastic Task Group

Responsible for developing Guide Material, ANSI Technical Reports, and other technical material as directed by the Main Body. Richard Slagle, Southern Company Gas, Chair Frank Volgstadt, Volgstadt & Associates, Secretary Glen Armstrong, EN Engineering DeWitt Burdeaux, TRC Solutions Heath Casteel, Performance Pipe Allison Crabtree, DuraLine Gregory Goble, R.W. Lyall & Company, Inc. Richard Huriaux, Consulting Engineer James Johnston, Jr., McElroy Manufacturing, Inc.

Randy Knapp, Plastics Pipe Institute William Luff, JANA Corp. Joel Martell, Southwest Gas Mary Lee McDonald, Performance Pipe Jeffrey Meyers, Black & Veatch Corporation Lane Miller, TRC Solutions Eugene Palermo, Palermo Plastics Pipe Consulting Patrick Seamands, Retired Parashar Sheth, National Grid

Committee Scope The Gas Piping Technology Committee (GPTC) is an independent technical group of individuals with expertise in, and concern for, natural gas pipeline safety and is responsible for:

• Developing and maintaining the Guide for Gas Transmission, Distribution, and Gathering Piping Systems (Guide), an American National Standards Institute (ANSI) Standard, that contains information and methods to assist a natural gas pipeline operator (operator) in complying with the Code of Federal Regulations "Transportation of Natural and Other Gas by Pipeline: Title 49, Subchapter D - Pipeline Safety - Part 191 - Annual Reports, Incident Reports, and Safety-Related Condition Reports; and Part 192 - Minimum Federal Safety Standards" by providing "how to" information related to the standards. Guide material is advisory in nature. Operators may use the guide material or other equally acceptable methods of compliance with the Federal Regulations.

• Developing and maintaining ANSI Technical Reports regarding the application of natural gas pipeline technology and operating or maintenance practices.

• Promoting the use of voluntary consensus standards.


xxii

• Petitioning the United States Department of Transportation (DOT) for changes in Federal Natural Gas Pipeline Safety Regulations based on the technical expertise of the GPTC.

• When deemed appropriate by the Main Body, commenting on Advanced Notice of Proposed Rulemakings, Notice of Proposed Rulemakings, Final Rules, and other regulatory notices issued by DOT involving such regulations.

• Reviewing applicable National Transportation Safety Board (NTSB) reports, DOT and State Pipeline Safety Agency incident reports, and taking appropriate action including that of responding to recommendations issued to the GPTC.

• Taking such actions that are necessary and proper to further the safe application of natural gas pipeline technology.


Addendum 9, August 2018

xxiii

GAS PIPING TECHNOLOGY COMMITTEE: Listed by Member Participation DIVISIONS TASK GROUPS SECTIONS Abbreviations: Chairperson: Chair First Vice Chairperson: 1st V Chair Second Vice Chairperson: 2nd V Chair Secretary: Sec Damage Prevention - Emergency Response: DP/ER Operations and Maintenance - Operator Qualification: O&M/OQ

M

ain Body

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istribution

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esign

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Plastic Pipe

Editorial

Executive

Liaison

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egulations

Abraham, Richard A. Retired, Findlay, OH X X X

Anderson, Erik Northwestern Energy, Butte, MT X X X

Armstrong, Glen F. EN Engineering, Warrenville, IL X X X X X

Bareither, Randy K. Avista Utilities, Spokane, WA X X X

Bass, Aaron G. Interstate Energy Company, Pottstown, PA X X

Bateman, Stephen C. Retired, Long Beach, CA X X X X X

Beatty, Stephen A. Louisville Gas & Electric, Louisville, KY X X X

Becken, Robert C. Energy Experts International, Pleasant Hill, CA X X X

Bellman, Mike American Gas Association, Washington, DC Sec Sec



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GAS PIPING TECHNOLOGY COMMITTEE: Listed by Member Participation (Continued) DIVISIONS TASK GROUPS SECTIONS Abbreviations: Chairperson: Chair First Vice Chairperson: 1st V Chair Second Vice Chairperson: 2nd V Chair Secretary: Sec Damage Prevention - Emergency Response: DP/ER Operations and Maintenance - Operator Qualification: O&M/OQ

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ain Body

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istribution

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P/ER

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Editorial

Executive

Liaison

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egulations

Benedict, Andrew G. Opvantek, Inc., Newtown, PA X X X

Bennett, Frank M. UGI Utilities, Reading, PA X X X X X

Blanchard, Michelle Alliant Energy X X X

Bonner, David T. PECO Energy, An Exelon Company, Philadelphia, PA

X X

Bull, David E. ViaData LP, Noblesville, IN X X Chair X X X

Burdeaux, DeWitt TRC Solutions, Kansas City, MO X X X X

Butler, John EQT Midstream, Charleston, WV X X X X X

Cadorin, Robert J. TransCanada Corp., Troy, MI X Sec X

Camfield, Brian PECO Energy, An Exelon Company, Philadelphia, PA

X X X

Carey, Willard S. Energy Experts International, Neptune, NJ X X X X

Casteel, Heath W. Performance Pipe, Plano, TX X X X



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istribution

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Editorial

Executive

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egulations

Chin, John S. TransCanada Corp., Troy, MI X X X X X

Clarke, Allan M. Consultant, Katy, TX X X X X

Cody, Leo T. Liberty Utilities, Salem, NH X X X X

Conners, Mark C. UGI Utilities, Reading, PA X X X

Crabtree, Allison DuraLine, Vernon, TX X X X

Del Buono, Amerigo J. Weldbend Corp., League City, TX X X

Dolezal, Denise L. Metropolitan Utilities District, Omaha, NE X X X

Dyck, Rodney I.J. PHMSA, Washington, DC X X X

Emeaba, Kalu Kelly NTSB, Washington, DC X X X

Erickson, John P. American Public Gas Association, Washington, DC X X X

Esmacher, Matthew Washington Gas Light Co, Springfield, VA X X X

Falk, Michael Xcel Energy, Denver, CO X X X

Fassett, Robert P. E2 Consulting Engineers, Emeryville, CA X X X



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Editorial

Executive

Liaison

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egulations

Foley, Chris RCP Inc., Houston, TX X X X

Forster, Mark Southern California Gas, Los Angeles, CA X X X

Freeman, Lloyd Southern California Gas, Los Angeles, CA X X X

Friend, Mary S. WV PSC, Charleston, WV / NAPSR X X X X

Fuhrman, Anthony Public Service Electric & Gas, Newark, NJ X X X

Garland, Jamie Maine Natural Gas, Brunswick, ME X X X

Gauthier, Steven W. Energy Experts International, Inverness, IL X X

Goble, Gregory H. R. W. Lyall & Co., Corona, CA X X X X

Goetz, John Meade, McCook, IL X X

Grewal, Narinder AG Square, Inc., Sugar Grove, IL X X X



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Editorial

Executive

Liaison

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egulations

Groeber, Steven A. Gas Operations Consultant, Cinnaminson, NJ X X X X X

Groot, John M. Southern California Gas, Los Angeles, CA X X X X

Hamaty, George TransCanada/Columbia Pipeline Group, Charleston, WV

X X X

Hermiller, Renee Marathon Petroleum Corporation, Findlay, OH X X X

Hill, Matt Vectren, Evansville, IN X X X

Huntington, Steven System One Services, Pittsburgh, PA X X

Huriaux, Richard D. Consulting Engineer, Baltimore, MD X X X X

Johnston Jr., James S. McElroy Manufacturing, Inc., Tulsa, OK X X X

Knapp, Randy Plastics Pipe Institute, Irving, TX X X X X


Addendum 9, August 2018 xxviii

GAS PIPING TECHNOLOGY COMMITTEE: Listed by Member Participation (Continued) DIVISIONS TASK GROUPS SECTIONS Abbreviations: Chairperson: Chair` First Vice Chairperson: 1st V Chair Second Vice Chairperson: 2nd V Chair Secretary: Sec Damage Prevention - Emergency Response: DP/ER Operations and Maintenance - Operator Qualification: O&M/OQ

