1997 november 6 - editorial section - american gas association · pdf fileamerican gas...

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

Paul Cabot, C.G.E. GPTC Secretary (202) 824-7312

[email protected]

June 17, 2015 Dear Guide Purchaser, Enclosed is Addendum 1 to ANSI GPTC Z380.1, Guide for Gas Transmission and Distribution 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

http://www.aga.org/gptc

https://www.aga.org/aga-publications

B L A N K

1

GPTC GUIDE FOR GAS TRANSMISSION AND DISTRIBUTION PIPING SYSTEMS

2015 EDITION

ADDENDUM 1, May 2015 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. The Federal Regulations were updated by 2 amendments that affected 23 sections of the Regulations and 30 sections of the Guide. Four GPTC transactions affected 5 sections of the Guide. Editorial updates include application of the Editorial Guidelines, updating reference titles, 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 21 sections of the Guide (plus other sections impacted by page adjustments, etc.). The following table shows the affected sections and pages.

2

Amdt. or Docket Number: FS Amendment TR Number: New or Updated GM GMUR: GM Under Review EU: Editorial Update ER: Editorial Refinement

Guide Section Reason For Change Pages to Remove Pages to Insert

Title page EU i/ii, iii/iv i/ii, iii/iv

Table of Contents Amdt 191-23

GPTC Membership listed by Committee

EU xvii/xviii thru xxxi/xxxii xvii/xviii thru xxxi/xxxii

GPTC Membership listed by member participation

EU

Historical Reconstruction of Part 191

Amdt 191-23 xxxvii/xxxviii xxxvii/xxxviii

Historical Record of Amendments to Part 191

Amdt 191-23 xli/xlii thru li/lii xli/xlii thru li/lii

Historical Reconstruction of Part 192

Amdt 192-120

Historical Record of Amendments to Part 192

Amdt 192-120 lxxiii/lxxiv lxxiii/lxxiv

Part 191 Authority EU, Amdt 191-23 1/2 thru 5/6 1/2 thru 5/6

191.7 Amdt 191-23

191.25 Amdt 191-23 13/14, 15/16

13/14, 15/16

191.27 Amdt 191-23

191.29 EU, Amdt 191-23

Part 192 Authority EU, Amdt 192-120 17/18, 19/20, 27/28 17/18, 19/20, 27/28

Subpart A 192.3 EU,Amdt 192-120

192.9 EU, Amdt 192-120 41/42, 43/44 41/42, 43/44

Subpart B 192.65 EU, Amdt 192-120 53/54 53/54

Subpart C 192.112 Amdt 192-120 61/62 thru 67/68 61/62 thru 67/68

192.121 TR 14-12

Subpart D 192.153 EU, Amdt 192-120 87/88 87/88

192.165 EU, Amdt 192-120 99/100 99/100

Subpart E 192.225 Amdt 192-120 119/120 thru 125/126 119/120 thru 125/126

192.227 EU, Amdt 192-120

192.229 EU, Amdt 192-120

192.241 EU, Amdt 192-120

192.243 Amdt 192-120

3

Guide Section Reason For Change Pages to Remove Pages to Insert

Subpart F 192.285 EU, Amdt 192-120 137/138 thru 141/142 137/138 thru 141/142

Subpart G 192.305 EU, Amdt 192-120

192.321 TR 13-24 149/150, 151/152 149/150, 151/152

Subpart J 192.503 EU, Amdt 192-120 217/218, 219/220 217/218, 219/220

192.505 EU, Amdt 192-120

Subpart L 192.605 TR 13-20 241/242 241/242

192.613 TR 13-27 259/260 259/260

192.620 Amdt 192-120 285/286, 287/288, 293/294

285/286, 287/288, 293/294

Subpart N 192.805 Amdt 192-120 355/356 355/356

Subpart O 192.925 Amdt 192-120 433/434 433/434

192.949 Amdt 192-120 505/506 505/506

Subpart P 192.1013 EU 513/514, 515/516 513/514, 515/516

GMA G-191-3 EU Form with Expiration Date: 1/31/14

Form with Expiration Date: 10/31/16

GMA G-192-1 TR 13-24 567/568 567/568

GMA G-192-8 EU 625/626, 627/628, 651/652

625/626, 627/628, 651/652

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i

Guide for Gas Transmission, Distribution, and Gathering

Piping Systems

2015 Edition Addendum 1, May 2015

Author: Gas Piping Technology Committee (GPTC) Z380

Accredited by ANSI

Secretariat: American Gas Association

Approved by American National Standards Institute (ANSI)