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istribution

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Executive

Liaison

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egulations

Kottwitz, John D. MO Public Service Comm., Jefferson City, MO X X X X Chair X

Koym, Brent L. CenterPoint Energy, Houston, TX X X X

Lee, Douglas M. Consultant, Bismarck, ND X Sec Sec

Lewis, Raymond D. Retired, Houston, TX X X

Lomax, George S. Heath Consultants Inc., Montoursville, PA X X X X

Lueders, John D. DTE Gas Company, Grand Rapids, MI X Chair X X X

Luff, William JM JANA Corp., Toronto, ON X X X

Lynn, Sean Xcel Energy, Denver, CO X X X

Marlow, Thomas B. PRCI, Chantilly, VA X X X

Martell, Joel Southwest Gas, Las Vegas, NV X X X


Addendum 9, August 2018 xxix


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Editorial

Executive

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Maynard, Christine NiSource, Inc., Columbus, OH X Sec X X

McDonald, Mary Lee Performance Pipe, Plano TX X X

McKay, Erin Hilcorp Alaska, LLC, Anchorage, AK X X X

McKenzie, James E. Atmos Energy Corp., Jackson, MS X X Chair Sec X X

McLaren, Theron C. (Chris) PHMSA , Washington, DC X X X X

Medcalf, Rich Indiana Utility Regulatory Commission, Indianapolis, IN

X X

Meyers, Jeffrey Black & Veatch Corporation, Knoxville, TN X X X

Miller, D. Lane TRC Solutions, Kansas City, MO Sec X X Sec

Naper, Robert C. Energy Experts International, Canton, MA X X X X X

O’Leary, Daniel Timberline Tool, Kalispell, MT X X X

Oleksa, Paul E. Oleksa & Assoc., Broadview Heights, OH X X X X

Opert, Joseph BGE, An Exelon Company, Baltimore, MD X X X X Chair


Addendum 9, August 2018 xxx


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Editorial

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egulations

Palermo, Eugene F. Palermo Plastics Pipe Consulting, Friendsville, TN X Chair X X X X

Peters, Kenneth C. Kinder Morgan, Birmingham, AL X Chair X X X

Pioli, Christopher A. Jacobs Consultancy, Ventura, CA X X X

Quezada, Leticia Southern Company Gas, Naperville, IL Chair X

Ratcliffe, Alice Crestwood Midstream, Fort Worth, TX X X X X X Chair

Rayot, Charles Ameren, IL, Pawnee, IL X X X

Reynolds, Donald Lee NiSource Gas Distribution, Columbus, OH

1st V Chair Chair

Schmidt, Robert A. Canadoil Forge, Russellville, AR X X X


Addendum 9, August 2018 xxxi


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Seamands, Patrick A. Retired, St. Louis, MO X X X X

Sher, Philip Philip Sher Pipeline Consultant, Cheshire, CT

2nd V Chair X

Sheth, Parashar National Grid, Hicksville, NY X X X

Siedlecki, Walter V. AEGIS Insurance Services, Inc., East Rutherford, NJ X X X X

Slagle, Richard L. Southern Company Gas, Atlanta, GA X X X Chair X

Spangler, David NPL, Manassas, VA X X X

Strommen, Timothy D. WE Energies, Milwaukee, WI X X X

Terzian, David National Grid, Waltham, MA X X

Themig, Jerome S. Retired, Springfield, IL X X X Chair X

Troch, Steven J. BGE, An Exelon Company, Baltimore, MD X X X X


Addendum 9, August 2018 xxxii

GAS PIPING TECHNOLOGY COMMITTEE: Listed by Member Participation (Continued)

DIVISIONS TASK GROUPS SECTIONS Abbreviations: Chairperson: Chair First Vice Chairperson: 1st V Chair Second Vice Chairperson: 2nd V Chair Secretary: Sec Damage Prevention - Emergency Response: DP/ER Operations and Maintenance - Operator Qualification: O&M/OQ

M

ain Body

D

istribution

M

anufacturers

Transm

ission

D

esign

D

P/ER

IM

P/Corrosion

O

&M

/OQ

Plastic Pipe

Editorial

Executive

Liaison

R

egulations

Trombley, Erich D. Southwest Gas Corp., Las Vegas, NV X X X

Ulanday, Alfredo (Fred) S. EN Engineering, Warrenville, IL X X X X

Veerapaneni, Ram DTE Gas Company, Detroit, MI X X X Chair X X

Volgstadt, Frank R. Volgstadt & Associates, Madison, OH X Sec X Sec

Walton, Jim JW’s Pipeline Integrity Services, Carrollton, TX X X X

Wartluft, David C. Continental Industries, Broken Arrow, OK X X X

Webb, Thomas Peoples Gas Light & Coke X X

White, Gary R. PI Confluence, Inc., Humble, TX X X

Wolf, Brian Hatch Mott MacDonald, Holyoke, MA X X X

Wong, Anson Southern California Gas Company, Los Angeles, CA

X X X


xxxiii

LETTER TO GAS PIPING TECHNOLOGY COMMITTEE FROM THE U.S. DEPARTMENT OF TRANSPORTATION


xxxiv

AMERICAN GAS ASSOCIATION (AGA) NOTICE AND DISCLAIMER

This document was developed through a voluntary consensus standards development process via the American National Standards Institute (ANSI) ANSI Essential Requirements Due process requirement for American National Standards (Edition January 2014). While AGA administers the process and establishes rules to promote fairness in the development of consensus, it does not write the document and it does not independently test, evaluate, or verify the accuracy or completeness of any information or the soundness of any judgments contained in this publication. The AGA disclaims liability for any personal injury, property or other damages of any nature whatsoever, whether special, indirect, consequential or compensatory, directly or indirectly resulting from this publication, use of, or reliance on this publication. The AGA also makes no guaranty or warranty as to the accuracy or completeness of any information published herein. In issuing and making this document available, the AGA is not undertaking to render professional or other services for or on behalf of any person or entity. Nor is the AGA undertaking to perform any duty owed by any person or entity to someone else. Anyone using this document should rely on his or her own independent judgment or, as appropriate, seek the advice of a competent professional in determining the exercise of reasonable care in any given circumstances. The AGA has no power, nor does it undertake, to police or enforce compliance with the contents of this document. Nor does the AGA list, certify, test, or inspect products, designs, or installations for compliance with this document. Any certification or other statement of compliance with the requirements of this document shall not be attributable to the AGA and is solely the responsibility of the certifier or maker of the statement. The AGA does not take any position with respect to the validity of any patent rights asserted in connection with any items which are mentioned in or are the subject of this publication, and the AGA disclaims liability for the infringement of any patent resulting from the use of or reliance on it. Users of this publication are expressly advised that determination of the validity of any such patent rights, and the risk of infringement of such rights, is entirely their own responsibility. Users of this publication should consult applicable federal, state, and local laws and regulations. The AGA does not, through this publication, provide legal advice for any purpose or intend to urge action that is not in compliance with applicable laws, and this publication may not be construed as doing so. Changes to this document may become necessary from time to time. If changes are believed appropriate by any person or entity, such suggested changes should be communicated to AGA in writing using the form found at the end of the document titled, Form For Proposals on ANSI GPTC Z380.1 and sent to: American Gas Association, ATTN: Secretariat GPTC Z380, 400 North Capitol Street, NW, Suite 450, Washington, DC 20001, U.S.A. Suggested changes must include: contact information, including name, address and any corporate affiliation; full name of the document; suggested revisions to the text of the document; the rationale for the suggested revisions; and permission to use the suggested revisions in an amended publication of the document.


xxxv

EDITORIAL CONVENTIONS OF THE GUIDE

Practices Used in the Guide ♦ If the guide material does not cover all the specific elements in a section of the Federal Regulations

(Regulation(s)), and there is no editorial note, no other guide material has been deemed necessary by the Gas Piping Technology Committee (Committee).

♦ The term "includes" does not limit any list to those items presented and means, "includes but not limited

to." This term is used in the same manner as it is used in the Regulations (reference §192.15). Further, added qualifiers such as "may" or "might" are sometimes used to emphasize that a list is not intended to set a minimum requirement or practice.

♦ The term "should" indicates recommendations that are not mandatory, but are to be acted upon as

appropriate. As such, this guide material is advisory in nature, and operators may use it (or other equally acceptable methods) for a regulatory compliance aid.

♦ All figures and tables located in the basic guide material are designated by the corresponding Regulation

section number followed by a capital letter for figures (sequentially), or lower case Roman numeral for tables (e.g., FIGURE 192.485A or TABLE 192.485i).

♦ The date shown in the title block for each section is the effective date of the original Regulation or its

latest amendment. ♦ Sections of the Regulations that have been deleted are not listed by title in the Contents unless reserved

by the Regulations. However, the section numbers have been retained in the Guide, along with their effective date of removal (e.g., §192.57, Removed and reserved. [Effective 03/08/89]).

♦ Sections of the Regulations having a future effective date may be presented for both the current and new

requirements and with the effective date emphasized. In such case, the guide material is subject to review in light of the new requirements.

Common Notes in the Guide

♦ No guide material necessary. In the opinion of the Committee, the Regulation section is self-

explanatory and no additional information is provided. ♦ No guide material available at present. The Committee has not issued guide material or has not yet

determined if guide material is necessary. ♦ This guide material is under review following Amendment (either 19x-yy or control number). The

Committee is currently reviewing the amendment. ♦ Discontinued or Withdrawn. Where either of these words accompanies a listing of an industry standard

or other published reference, it indicates that the document is no longer current or has been withdrawn, and may not be available from its original source. The document may be available from an alternate source. When using such a document, care should be taken to determine the validity of the material and the reason for which it was discontinued or withdrawn.

♦ See §19x.xxx, refers to Regulation Section 19x.xxx and the guide material directly beneath it.


xxxvi

♦ See x of the guide material under §19y.yyy. This refers to Section x of the guide material directly beneath §19y.yyy.

♦ See x above (or below). This refers to Section x of the guide material in which the reference appears.

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Addendum 9, January 2018 219

(d) For fabricated units and short sections of pipe, for which a post installation test is impractical, a preinstallation strength test must be conducted by maintaining the pressure at or above the test pressure for at least 4 hours. [Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-94, 69 FR 32886, June 14, 2004 with Amdt. 192-94 Correction, 69 FR 54591, Sept. 9, 2004; Amdt. 192-120, 80 FR 12762, Mar. 11, 2015]

GUIDE MATERIAL 1 GENERAL The following preliminary considerations should be noted. (a) Because of the requirements of §192.611 and the possibility of a change in class location, especially

in Class 1 and Class 2 locations, a strength test to at least 90% SMYS is recommended. (b) A pipeline crossing a railroad, public road, street, or highway might be tested in the same manner

and to the same pressure as the pipe on each side of the crossing, recognizing that the pipeline in the crossing might have a different design factor. See §192.111 and the design formula under §192.105.

(c) Fabricated assemblies (e.g., mainline valve assemblies, crossover connections, and river crossing headers) installed in pipelines in Class 1 locations may be tested as required for Class 1 locations (even though §192.111 requires a Class 2 design factor).

(d) Testing against closed valves is not recommended. Testing should include the use of test manifolds. Blinds (e.g., flanges or plates) should be used as necessary to minimize testing against any closed valves. Where valves exist in a test section, they should remain in the open or manufacturer’s recommended position during the test. To ensure that air does not enter the gas system, testing with air against a closed valve that is connected to the gas system is not advisable.

(e) A single component with a valid ASME or MSS specification pressure rating may be installed without a pressure test. Rating examples are common designations, such as ASME Class 600. Corresponding temperature limits need to be considered for each pressure rating.

(f) For lateral connections to transmission lines and transmission line replacements, see Note (1) in Guide Material Appendix G-192-9.

2 TEST PROCEDURE The test procedure used should be selected after giving due consideration to items such as the

following. (a) Equipment to be used. (b) Test medium.* (c) Environment. (d) Elevation profile. (e) Volumetric content of the line. (f) Test pressure.* (g) Duration of the test.* (h) Location of the line. (i) The effects of temperature changes on the pressure of the test medium. (j) The reason for the strength test. (1) New construction. (2) Pipe replacement. (3) Class location changes. (4) Uprating. (5) Integrity assessment.* (6) Other as deemed appropriate by the operator. *See Guide Material Appendices G-192-9 and G-192-9A.

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220

3 HYDROSTATIC TEST 3.1 Test preparation. It is recommended that the pipeline segment to be tested be physically isolated from all other pipelines.

See 1(d) above. Testing against closed valves is not recommended. Weld caps, blind flanges, or other devices of appropriate design should be utilized to seal pipe ends. It is also recommended that spheres or squeegees be inserted in the pipeline ahead of the water to reduce air entrapment while filling and to facilitate dewatering operations.

3.2 Test evaluation.

(a) General. In order that intelligent interpretation of pressure variations can be made, it is important that

accurate thermometers, deadweight pressure gauges, meters, etc., be used and that the readings be taken at properly located points and at proper intervals of time. The use of a pressure-volume plot is recommended for tests that are planned to approach SMYS.

(b) Small changes in pressure during hold period. Experience has shown that a small steady decline in pressure often occurs during the hold period.

This does not necessarily indicate the existence of a leak. Such declines can often be caused by a change in temperature of the test liquid, a small entrapment of air, or a leaking gauge connection. A pressure rise is usually caused by the warming of air trapped in the structure or the warming of the test liquid or both. When an appreciable amount of pipe is exposed to atmosphere (not backfilled) during the test, temperature effects are sometimes quite pronounced. In the event of a small steady pressure decline, it is considered good practice to periodically add liquid, thereby maintaining the desired pressure until the hold period is completed. Likewise, it is also considered good practice to bleed off small quantities of test liquid to prevent exceeding the maximum selected pressure.

3.3 Locating minor leaks. When a hydrostatic strength proof test has been completed and there are indications of a minor leak

which was not located during the test, the line may be filled with natural or other detectable gas at a pressure less than or equal to the maximum allowable operating pressure of the section of line being tested; and a suitable gas detection device (e.g., flame ionization analyzer, controlled catalytic combustion unit, infrared analyzer, or nitrous oxide detector) used to search for the leak.

3.4 Repairs. Temporary repairs may be made in order not to interrupt the test, and a permanent repair made after

completing the test and before placing the line in service. If permanent repairs are made after the conclusion of the test using pretested pipe, the tie-in welds must be inspected in accordance with §192.241.

4 AIR, INERT, OR NATURAL GAS TEST Maximum hoop stress limitations are specified by §192.503(c). More stringent requirements for

conducting such strength tests within 300 feet of buildings designed for human occupancy are specified by §192.505(a).

4.1 Test preparation. (a) It is recommended that the pipeline segment to be tested be physically isolated from all other

pipelines. See 1(d) above. Testing against closed valves is not recommended. Weld caps, blind flanges, or other devices of appropriate design should be utilized to seal pipe ends.

(b) Purging should be considered to prevent an explosive air-gas mixture in the test segment. Refer to §§192.629 and 192.751 and the accompanying guide material.

GPTC GUIDE FOR GAS TRANSMISSION, DISTRIBUTION, §192.612 AND GATHERING PIPING SYSTEMS: 2015 Edition SUBPART L


3 REPORTING (§192.612(c)(1))

In addition to the reporting requirements of §192.612(c)(1), an operator should also consider including the following.

(a) Latitude and longitude of the pipeline end points. (b) Offshore area name. (c) Offshore block number. (d) Name of water body. (e) Name of parish or county. (f) Other pertinent information. 4 REMEDIAL ACTION

If an operator is unable to meet the deadline for remediation, the required notification to OPS should be in writing.

§192.613 Continuing surveillance.

[Effective Date: 11/12/70]

(a) Each operator shall have a procedure for continuing surveillance of its facilities to determine and take appropriate action concerning changes in class location, failures, leakage history, corrosion, substantial changes in cathodic protection requirements, and other unusual operating and maintenance conditions. (b) If a segment of pipeline is determined to be in unsatisfactory condition but no immediate hazard exists, the operator shall initiate a program to recondition or phase out the segment involved, or, if the segment cannot be reconditioned or phased out, reduce the maximum allowable operating pressure in accordance with §192.619(a) and (b).

GUIDE MATERIAL 1 GENERAL Continuing surveillance should be conducted to identify any pipeline facilities experiencing abnormal or

unusual operating and maintenance conditions. This may be accomplished by the following. (a) Periodic visual inspection of pipeline facilities to identify items such as the following. (1) Changes in population densities. (2) Effects of changes in topography. (3) Effects of exposure or movement. (4) Effects of encroachments. (5) Specific circumstances relating to patrolling and leakage. See guide material under §§192.705,

192.706, 192.721, and 192.723. (6) Potential for, or evidence of: (i) Excavation activity.

Note: If evidence of an excavation is found near a transmission pipeline covered segment, the location must be examined in accordance with §192.935(b)(1)(iv).

(ii) Tampering, vandalism, or damage. (iii) Flooding. See 6 below (iv) Mining activity. See Guide Material Appendix G-192-13. (v) Soil or water accumulation in vaults or pits. (vi) Gas migration through air intakes into buildings from vaults and pits.