June 10, 2015

ANSI GPTC Z380.1-2015 Catalog Number: Z3801151

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

ii

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.


iii

CONTENTS Page PREFACE ......................................................................................................................................... xiii HISTORY .......................................................................................................................................... xiii FOREWORD .................................................................................................................................... xiv GAS PIPING TECHNOLOGY COMMITTEE MEMBERSHIP ....................................... xvii Listed by Committee ...................................................................................................................... xvii Listed by Member Participation .................................................................................................... xxiii LETTER TO GAS PIPING TECHNOLOGY COMMITTEE FROM THE U.S. DEPARTMENT OF TRANSPORTATION ................................................xxxiii AMERICAN GAS ASSOCIATION (AGA) NOTICE AND DISCLAIMER ................ xxxiv EDITORIAL CONVENTIONS OF THE GUIDE ................................................................ xxxv EDITORIAL NOTES FOR THE HISTORICAL RECONSTRUCTION OF PARTS 191 AND 192 ........................................................................................................ xxxvii HISTORICAL RECONSTRUCTION OF PART 191 ..................................................... xxxvii HISTORICAL RECORD OF AMENDMENTS TO PART 191 .................................... xxxix HISTORICAL RECONSTRUCTION OF PART 192 ......................................................... xliii HISTORICAL RECORD OF AMENDMENTS TO PART 192 ......................................... liii PART 191 - ANNUAL REPORTS, INCIDENT REPORTS, AND SAFETY-RELATED CONDITION REPORTS ................................................................. 1 191.1 Scope ........................................................................................................................... 1 191.3 Definitions .................................................................................................................... 2 191.5 Immediate notice of certain incidents .......................................................................... 3 191.7 Report submission requirements ................................................................................ 4 191.9 Distribution system: Incident report ............................................................................. 5 191.11 Distribution system: Annual report ............................................................................... 6 191.12 Distribution systems: Mechanical fitting failure reports ............................................... 6 191.13 Distribution systems reporting transmission pipelines; transmission or gathering systems reporting distribution pipelines ............................................................. 9 191.15 Transmission systems; gathering systems; and liquefied natural gas facilities: Incident report ..................................................................................................... 9 191.17 Transmission systems; gathering systems; and liquefied natural gas facilities: Annual report .................................................................................................... 10


Addendum 1, May 2015 iv

191.19 (Removed) ................................................................................................................. 10 191.21 OMB control number assigned to information collection .......................................... 10 191.22 National Registry of Pipeline and LNG Operators..................................................... 11 191.23 Reporting safety-related conditions ........................................................................... 12 191.25 Filing safety-related condition reports ........................................................................ 13 191.27 (Removed) ................................................................................................................. 14 191.29 National Pipeline Mapping System ............................................................................ 15 PART 192 - MINIMUM FEDERAL SAFETY STANDARDS ........................................... 17 SUBPART A - GENERAL .................................................................................................................... 17 192.1 What is the scope of this part? .................................................................................. 17 192.3 Definitions .................................................................................................................. 18 192.5 Class locations ........................................................................................................... 29 192.7 What documents are incorporated by reference partly or wholly in this part? ....................................................................................................... 30 192.8 How are onshore gathering lines and regulated onshore gathering lines determined? ............................................................................................. 35 192.9 What requirements apply to gathering lines? ............................................................ 41 192.10 Outer continental shelf pipelines ........................................................................... 42 192.11 Petroleum gas systems ............................................................................................. 42 192.12 (Removed) ................................................................................................................. 45 192.13 What general requirements apply to pipelines regulated under this part? ............... 45 192.14 Conversion to service subject to this part.................................................................. 46 192.15 Rules of regulatory construction ................................................................................ 47 192.16 Customer notification ................................................................................................. 48 192.17 (Removed) ................................................................................................................. 48 SUBPART B - MATERIALS ................................................................................................................ 49 192.51 Scope ......................................................................................................................... 49 192.53 General ...................................................................................................................... 49 192.55 Steel pipe ................................................................................................................... 50 192.57 (Removed and reserved) ........................................................................................... 51 192.59 Plastic pipe ................................................................................................................. 51 192.61 (Removed and reserved) ........................................................................................... 52 192.63 Marking of materials .................................................................................................. 52 192.65 Transportation of pipe ................................................................................................ 53 SUBPART C - PIPE DESIGN .............................................................................................................. 55 192.101 Scope ......................................................................................................................... 55 192.103 General ...................................................................................................................... 55 192.105 Design formula for steel pipe ..................................................................................... 56 192.107 Yield strength (S) for steel pipe ................................................................................. 57 192.109 Nominal wall thickness (t) for steel pipe .................................................................... 58 192.111 Design factor (F) for steel pipe .................................................................................. 59 192.112 Additional design requirements for steel pipe using alternative maximum allowable operating pressure ........................................................................... 61 192.113 Longitudinal joint factor (E) for steel pipe .................................................................. 66 192.115 Temperature derating factor (T) for steel pipe .......................................................... 67 192.117 (Removed and reserved) ........................................................................................... 67 192.119 (Removed and reserved) ........................................................................................... 67 192.121 Design of plastic pipe ................................................................................................. 67 192.123 Design limitations for plastic pipe .............................................................................. 71 192.125 Design of copper pipe ................................................................................................ 75