(vii) Excessive snow and ice build-up on aboveground facilities (e.g., meter sets, pressure control equipment, heaters) that could affect their function.

(b) Periodic review and analysis of records, such as the following. (1) Patrols. (2) Leak surveys. (3) Valve inspections. (4) Vault inspections. (5) Pressure regulating, relieving, and limiting equipment inspections. (6) Corrosion control inspections. (7) Facility failure investigations.

Anomalies discovered should be evaluated, and those determined to present potential safety concerns should be scheduled for remediation and communicated to appropriate integrity management personnel.

2 CAST IRON PIPELINES For cast iron pipelines, see Guide Material Appendix G-192-18. 3 PE PIPELINES (a) Some PE materials manufactured before 1982 have a lower resistance to the effects of induced

stresses and are subject to brittle-like cracking under certain in-service conditions (e.g., rock impingement, squeeze-offs, severe bending moments). Brittle-like cracking is characterized by a part-through crack initiating in the pipe wall followed by slow crack growth causing failure. These failures result in a tight slit-like opening and a gas leak. This older generation of PE may have leak-free performance for a number of years before brittle-like cracks occur. An increase in the occurrence of leaks is typically the first indication of a brittle-like cracking problem.

(b) PE materials that are most known for this failure mode include the following. (1) Century Utility Products, Inc. products. (2) Low-ductile inner wall PE 2306 "Aldyl A" pipe manufactured by DuPont Company during 1970

through 1972, generally NPS 1¼ to NPS 4. To determine if the "Aldyl A" pipe has low-ductile inner wall, see 3(f) below.

(3) PE gas pipe designated PE 3306. (4) DuPont PE tapping tees with DuPont Delrin® polyacetal (homopolymer) inserts (see 3(g)

below). (5) Plexco PE service tees with Celanese Celcon® polyacetal (copolymer) caps (see 3(h) below). (c) Conditions that may cause these types of materials to fail prematurely include the following. (1) Inadequate support and backfill during installation. (2) Tree root or rock impingement. (3) Shear and bending stresses due to differential settlement resulting from factors such as: (i) Excavation in close proximity to PE piping. (ii) Directional drilling in close proximity to PE piping. (iii) Frost heave. (4) Bending stresses due to pipe installations with bends exceeding recommended practices. (5) Stresses where the pipe has been squeezed off. (d) Each operator that has these older PE pipelines should consider the following practices. (1) Review system records to determine if any known susceptible materials have been installed in

the system. (2) Perform more frequent inspection and leak surveys on systems that have exhibited brittle-like

cracking failures of known susceptible materials. (3) Collect failure samples of PE piping exhibiting brittle-like cracking. (4) Record the print line from any piping that has been involved in a failure. The print line

information can be used to identify the resin, manufacturer, and year of manufacture for plastic piping.



(d) Priority to protect life. Emphasize that personal safety and the protection of human life should always be given higher

priority than protection of property. (e) Damage prevention. See 2.5 of the guide material under §192.614. 2.4 Additional information. Distribution system operators may choose to include additional messages for recognizing and reporting

types of hazards or potential hazards not addressed by API RP 1162, such as the following. (a) Heavy snow accumulation on meter set assemblies and a safe method of snow removal from meter

set assemblies to prevent equipment damage (e.g., use of a broom instead of a shovel). (b) Snow or ice falling or being shoveled from roofs onto gas facilities. (c) Ice buildup on regulators or regulator vents. (d) Carbon monoxide hazards from snow and ice buildup around combustion air and exhaust vents for

gas appliances. (e) Flooding that might affect gas facilities. 2.5 Message delivery methods. Guidance is provided in API RP 1162, Section 5 for several delivery methods and tools available for

communicating with the stakeholder audiences. See 2.4 of the guide material under §192.614 for additional information regarding delivery methods for excavators and the affected public. However, the operator is required by §192.616(c) to justify in its program or procedural manual if it does not follow the general program recommendations of API RP 1162 regarding message delivery methods.

3 LANGUAGE The following may provide indications of languages in addition to English to consider when conducting

public education programs. (a) Languages prescribed by state or local governments. (b) Commercial non-English radio, television, and print media. (c) U.S. Census data. 4 REFERENCES (a) Information regarding public education programs, such as FAQs and Workshops, is available at

primis.phmsa.dot.gov/comm/PublicEducation.htm. (b) OPS Advisory Bulletins (see Guide Material Appendix G-192-1, Section 2) as follows. (1) ADB-93-01 (58 FR 7034, Feb. 3, 1993). (2) ADB-97-01 (Issued in Kansas City, MO on Jan.24, 1997). (3) ADB-08-03 (73 FR 12796, Mar. 10, 2008). (4) ADB-11-02 (76 FR 7238, Feb. 9, 2011).

§192.617 Investigation of failures.

[Effective Date: 11/12/70]

Each operator shall establish procedures for analyzing accidents and failures, including the selection of samples of the failed facility or equipment for laboratory examination, where appropriate, for the purpose of determining the causes of the failure and minimizing the possibility of a recurrence.


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GUIDE MATERIAL

1 GENERAL (a) Data on all failures and leaks should be compiled to support compliance with §192.613. A failure

investigation should be performed to determine the cause of the failure and minimize the possibility of a recurrence.

(b) For information on failures of PE pipe, see 3 of the guide material under §192.613. (c) For information on reporting failures of mechanical fittings, see guide material under §191.12. 2 TYPES AND NATURE OF FAILURES THAT SHOULD BE ANALYZED

Failure investigation should be conducted for incidents as defined in §191.3. An operator should also consider investigating any other failure that enables the operator to establish patterns that might be occurring on its pipeline system. For examples, see guide material under §192.613.

3 FAILURE INVESTIGATION (a) Failure investigation and subsequent analysis should determine the root cause(s) of the failure. The

investigation may be as simple as assembling an internal review group or as complex as conducting a full-scale failure investigation with laboratory analysis of a failed component. The information for completing a 30-day incident report form contained in Part 191 may constitute an adequate analysis of a reportable failure or leak. See §§191.9 and 191.15.

(b) The general process for performing root-cause analysis is as follows. (1) Assemble the review team. (2) Define the problem and gather data and documentation. (3) Identify factors that contributed to the problem (i.e., causal factors). (4) Find the root cause for each causal factor, such as people, equipment, material, process, or

outside influence. (5) Develop and assign recommendations. (6) Distribute recommendations and review the operator’s procedures. (7) Implement the recommendations. 4 RESPONSE TO FAILURE If a detailed analysis is to be made, rapid response will be necessary for preserving the integrity of

specimens and gathering information. 5 DATA COLLECTION 5.1 Incident. When a detailed analysis is to be made, a person at the scene of the incident should be designated to

coordinate the investigation. That person's responsibilities should include the following. (a) Acting as a coordinator for all field investigative personnel. (b) Maintaining a log of the personnel, equipment, and witnesses. (c) Recording in chronological order the events as they take place. (d) Ensuring that photographs are taken of the incident and surrounding areas. These photographs

may be of great value in the investigation. (e) Ensuring the notification of all appropriate governmental authorities. (f) Ensuring the preservation of evidence. 5.2 Other failures. Gather sufficient data to complete the general process for performing root-cause analysis. See 3 above.

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Note: It is required that operators using ECDA develop and implement a direct assessment plan following ASME B31.8S and NACE SP0502 (see §192.925(b)). Some operators, however, may elect to organize the activities required within each of the 4 steps differently. For example, NACE SP0502 includes determining the minimum number of excavations (digs) in the direct examination step, whereas an operator may elect to include this item in its indirect inspection step. This re-organization of ECDA activities is generally acceptable, provided that all activities are addressed in the operator’s direct assessment plan.

3 PRE-ASSESSMENT STEP The objectives of the pre-assessment step are to collect and analyze data to determine ECDA feasibility,

define ECDA regions, and select indirect inspection tools. 3.1 Data collection. (a) An operator is required to define minimum data requirements based on the history and condition of

the pipeline to determine the feasibility of ECDA (NACE 3.2.1.1). The operator is also required to define data elements for five pipeline data categories: pipe-related, construction-related, soils / environment, corrosion control, and operational data (NACE 3.2.2). NACE SP0502 provides examples of data elements for each category.

Table 192.925i provides examples of data elements that may be considered critical for justifying the

feasibility of ECDA. The operator should document why a data element listed in NACE SP0502, Table 1 was or was not selected as critical. See §192.947(d).

Category Examples of Critical Data Elements

Pipe-related Pipe material (e.g., steel) Pipe bare or coated

Construction-related Location of known casings Excessive depth that restricts indirect inspection tool use Water crossings Line crossings that affect CP Location of high-voltage lines

Soils/Environment Soil characteristics (e.g., clay, rock) Paved versus non-paved surfaces Frozen ground

Corrosion Control CP type (anodes versus rectifiers) Coating condition, such as disbonded coating

Operational Data Repair history (repair types, locations, and causes)

TABLE 192.925i (b) Data may be obtained from various sources, including the following. (1) Operating and maintenance records. (2) Alignment sheets. (3) Aerial photography. (4) Risk assessment process. (5) Subject matter expert input. (6) Geographic information system (GIS). (7) Field verification.



3.2 ECDA feasibility. (a) Analysis of data is required to determine if ECDA is feasible (NACE 3.3.1). This analysis should

include determining the following. (1) Does sufficient data exist about the covered segment to support the pre-assessment step? (2) Is pipeline right-of-way accessible by personnel performing indirect inspections? (3) Can indirect inspection tools be used over the pipeline? (4) Do conditions exist that would make ECDA data difficult to interpret? These might include the

following. (i) Electric shielding of cathodic protection current. (ii) Significant rock in the backfill or surrounding the pipe. (iii) Other buried structure impacting electrical measurements. (5) What other information does the operator deem appropriate for analysis (e.g., AC interference)?

(b) Cased pipe can present challenges to conducting a successful integrity assessment using ECDA. NACE 3.3.2 states that there are locations where indirect inspections are not practicable such as certain cased crossings. Examples of factors that could make ECDA not feasible for cased crossings include the following. (1) Lack of data about the carrier pipe or casing. (2) Length of crossing. (3) Depth of crossing.

(c) If data cannot be collected to support the pre-assessment step, ECDA cannot be used as the primary integrity assessment method.

(d) During the analysis of the data, if it is determined that other potential threats exist on the line, the operator should evaluate the significance of the other threat(s) and determine whether other assessment methods are appropriate.

3.3 Selection of indirect inspection tools.

(a) The selection of indirect inspection tools is based on their ability to reliably detect potential corrosion activity or coating holidays. The operator is required to document the basis for tool selection (see §192.925(b)(1)(ii)). Factors to consider when documenting the basis include the following. (1) Expected level of performance of each tool. (2) The nature of the data or information that can reasonably be expected from each tool. (3) Limitations of each tool.

(b) Section 192.925(b)(1)(ii) requires a minimum of two complementary indirect inspection tools for

each ECDA region within a covered pipeline segment. "Complementary" (as explained by NACE 3.4) is the strengths of one tool compensating for the limitations of another tool. For example, a strength of a close-interval survey is that it measures cathodic protection levels, but it is limited in its ability to identify coating holidays; whereas, a strength of a direct current voltage gradient (DCVG) survey is identifying coating holidays accurately, but it does not measure cathodic protection levels.

Examples of indirect inspection tools that are complementary include the following. (1) Close-interval and DCVG surveys. (2) Close-interval and AC current attenuation (electromagnetic) surveys. (3) Close-interval and alternating current voltage gradient (ACVG) surveys. (c) Indirect inspection tools not specifically listed in NACE SP0502 (e.g., ultrasonics, guided wave) are

allowed, but the operator is required to justify and document the following for any other inspection method that is used (see §192.925(b)(1)(ii)).

(1) Applicability. (2) Validation basis. (3) Utilization of data. (4) Equipment used. (5) Field procedure.


437

3.4 Identification of ECDA regions. (a) ECDA regions must be determined for each covered segment (NACE 3.5.1). The primary objective

for identifying different regions is to ensure that the proper indirect inspection methods are selected. A second objective is to identify the characteristics of the ECDA region that might influence the interpretation of the inspection data.

(b) An ECDA region does not need to be contiguous and can exist on multiple pipelines or pipeline segments. For example, an ECDA region can be separated along the pipeline if similar characteristics exist on either side of a river crossing. See NACE 3.5.

(c) An ECDA region is a section or sections of a pipeline that have the following. (1) Similar physical characteristics, such as: (i) Soil conditions. (ii) Corrosion protection mechanisms. (iii) River or large stream crossings. (iv) Paved roads. (v) Casings. (vi) Designated wetlands. (vii) Stray current areas. (viii) Coating type and conditions. (2) Similar operating histories, such as: (i) Leakage. (ii) Failures having the same root cause. (iii) MAOP. (3) Similar corrosion control histories, such as: (i) CP system type (impressed versus galvanic). (ii) CP criteria. (iii) CP levels. (iv) Corrosion control failures. (v) Years without CP. (4) Expected future corrosion conditions. (5) Same indirect inspection tools to be applied. Note: See NACE 2 and 3.5.1.1.1. (d) Region definitions or boundaries may change as more information is gathered through the ECDA

process. Changes to regions and the reasons for changes must be documented (see §192.947(d)). 3.5 First-time application. When conducting ECDA for the first time on a covered segment, an operator is required to apply more

stringent pre-assessment criteria (see §192.925(b)(1)(i)), such as one or more of the following. (a) Select more than two indirect inspection tools. (b) Perform test-hole inspections to verify data or gather additional data. Examples include the

following. (1) Soil resistivity. (2) Coating type and condition. (3) Soil conditions. (c) Increase the number of ECDA regions. 4 INDIRECT INSPECTION STEP 4.1 General. (a) The objective of this step is to use aboveground inspection techniques to identify and define the

severity of the following. (1) Coating faults. (2) Other anomalies (e.g., stray current interference, electrical shorts). (3) Areas where corrosion activity (e.g., insufficient CP current) may have occurred or may be


438

occurring. (b) In this step, two or more complementary indirect inspection tools are used over the entire covered

pipeline segment to provide improved detection reliability under the wide variety of conditions that may be encountered.

(c) This step is comprised of the following activities. (1) Conduct indirect inspections. (2) Align inspection data. (3) Determine indications. (4) Classify the severity of each indication. (5) Compare results for consistency. 4.2 Conduct indirect inspections. (a) ECDA region boundaries. Prior to conducting the indirect inspections, the boundaries (i.e., start and

stop) of each ECDA region are required to be identified unless the operator justifies and documents an alternative approach (NACE 4.2.1). Operators should consider noting the boundaries on an alignment sheet, pipeline map, or other document that indicates the covered segment to be inspected.

(b) Indirect inspection procedures. Operators may develop their own or review and accept other established procedures. When developing the required written procedures, the following factors should be considered.

(1) Electrical and other safety precautions. (2) Equipment and instrumentation operating and calibration instructions. (3) IR drop considerations. (4) Locating and marking pipe. (5) Survey spacing interval. (i) Routine survey. (ii) Suspected anomaly. (6) Data documentation. (7) Data quality review and analysis. (c) Indirect inspection overlaps. To ensure that an inspection is conducted over the entire length of

each ECDA region, operators should consider overlapping the inspections into adjacent regions. (d) Aboveground references. (1) Aboveground location measurements are required to be referenced to precise geographical

locations (e.g., global positioning system (GPS)) or permanent geographical features (e.g., edge of a road, isolation valve, valve basin cover, or test station) unless the operator justifies and documents an alternative approach (NACE 4.2.5).

(2) A sufficient number of easily located aboveground reference points should be identified to reduce spatial errors. These reference points should be documented to allow survey measurements to be aligned and used to identify excavation sites.

(e) Changes to facilities. No major changes to a covered segment (e.g., installation or abandonment of a pipeline) should be made between the use of the first and second inspection tools.

(f) Subsequent surveys. After completion of the first indirect inspection, the subsequent survey(s) should be done as soon as practicable to avoid changes in pipeline conditions. For example, seasonal changes affecting soil moisture content could make it difficult to correlate measurements between the surveys.

4.3 Align inspection data. After the indirect inspection measurements are obtained, data from each tool is required to be aligned

for comparison (NACE 4.3.1). An example of aligning inspection data may include the following. (a) First, align the data from the two or more tools for the region by comparing start and stop locations,

as well as the aboveground reference locations. In effect, this is overlaying the two or more data sets on top of a virtual centerline for comparison.