Addendum 1, May 2015 xvii

GAS PIPING TECHNOLOGY COMMITTEE MEMBERSHIP1

Listed by Committee

Officers Leticia Quezada, Chair

Nicor Gas, An AGL Resources Company Lee Reynolds, 1st Vice Chair

NiSource Philip Sher, 2nd Vice Chair

Philip Sher Pipeline Consultant Paul Cabot, 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, Nicor Gas, An AGL Resources Co., Chair Lee Reynolds, NiSource, 1st Vice Chair Philip Sher, Philip Sher Pipeline Consultant, 2nd Vice Chair Paul Cabot, American Gas Association, Secretary 2 Richard Abraham, Marathon Pipe Line LLC Stephen Bateman, Long Beach Gas & Oil Glen Armstrong, EN Engineering Frank Bennett, UGI Utilities, Inc. David Bull, ViaData LP DeWitt Burdeaux, FlexSteel Pipeline Technologies John Butler, EQT Corp. Robert Cadorin, TransCanada Corporation Willard Carey, Energy Experts International John Chin, TransCanada Corporation Allan Clarke, Spectra Energy Corp Amerigo Del Buono, Weldbend Corporation F. Roy Fleet, F. Roy Fleet, Inc. Mary Friend, Public Service Commission of West Virginia Ralph Graeser, Pennsylvania Public Utility Commission - Representing NAPSR Steven Groeber, Gas Operations Consultant

John Harper, Oklahoma Corporation Commission - Representing NAPSR Richard Huriaux, Richard Huriaux, Consulting Engineer Randy Knapp, Plastics Pipe Institute John Kottwitz, Missouri Public Service Commission Jon Loker, Pipeline Safety Consultant George Lomax, Heath Consultants Incorporated John Lueders, DTE Gas Company James McKenzie, Atmos Energy Corporation Theron McLaren, U.S. Department of Transportation - PHMSA Robert Naper, Energy Experts International Eugene Palermo, Palermo Plastics Pipe Consulting Kenneth Peters, Kinder Morgan Inc. Robert Schmidt, Canadoil Forge Patrick Seamands, Laclede Gas Company Walter Siedlecki, AEGIS Insurance Services, Inc. Richard Slagle, AGL Resources Jerome Themig, Ameren Illinois 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, Chair Paul Cabot, American Gas Association, Secretary 2 David Bull, ViaData LP Allan Clarke, Spectra Energy Corp Jon Loker, Pipeline Safety Consultant John Lueders, DTE Gas Company Joseph Opert, BGE, An Exelon Company Eugene Palermo, Palermo Plastics Pipe Consulting

Kenneth Peters, Kinder Morgan Inc. Leticia Quezada, Nicor Gas, An AGL Resources Company Patrick Seamands, Laclede Gas Company Philip Sher, Philip Sher Pipeline Consultant Richard Slagle, AGL Resources Jerome Themig, Ameren Illinois Ram Veerapaneni, DTE Gas Company

________________________ 1 Membership as of 5/21/15 2 Non voting

Editorial Section


Addendum 1, May 2015 xviii

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

Jon Loker, Pipeline Safety Consultant, Chair Lane Miller, Pacific Gas and Electric Company, Secretary Richard Abraham, Marathon Pipe Line LLC Stephen Bateman, Long Beach Gas & Oil John Butler, EQT Corp. F. Roy Fleet, F. Roy Fleet, Inc. Steven Gauthier, Energy Experts International

Steven Groeber, Gas Operations Consultant John Kottwitz, Missouri Public Service Commission Paul Oleksa, Oleksa and Associates, Inc. Patrick Seamands, Laclede Gas Company Ram Veerapaneni, DTE Gas Company David Weber, Consultant

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.