(vi) Severe indications. (vii) Moderate indications. (viii) Minor indications. (ix) Coating damages found. (c) An operator should evaluate the performance measure results by comparing previous assessment

results for trending purposes. An increased number of indications between assessments may not necessarily mean that the ECDA process is ineffective. An operator may consider the following when performing the evaluation.

(1) Pipeline failures between assessments. (2) Changes in prioritization criteria. (3) Expected aging effects on the coating. (4) Increased construction activity (e.g., light rail). (5) Significant changes to the pipeline environment. (6) Additions to the pipeline. (7) Suburban sprawl. (d) In the event that the evaluation of performance measures does not show ECDA to be effective, the

pipeline operator is required to reevaluate the ECDA application or consider alternative methods of assessing pipeline integrity unless the operator provides written justification (NACE 6.4.4).

6.5 Feedback (continuous improvement). (a) NACE 6.5.1 requires the operator to endeavor to improve the ECDA process by providing

opportunities to evaluate feedback from applicable processes. (b) NACE 6.5.2 requires the operator to consider including the following activities in the feedback

process. (1) Indication severity classification and priority categories. (2) Data collection during direct examinations. (3) In-process criteria evaluations. (4) Remaining strength evaluations. (5) Root-cause analyses. (6) Remediation activities. (7) Criteria for monitoring long-term ECDA effectiveness (e.g., reclassifications, reprioritizations). (8) Reassessment criteria. (9) Periodic reassessments. (10) Interactive threats. (c) An operator should verify that applicable records have been updated with the information captured

from applicable forms and records. 7 RECORDKEEPING (a) See NACE 7 for recordkeeping requirements. (b) ECDA records that are pertinent to the pre-assessment, indirect inspection, direct examination, and

post-assessment steps should be documented in a clear, concise, and workable manner. (c) Records of each ECDA step may be maintained at a central location, or at multiple locations. (d) Records may be maintained either electronically, as paper copies, or in any other appropriate

format. 8 REFERENCES (a) AGA Pipeline Research Committee PRCI Project PR-3-805, ''A Modified Criterion for Evaluating the

Remaining Strength of Corroded Pipe," (RSTRENG) (see §192.7). (b) ASME B31G, "Manual for Determining the Remaining Strength of Corroded Pipelines." (see

§192.7). (c) NACE SP0502-2010, "Pipeline External Corrosion Direct Assessment Methodology." (see §192.7). (d) PHMSA-OPS Protocols, "Gas Integrity Management Inspection Manual, Inspection Protocols with



456

Results Forms," specifically Section D, DA Plan. (e) GTI-04/0071, "External Corrosion Direct Assessment (ECDA) Implementation Protocol." (f) NACE SP0113, “Pipeline Integrity Method Selection.” (g) NACE SP0207, “Performing Close-Interval Potential Surveys and DC Surface Potential Gradient

Surveys on Buried or Submerged Metallic Pipelines.” (h) NACE TM0109, “Aboveground Survey Techniques for the Evaluation of Underground Pipeline

Coating Condition.” (i) NACE TM0497, “Measurement Techniques Related to Criteria for Cathodic Protection on

Underground or Submerged Metallic Piping Systems.” (j) PHMSA-OPS, “Guidelines for Integrity Assessment of Cased Pipe for Gas Transmission

Pipelines in HCAs.”

§192.927 What are the requirements for using

Internal Corrosion Direct Assessment (ICDA)? [Effective Date: 07/10/06]

(a) Definition. Internal Corrosion Direct Assessment (ICDA) is a process an operator uses to identify areas along the pipeline where fluid or other electrolyte introduced during normal operation or by an upset condition may reside, and then focuses direct examination on the locations in covered segments where internal corrosion is most likely to exist. The process identifies the potential for internal corrosion caused by microorganisms, or fluid with CO2, O2, hydrogen sulfide or other contaminants present in the gas. (b) General requirements. An operator using direct assessment as an assessment method to address internal corrosion in a covered pipeline segment must follow the requirements in this section and in ASME/ANSI B31.8S (incorporated by reference, see §192.7), section 6.4 and appendix B2. The ICDA process described in this section applies only for a segment of pipe transporting nominally dry natural gas, and not for a segment with electrolyte nominally present in the gas stream. If an operator uses ICDA to assess a covered segment operating with electrolyte present in the gas stream, the operator must develop a plan that demonstrates how it will conduct ICDA in the segment to effectively address internal corrosion, and must provide notification in accordance with §192.921(a)(4) or §192.937(c)(4). (c) The ICDA plan. An operator must develop and follow an ICDA plan that provides for preassessment, identification of ICDA regions and excavation locations, detailed examination of pipe at excavation locations, and post-assessment evaluation and monitoring. (1) Preassessment. In the preassessment stage, an operator must gather and integrate data and information needed to evaluate the feasibility of ICDA for the covered segment, and to support use of a model to identify the locations along the pipe segment where electrolyte may accumulate, to identify ICDA regions, and to identify areas within the covered segment where liquids may potentially be entrained. This data and information includes, but is not limited to — (i) All data elements listed in Appendix A2 of ASME/ANSI B31.8S; (ii) Information needed to support use of a model that an operator must use to identify areas along the pipeline where internal corrosion is most likely to occur. (See paragraph (a) of this section.) This information, includes, but is not limited to, location of all gas input and withdrawal points on the line; location of all low points on covered segments such as sags, drips, inclines, valves, manifolds, dead-legs, and traps; the elevation profile of the pipeline in sufficient detail that angles of inclination can be calculated for all pipe segments; and the diameter of the pipeline, and the range of expected gas velocities in the pipeline; (iii) Operating experience data that would indicate historic upsets in gas conditions, locations where these upsets have occurred, and potential damage resulting from these upset conditions; and (iv) Information on covered segments where cleaning pigs may not have been used or where cleaning pigs may deposit electrolytes.

GPTC GUIDE FOR GAS TRANSMISSION, DISTRIBUTION, Guide Material Appendix G-192-1 AND GATHERING PIPING SYSTEMS: 2015 Edition

Addendum 3, December 2015

561

1.5 FITTINGS: THREADED & SOCKET-WELD (Continued)

ASME B16.15 Cast Copper Alloy Threaded Fittings: Classes 125 and 250 §192.149

ASTM A733 Welded and Seamless Carbon Steel and Austenitic Stainless Steel Pipe Nipples

§192.149

MSS SP-79 Socket-Welding Reducer Inserts §192.149

MSS SP-83 Class 3000 Steel Pipe Unions, Socket-Welding and Threaded

§192.149

1.6 FITTINGS: WELDED

ASME B16.9 Factory-Made Wrought [Steel] Buttwelding Fittings (2007 Edition includes Short Radius Elbows and Returns)

§192.149

ASME B16.25 Buttwelding Ends

ASME B16.49 Factory-Made, Wrought Steel, Buttwelding Induction Bends for Transportation and Distribution Systems

§192.149

MSS SP-75 High Test Wrought Butt Welding Fittings §192.149 §192.157

1.7 MATERIALS & FITTINGS: MISCELLANEOUS

ANSI A21.14 Ductile Iron Fittings, 3-Inch Through 24-Inch for Gas (Revised 1989; Withdrawn 1994)

ASME B16.18 Cast Copper Alloy Solder Joint Pressure Fittings

ASME B16.22 Wrought Copper and Copper Alloy Solder Joint Pressure Fittings

ASTM A105 Carbon Steel Forgings for Piping Applications

ASTM A181 Carbon Steel Forgings for General-Purpose Piping

ASTM A182 Forged or Rolled Alloy and Stainless Steel Pipe Flanges, Forged Fittings, and Valves and Parts for High-Temperature Service

ASTM A234 Piping Fittings of Wrought Carbon Steel and Alloy Steel for Moderate and High Temperature Service

ASTM A350 Carbon and Low-Alloy Steel Forgings, Requiring Notch Toughness Testing for Piping Components

ASTM A403 Wrought Austenitic Stainless Steel Piping Fittings

ASTM A420 Piping Fittings of Wrought Carbon Steel and Alloy Steel for Low-Temperature Service

AWWA C111 / ANSI 21.11

Rubber-Gasket Joints for Ductile-Iron Pressure Pipe and Fittings

GMA G-192-1A

Table Continued


562

1.7 MATERIALS & FITTINGS: MISCELLANEOUS (Continued)

AWWA Manual M41 Ductile-Iron Pipe and Fittings

MSS SP-6 Standard Finishes for Contact Faces of Pipe Flanges and Connecting-End Flanges of Valves and Fittings

§192.147

1.8 BOLTS & GASKETS

AGA CPR-83-4-1 Threaded Fastener Torquing (Available on GPTC website under Reports and Position Papers)

ASME B1.1 Unified Inch Screw Threads, Un and Unr Thread Form §192.147

ASME B16.20 Metallic Gaskets for Pipe Flanges: Ring-Joint, Spiral-Wound and Jacketed

§192.147

ASME B16.21 Non-metallic Flat Gaskets for Pipe flanges

ASME B18.2.1 Square and Hex Bolts and Screws, Inch Series §192.147

ASME B18.2.2 Square and Hex Nuts, Inch Series §192.147

ASTM A193 Alloy-Steel and Stainless Steel Bolting for High-Temperature or High Pressure Service and Other Special Purpose Applications

§192.147

ASTM A194 Carbon and Alloy Steel Nuts for Bolts for High-Pressure or High-Temperature Service, or Both

§192.147

ASTM A307 Carbon Steel Bolts and Studs, 60,000 PSI Tensile Strength §192.147

ASTM A320 Alloy-Steel and Stainless Steel Bolting for Low-Temperature Service

§192.147

ASTM A354 Quenched and Tempered Alloy Steel Bolts, Studs, and Other Externally Threaded Fasteners

§192.147

ASTM A449 Hex Cap Screws, Bolts and Studs, Steel, Heat Treated, General Use

§192.147

1.9 CORROSION RELATED

ASME STP-PT-011 Integrity Management of Stress Corrosion Cracking in Gas Pipeline High Consequence Areas

§192.929

CEPA Stress Corrosion Cracking Recommended Practices, 2nd Ed §192.929

GTI-04/0071 External Corrosion Direct Assessment (ECDA) Implementation Protocol

NACE MR0175 Materials for Use in H2S-Containing Environments in Oil and Gas Production

§192.53 §192.475

NACE RP0173 Collection and Identification of Corrosion Products (Revised 1973; Discontinued)

§192.617

Table Continued



1.9 CORROSION RELATED (Continued)

NACE RP0175 Control of Internal Corrosion in Steel Pipelines and Piping Systems (Revised 1975; Discontinued)

§192.475

NACE SP0192 Monitoring Corrosion in Oil and Gas Production with Iron Counts

§192.475 §192.917

NACE SP0274 High-Voltage Electrical Inspection of Pipeline Coatings §192.461

NACE RP0375 Field-Applied Underground Wax Coating Systems for Underground Pipelines: Application, Performance, and Quality Control

§192.461

NACE SP0775 Preparation, Installation, Analysis, and Interpretation of Corrosion Coupons in Oilfield Operations

§192.475

NACE SP0102 In-Line Inspection of Pipelines §192.476 GMA G-192-14

NACE SP0106 Control of Internal Corrosion in Steel Pipelines and Piping Systems

§192.476 §192.917

NACE SP0113 Pipeline Integrity Method Selection §192.925

NACE SP0169 Control of External Corrosion on Underground or Submerged Metallic Piping Systems

§192.453 §192.455 §192.461 §192.463 §192.473 §192.620 App. D

NACE SP0177 Mitigation of Alternating Current and Lightning Effects on Metallic Structures and Corrosion Control Systems

§192.467

NACE SP0200 Steel-Cased Pipeline Practices §192.323 §192.467

NACE SP0204 Stress Corrosion Cracking (SCC) Direct Assessment Methodology

§192.613 §192.917 §192.929

NACE SP0206 Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas (DG-ICDA)

§192.476 §192.927

NACE SP0207 Performing Close-Interval Potential Surveys and DC Surface Potential Gradient Surveys on Buried or Submerged Metallic Pipelines

§192.925

NACE TM0109 Aboveground Survey Techniques for the Evaluation of Underground Pipeline Coating Condition

§192.467 §192.925

NACE TM0194 Field Monitoring of Bacterial Growth in Oilfield Systems §192.475

Table Continued



564

1.9 CORROSION RELATED (Continued)

NACE TM0497 Measurement Techniques Related to Criteria for Cathodic Protection on Underground or Submerged Metallic Piping Systems

§192.467 §192.925

NACE 3D170 Technical Committee Report, Electrical and Electrochemical Methods for Determining Corrosion Rates (Revised 1984; Withdrawn 1994)

§192.475

NACE 3T199 Techniques for Monitoring Corrosion and Related Parameters in Field Applications

§192.476

NACE 35100 Technical Committee Report, In-Line Nondestructive Inspection of Pipelines

GMA G-192-14

NACE 35103 External Stress Corrosion Cracking of Underground Pipelines

§192.613 §192.929

PRCI L52043 / PR-273-0328

SCC Initiation Susceptibility Ranking/Screening §192.929

SSPC Painting Manual Good Painting Practice - Volume 1; and Systems and Specifications - Volume 2

§192.479

1.10 DIMENSIONAL STANDARDS

API Spec 5B Threading, Gauging, and Thread Inspection of Casing, Tubing, and Line Pipe Threads

ASME B1.20.1 Pipe Threads, General Purpose, Inch §192.273

ASME B1.20.3 Dryseal Pipe Threads, Inch

1.11 PLASTIC RELATED

AGA XR0104 Plastic Pipe Manual For Gas Service §192.285 §192.321 §192.751

GMA G-192-15B

API Spec 15HR Guidelines, High Pressure Fiberglass Line Pipe §192.917

ASME I00353 Installation of Plastic Gas Pipeline in Steel Conduits Across Bridges

§192.321

ASTM D696 Test Method for Coefficient of Linear Thermal Expansion of Plastics Between -30 oC and 30 oC With a Vitreous Silica Dilatometer

§192.281

ASTM D2235 Solvent Cement for Acrylonitrile-Butadiene-Styrene (ABS) Plastic Pipe and Fittings

§192.281

ASTM D2560 Solvent Cements for Cellulose Acetate Butyrate (CAB) Plastic Pipe, Tubing and Fittings (Withdrawn 1986)

§192.281

Table Continued


Addendum 7, May 2017 573

2 GOVERNMENTAL DOCUMENTS (Continued)

OPS ADB-10-03 Advisory Bulletin – Girth Weld Quality Issues Due to Improper Transitioning, Misalignment, and Welding Practices of Large Diameter Line Pipe (75 FR 14243, Mar. 24, 2010)

§192.620

OPS ADB-10-08 Advisory Bulletin – Emergency Preparedness Communications (75 FR 67807, Nov. 3, 2010)

§192.615

OPS ADB-11-02 Advisory Bulletin – Dangers of Abnormal Snow and Ice Build-Up on Gas Distribution Systems (76 FR 7238, Feb. 9, 2011)

§192.616

OPS ADB-12-02 Advisory Bulletin – Post-Accident Drug and Alcohol Testing (77 FR 10666, Feb. 23, 2012)

§192.605 §192.615

OPS ADB-12-03 Advisory Bulletin – Notice to Operators of Driscopipe® 8000 High Density Polyethylene Pipe of the Potential for Material Degradation (77 FR 13387, Mar. 6, 2012)

§192.917

OPS ADB-2012-07 Advisory Bulletin – Completion of Mechanical Fitting Failure Report Form, Leak Causes (77 FR 34457, June 11, 2012)

§191.12

OPS ADB-12-08 Advisory Bulletin – Inspection and Protection of Pipeline Facilities after Railway Accidents (77 FR 45417, July 31, 2012)

§192.615

OPS ADB-2012-11 Advisory Bulletin – Reporting of Exceedances of Maximum Allowable Operating Pressure (77 FR 75699, Dec. 21, 2012)

§191.23

OPS ADB-2015-02 Advisory Bulletin – Potential for Damage to Pipeline Facilities Caused by the Passage of Hurricanes (80 FR 36042, June 23, 2015)

§192.615

OPS ADB-2016-01 Advisory Bulletin – Potential for Damage to Pipeline Facilities Caused by Severe Flooding (81 FR 2943, Jan. 19, 2016)

§192.613

OPS ALN-88-01 Alert Notice – Operational failures of pipelines constructed with ERW prior to 1970 (Jan 28, 1988; see document at PHMSA-OPS website)

§192.917

OPS ALN-89-01 Alert Notice – Update to ALN-88-01 (Mar 8, 1989; see document at PHMSA-OPS website)

§192.917

OPS-DOT.RSPA/DMT 10-85-1

Safety Criteria for the Operation of Gaseous Hydrogen Pipelines (Discontinued)