Patrick Seamands, Laclede Gas Company, Chair David Bull, ViaData LP Allan Clarke, Spectra Energy Corp Gregory Goble, R.W. Lyall & Company, Inc. Steve Hurbanek, System One Services

John Lueders, DTE Gas Company Steven Troch, BGE, An Exelon Company Ram Veerapaneni, DTE Gas Company David Weber, Consultant

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, Pacific Gas and Electric Company, Secretary Richard Abraham, Marathon Pipe Line LLC Glen Armstrong, EN Engineering Stephen Bateman, Long Beach Gas & Oil Andrew Benedict, Opvantek Inc. Lawrence Berg, Pacific Gas and Electric Company Wayne Bryce, Jana Laboratories Inc. David Bull, ViaData LP Brian Camfield, PECO Energy, An Excelon Company Willard Carey, Energy Experts International Leo Cody, Liberty Utilities Mark Conners, UGI Utilities, Inc. Ray Deatherage, Integrys Energy Group Denise Dolezal, Metropolitan Utilities District Rodney Dyck, U.S. Department of Transportation - PHMSA Kalu Kelly Emeaba, National Transportation Safety Board John Erickson, American Public Gas Association Michael Faulkenberry, Avista Utilities Chris Foley, RCP Inc. Andy Fortier, NW Natural John Goetz, Meade Ralph Graeser, Pennsylvania Public Utility Commission - Representing NAPSR Steven Groeber, Gas Operations Consultant John Groot, Southern California Gas Company

John Harper, Oklahoma Corporation Commission - Representing NAPSR Thomas Hart, Eversource Energy Steve Hurbanek, System One Services Antoinette (Toni) Imad, Puget Sound Energy John Kottwitz, Missouri Public Service Commission Brent Koym, CenterPoint Energy Lawrence Krummert, NiSource Gas Distribution Brian Lopez, Xcel Energy Inc. Thomas Marlow, Vectren Corporation Jeffrey McClenahan, Public Service Electric and Gas Co. James McKenzie, Atmos Energy Corporation Theron McLaren, U.S. Department of Transportation - PHMSA Jeffrey Meyers, Knoxville Utilities Board Robert Naper, Energy Experts International Paul Oleksa, Oleksa and Associates, Inc. Joseph Opert, BGE, An Exelon Company Christopher Pioli, Jacobs Consultancy Kevin Powers, Public Service Electric and Gas Company Heather Risley, Xcel Energy Inc. Jim Rutherford, Heath Consultants Incorporated Patrick Seamands, Laclede Gas Company Parashar Sheth, National Grid D. Kevin Shuttlesworth, NorthWestern Energy Walter Siedlecki, AEGIS Insurance Services, Inc.

(Continued)


Addendum 1, May 2015 xix

Distribution Division (Continued) Richard Slagle, AGL Resources David Spangler, Washington Gas Light Company Jerome Themig, Ameren Illinois Steven Troch, BGE, An Exelon Company

Erich Trombley, Southwest Gas Corporation Alfredo Ulanday, EN Engineering David Weber, Consultant William Wells, New Jersey Natural Gas Company

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 Brandon Babe, Arkema Inc. DeWitt Burdeaux, FlexSteel Pipeline Technologies Heath Casteel, Performance Pipe Amerigo Del Buono, Weldbend Corporation Steven Gauthier, Energy Experts International Gregory Goble, R.W. Lyall & Company, Inc.