§192.1

OPS TTO No. 5 Technical Task Order – Low Frequency ERW and Lap Welded Longitudinal Seam Evaluation, Michael Baker Jr., Inc., et al

§192.917



2 GOVERNMENTAL DOCUMENTS (Continued)

OPS TTO No. 8 Technical Task Order – Stress Corrosion Cracking Study, Michael Baker, Jr., Inc., January 2005

§192.613 §192.917 §192.929

PHMSA-OPS Gas Integrity Management Protocols §192.925 §192.927

Guidelines for Integrity Assessment of Cased Pipe for Gas Transmission Pipelines in HCAs §192.925

"Interim Guidelines for Confirming Pipe Strength in Pipe Susceptible to Low Yield Strength for Gas Pipelines”

§192.620

Notice – Development of Class Location Change Waiver Criteria (69 FR 38948, June 29, 2004)

§192.611

Training Guide for Operators of Small LP Gas Systems (also referred to as "Guidance Manual")

§192.1 §192.11



GUIDE MATERIAL APPENDIX G-192-9 (See guide material under §§192.143, 192.503, 192.505, 192.507,

192.509, 192.513, 192.619, 192.921, and Guide Material Appendix G-192-9A)

TEST CONDITIONS FOR PIPELINES OTHER THAN SERVICE LINES This table is presented as a compilation for the application of the test requirements in §§192.143, 192.503, 192.505, 192.507, 192.509, 192.513, and 192.619 as they apply to pipelines other than service lines. Additional guidance is provided in the notes.

Other Than Plastic Plastic Under 30 Percent SMYS 30 Percent

SMYS and Over Maximum Operating Pressure

Less than 1 psig

1 psig but less than 100

psig

100 psig and over

All pressures

All pressures See Note (2)

Test Medium

Water Air Natural gas Inert gas


Water Air Natural gas Inert gas See Note (3)


Water Air Natural gas Inert gas See Note (4)

Maximum Test Pressure

See Note (5)

See Note (5)

See Note (5)

See Note (5)

3 x design pressure See Notes (6) and (7)

Minimum Test Pressure

10 psig

90 psig

Maximum operating pressure multiplied by class location factor in §192.619 (a)(2)(ii); See Note (3)

Maximum operating pressure multiplied by class location factor in §192.619 (a)(2)(ii); See Note (8)

50 psig or 1.5 x maximum operating pressure, whichever is greater See Note (6)

Minimum Test Duration

See Note (9)

See Note (9)

1 Hour and see Note (9)

8 Hours and see Notes (9) & (10)

See Note (9)

Notes:

(1) Determining whether a new segment of pipeline should be tested per §192.505 (30% SMYS and over) or per §192.507 (under 30% SMYS and at or above 100 psig) is dictated by the percent of SMYS at MAOP. Some pipelines, generally tested per §192.505, may contain segments or have connections that are tested per §192.507. For examples, see the following. (a) If a new lateral is to be installed on a pipeline that operates over 30% SMYS, and the new

lateral will operate with an MAOP that is less than 30% SMYS and at or above 100 psig, the new lateral is covered by §192.507, even though the header pipe might have been tested per §192.505.

(b) If a segment of transmission line is replaced with different-wall-thickness or stronger pipe that will operate with an MAOP below 30% SMYS, the replacement pipe segment is covered by §192.507, even if the majority of the pipeline has been tested per §192.505. However, in this situation the operator might consider testing in accordance with §192.505 to avoid possible issues with the following.



(i) Section 192.555(b)(1) and (b)(2), if the pipeline segment is uprated in the future to 30% SMYS or more.

(ii) Section 192.611(a)(1), if there is a confirmation or revision of the MAOP in the future due to a change in class location.

(2) Plastic pipe must be designed in accordance with §192.121, and the design pressure for PE and PA pipe must be limited by §192.123.

(3) Whenever test pressure is 20% SMYS or greater and air, natural gas, or inert gas is the test medium, the line must be checked for leaks either by a leak test at a pressure greater than 100 psig but less than 20% SMYS or by walking the line while the pressure is held at 20% SMYS (§192.507(b)).

(4) See temperature limitations for thermoplastic material in §192.513(d). (5) Refer to §192.503(c) for limitations when testing with air, natural gas, or inert gas. There are no

limitations for water test. For all test media, pipeline components must be taken into consideration when determining the maximum test pressure. When water is used as the test medium, it is essential to consider elevation differences to avoid overpressuring pipe at lower elevations in the segment. The pressure at lower elevations is determined by adding 0.43 psig for every foot of elevation differential to the test pressure, measured at a higher point.

(6) See 9.2 of the guide material under §192.321. (7) Apply 2.5 x design pressure for PE or PA pipe using a design factor of 0.40. (8) Refer to §192.505(a) for testing criteria covering pipelines located within 300 feet of buildings and

§192.505(b) for compressor, measuring, and regulator stations. (9) Duration determined by volumetric content of test section, test medium, test pressure, thermal

effects, leak criteria, and instrumentation in order to ensure discovery of all potentially hazardous leaks. See 2 of the guide material under §192.509 and 4 of the guide material under §192.513.

(10) Refer to §192.505(e) for fabricated units and short sections of pipe.



GUIDE MATERIAL APPENDIX G-192-10 (See guide material under §192.511, plus

§§192.143, 192.503, 192.507, 192.509, 192.513, and 192.619)

TEST CONDITIONS FOR SERVICE LINES 1 SUMMARY OF PRESSURE TEST REQUIREMENTS

This table is presented as a compilation for the application of the test requirements of §192.511 and §§192.503, 192.507, 192.513, and 192.619 as applied to service lines. Additional guidance is provided in the notes.

Other Than Plastic Plastic Maximum Operating Pressure

Less than 1 psig

1 psig to

40 psig

Over 40 psig but less than

100 psig

100 psig and over

All Pressures See Note (1)

Test Medium

Water Air Natural Gas Inert Gas




Water Air Natural Gas Inert Gas See Note (2)

Maximum Test Pressure

See Note (3) See Note (3) See Note (3) See Note (3) 3 x design pressure See Notes (4) & (5)

Minimum Test Pressure

See Note (6) 50 psig 90 psig See Note (7)

1.5 x maximum operating pressure; See Notes (7) & (8)

50 psig or 1.5 x maximum operating pressure, whichever is greater; See Note (4)

Minimum Test Duration

See Note (9) See Note (9) See Notes (7) & (9) See Notes (7) & (9) See Notes (9) & (10)

Notes:

(1) Plastic pipe must be designed in accordance with §192.121, and the design pressure for PE and PA pipe must be limited by §192.123.

(2) See temperature limitations for thermoplastic material in §192.513(d). (3) Refer to §192.503(c) for limitation when testing with air, natural gas, or inert gas. Limited also to the

design pressure of service line component (§192.619). (4) See 9.2 of the guide material under §192.321. (5) Apply 2.5 x design pressures for PE or PA pipe using a design factor of 0.40 (6) Recommended practice is a minimum of 10 psig. (7) Whenever test pressure stresses pipe to 20% SMYS or more, see §§192.507 and 192.511(c) for

additional requirements. Note that a service line stressed to 20% or more of SMYS is required by §192.511(c) to be tested per §192.507, even if the transmission line to which it is attached has been tested per §192.505.

(8) See §192.619 for Class 1 and Class 2 locations. (9) Duration determined by volumetric content of test section, test medium, test pressure, thermal

effects, leak criteria, and instrumentation in order to ensure discovery of all potentially hazardous leaks. See 2 of the guide material under §192.509.

(10) See 4 of the guide material under §192.513.


670

2 TESTING SERVICE LINES EQUIPPED WITH EXCESS FLOW VALVES 2.1 Pressurizing the service line.

When pressurizing a service line equipped with an excess flow valve (EFV) during either testing or service activation, the operator should introduce either the test medium or gas at a flow rate that does not activate the EFV. EFV activation may be indicated by a sudden increase in pressure as noted on a pressure gauge at the injection point or the lack of a rapid buildup of pressure at the service line riser. If activated, bypass-type EFVs (EFVB) should reset automatically; non-bypass types (EFVNB) should be reset following their manufacturers’ instructions.

2.2 Testing the EFV. Prior to service line testing or service activation, the operator may opt to test the EFV for shutoff by first introducing the test medium at a high flow rate. If the EFV does not operate as designed, it should be replaced.

guide for gas transmission, distribution and gathering ... · allan clarke, consultant . rodney...

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