Richard Huriaux, Consulting Engineer James Johnston, McElroy Manufacturing, Inc. Randy Knapp, Plastics Pipe Institute George Lomax, Heath Consultants Incorporated Daniel O'Leary, GasBreaker, Inc./UMAC, Inc. Barry Peterson, Performance Pipe Robert Schmidt, Canadoil Forge

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 Banu Acimis, State of CA, Public Utilities Commission - Representing NAPSR Aaron Bass, PPL Interstate Energy Company Stephen Beatty, LG&E-KU, PPL Companies Robert Becken, Energy Experts International Frank Bennett, UGI Utilities, Inc. John Butler, EQT Corp. John Chin, TransCanada Corporation Allan Clarke, Spectra Energy Corp F. Roy Fleet, F. Roy Fleet, Inc. Mary Friend, Public Service Commission of West Virginia

Narinder Grewal, AG Square, Inc. George Hamaty, Columbia Gas Transmission Corp. Donald Kincaid, Enable Midstream Partners Douglas Lee, KLJ Progress Solutions Ray Lewis, ROSEN USA Jon Loker, Pipeline Safety Consultant Erin McKay, Hilcorp Alaska, LLC Timothy Strommen, WE Energies William Taylor, CenterPoint Energy David Terzian, National Grid Ram Veerapaneni, DTE Gas Company Gary White, PI Confluence, Inc. Brian Wolf, Hatch Mott MacDonald

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 Richard Abraham, Marathon Pipe Line LLC Glen Armstrong, EN Engineering Stephen Bateman, Long Beach Gas & Oil Frank Bennett, UGI Utilities, Inc. Lawrence Berg, Pacific Gas and Electric Company Willard Carey, Energy Experts International John Chin, TransCanada Corporation Allan Clarke, Spectra Energy Corp Leo Cody, Liberty Utilities Ray Deatherage, Integrys Energy Group Kalu Kelly Emeaba, National Transportation Safety Board John Erickson, American Public Gas Association F. Roy Fleet, F. Roy Fleet, Inc. Mary Friend, Public Service Commission of West Virginia

Ralph Graeser, Pennsylvania Public Utility Commission - Representing NAPSR Steven Groeber, Gas Operations Consultant George Hamaty, Columbia Gas Transmission Corp. Thomas Hart, Eversource Energy Steve Hurbanek, System One Services John Kottwitz, Missouri Public Service Commission Lawrence Krummert, NiSource Gas Distribution George Lomax, Heath Consultants Incorporated Thomas Marlow, Vectren Corporation Erin McKay, Hilcorp Alaska, LLC Robert Naper, Energy Experts International Christopher Pioli, Jacobs Consultancy Kevin Powers, Public Service Electric and Gas Company Heather Risley, Xcel Energy Inc.

(Continued)


Addendum 1, May 2015 xx

Damage Prevention / Emergency Response Task Group (Continued) Patrick Seamands, Laclede Gas Company Kevin Shuttlesworth, NorthWestern Energy Walter Siedlecki, AEGIS Insurance Services, Inc. Richard Slagle, AGL Resources David Spangler, Washington Gas Light Company Jerome Themig, Ameren Illinois

Alfredo Ulanday, EN Engineering Ram Veerapaneni, DTE Gas Company Benjamin Wasson, Alyeska Pipeline Service Company William Wells, New Jersey Natural Gas Company Brian Wolf, Hatch Mott MacDonald

Design Task Group Responsible for developing Guide Material, ANSI Technical Reports, and other technical material as directed by the Main Body.

Allan Clarke, Spectra Energy Corp, Chair James McKenzie, Atmos Energy Corporation Secretary Stephen Beatty, LG&E-KU, PPL Companies Robert Becken, Energy Experts International Wayne Bryce, Jana Laboratories Inc. DeWitt Burdeaux, FlexSteel Pipeline Technologies John Butler, EQT Corp. Heath Casteel, Performance Pipe John Chin, TransCanada Corporation Mark Connors, UGI Utilities, Inc. Denise Dolezal, Metropolitan Utilities District Robert Fassett, Kleinfelder, Inc. Michael Faulkenberry, Avista Utilities Chris Foley, RCP Inc. Andy Fortier, NW Natural Gregory Goble, R.W. Lyall & Company, Inc. Narinder Grewal, AG Square, Inc. John Groot, Southern California Gas Company John Harper, Oklahoma Corporation Commission - Representing NAPSR

Richard Huriaux, Consulting Engineer Antoinette (Toni) Imad, Puget Sound Energy Donald Kincaid, Enable Midstream Partners Randy Knapp, Plastics Pipe Institute Brent Koym, CenterPoint Energy Douglas Lee, KLJ Progress Solutions Brian Lopez, Xcel Energy Inc. John Lueders, DTE Gas Company Theron McLaren, U.S. Department of Transportation - PHMSA Jeffrey Meyers, Knoxville Utilities Board 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 William Taylor, CenterPoint Energy 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 Banu Acimis, State of CA, Public Utilities Commission - Representing NAPSR Glen Armstrong, EN Engineering Aaron Bass, Interstate Energy Company Frank Bennett, UGI Utilities, Inc. Wayne Bryce, Jana Laboratories Inc. John Chin, TransCanada Corporation Allan Clarke, Spectra Energy Corp Rodney Dyck, U.S. Department of Transportation - PHMSA Kalu Kelly Emeaba, National Transportation Safety Board Robert Fassett, Kleinfelder, Inc. Ralph Graeser, Pennsylvania Public Utility Commission Representing NAPSR Narinder Grewal, AG Square, Inc.

Donald Kincaid, Enable Midstream Partners Brent Koym, CenterPoint Energy Ray Lewis, ROSEN USA Thomas Marlow, Vectren Corporation Theron McLaren, U.S. Department of Transportation - PHMSA Lane Miller, Pacific Gas and Electric Company Daniel O'Leary, GasBreaker, Inc./UMAC, Inc. Paul Oleksa, Oleksa and Associates, Inc. Christopher Pioli, Jacobs Consultancy Timothy Strommen, WE Energies William Taylor, CenterPoint Energy Steven Troch, BGE, An Exelon Company Erich Trombley, Southwest Gas Corporation Alfredo Ulanday, EN Engineering Gary White, PI Confluence, Inc. Brian Wolf, Hatch Mott MacDonald


Addendum 1, May 2015 xxi

Operations & Maintenance / Operator Qualification Task Group Jerome Themig, Ameren Illinois, Chair Douglas Lee, KLJ Progress Solutions, Secretary Stephen Bateman, Long Beach Gas & Oil Stephen Beatty, LG&E-KU, PPL Companies Robert Becken, Energy Experts International Andrew Benedict, Opvantek Inc. Lawrence Berg, Pacific Gas and Electric Company David Bull, ViaData LP John Butler, EQT Corp. 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. Ray Deatherage, Integrys Energy Group Denise Dolezal, Metropolitan Utilities District John Erickson, American Public Gas Association Michael Faulkenberry, Avista Utilities Chris Foley, RCP Inc. Mary Friend, Public Service Commission of West Virginia John Goetz, Meade Steven Groeber, Gas Operations Consultant

John Groot, Southern California Gas Company Thomas Hart, Eversource Energy Antoinette (Toni) Imad, Puget Sound Energy James Johnston, McElroy Manufacturing, Inc. John Kottwitz, Missouri Public Service Commission Lawrence Krummert, NiSource Gas Distribution George Lomax, Heath Consultants Incorporated John Lueders, DTE Gas Company Jeffrey McClenahan, Public Service Electric and Gas Co. Erin McKay, Hilcorp Alaska, LLC Robert Naper, Energy Experts International Joseph Opert, BGE, An Exelon Company Kenneth Peters, Kinder Morgan Inc. Kevin Powers, Public Service Electric and Gas Company Heather Risley, Xcel Energy Inc. Jim Rutherford, Heath Consultants Incorporated D. Kevin Shuttlesworth, NorthWestern Energy Walter Siedlecki, AEGIS Insurance Services, Inc. David Spangler, Washington Gas Light Company Alfredo Ulanday, EN Engineering Benjamin Wasson, Alyeska Pipeline Service Company William Wells, New Jersey Natural Gas Company

Plastic Task Group Responsible for developing Guide Material, ANSI Technical Reports, and other technical material as directed by the Main Body.

Richard Slagle, AGL Resources, Chair Frank Volgstadt, Volgstadt & Associates, Secretary Glen Armstrong, EN Engineering Brandon Babe, Arkema Inc. Wayne Bryce, Jana Laboratories Inc. DeWitt Burdeaux, FlexSteel Pipeline Technologies Heath Casteel, Performance Pipe Gregory Goble, R.W. Lyall & Company, Inc. Richard Huriaux, Consulting Engineer James Johnston, McElroy Manufacturing, Inc.

Randy Knapp, Plastics Pipe Institute Brian Lopez, Xcel Energy Inc. Jeffrey Meyers, Knoxville Utilities Board Lane Miller, Pacific Gas and Electric Company Eugene Palermo, Palermo Plastics Pipe Consulting Barry Peterson, Performance Pipe Patrick Seamands, Laclede Gas Company Parashar Sheth, National Grid David Weber, Consultant

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. Petitioning the United States Department of Transportation (DOT) for changes in Federal Natural

Gas Pipeline Safety Regulations based on the technical expertise of the Committee.


xxii

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 1, May 2015 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

D

istribution

M

anufacturers

Transm

ission

D

esign

D

P/ER

IM

P/Corrosion

O

&M

/OQ

Plastic Pipe

Editorial

Executive

Liaison

R

egulations

Abraham, Richard A. Marathon Pipe Line LLC, Findlay, OH X X X X

Acimis, Banu State of CA, PUC/NAPSR, Sacramento, CA X X

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

Babe, Brandon Arkema, King of Prussia, PA X X

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

Bateman, Stephen C. Long Beach Gas & Oil, 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

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

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


Addendum 1, May 2015 xxiv

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

Berg, Lawrence M. Pacific Gas & Electric, San Ramon, CA X X X

Bryce, Wayne Jana Laboratories, Aurora, ON X X X X

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

Burdeaux, DeWitt FlexSteel Pipeline Technologies, Houston, TX X X X X

Butler, John EQT Corp., Charleston, WV X X X X X

Cabot, Paul W. American Gas Association, Washington, DC Sec Sec

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

Camfield, Brian PECO Energy, An Exelon Company, Plymouth Meeting, PA

X X

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

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


xxv


M

ain Body

D

istribution

M

anufacturers

Transm

ission

D

esign

D

P/ER

IM

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Editorial

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egulations

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

Clarke, Allan M. Spectra Energy Corp., Houston, TX X X Chair X X X

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

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

Deatherage, Ray Integrys Energy Group, Chicago, IL 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, Rod PHMSA, Washington, DC X X

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

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

Fassett, Robert P. Kleinfelder, Inc., Santa Rosa, CA X X X


Addendum 1, May 2015 xxvi


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Faulkenberry, Michael J. Avista Corp., Spokane, WA X X X

Fleet, F. Roy F. Roy Fleet, Inc., Westmont, IL X X X X

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

Fortier, Andy M. NW Natural, Portland, OR X X

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

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

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

Goetz, John Meade, McCook, IL X X

Graeser, Ralph A. PA Public Utility Comm./NAPSR, Clairton, PA X X Sec X

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

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


Addendum 1, May 2015 xxvii


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egulations

Hamaty, George Columbia Gas Transmission Corp., Charleston, WV X X

Harper, John OK Corp. Comm./NAPSR, Oklahoma City, OK X X X

Hart, Thomas L. Northeast Utilities, Westwood, MA X X X

Hurbanek, Stephen F. System One Services, New Bern, NC X X X

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

Imad, Antoninette Puget Sound Energy, Bellevue, WA X X X

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

Kincaid, Donald L. Enable Midstream Partners, Shreveport, LA X X X

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


Addendum 1, May 2015 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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Kottwitz, John D. MO Public Service Comm., Jefferson City, MO X X X X X

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

Krummert, Lawrence M. NiSource Gas Distribution, Cannonsburg, PA X X X

Lee, Douglas M. KLJ Progress Solutions, Bismarck, ND X X Sec

Lewis, Raymond D. Rosen USA, Houston, TX X X

Loker, Jon O. Pipeline Safety Consultant, Saint Albans, WV X X Chair X

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

Lopez, Brian Xcel Energy, Denver, CO X X X

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

Marlow, Thomas Vectren Utility Holdings, Evansville, IN X X X


Addendum 1, May 2015 xxix


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egulations

McClenahan, Jeffrey D. Public Service Electric & Gas, Newark, NJ X X

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

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

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

Meyers, Jeffrey Knoxville Utilities Board, Knoxville, TN X X X

Miller, D. Lane PG&E Company, San Ramon, CA Sec X X Sec

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

O’Leary, Daniel GasBreaker, Inc./UMAC, Inc., Malvern, PA X X

Oleksa, Paul E. Oleksa & Assoc., Akron, OH X X X X

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


xxx


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

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

Peterson, Barry A. Performance Pipe, Concord, CA X X

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

Powers, Kevin E. Public Service Electric & Gas, Newark, NJ X X X

Quezada, Leticia Nicor Gas, An AGL Resources Co., Naperville, IL Chair X

Reynolds, Donald Lee NiSource Gas Distribution, Columbus, OH

1st V Chair Chair

Risley, Heather M. Xcel Energy Inc., St. Paul, MN X X X

Rutherford, James Heath Consultants, Houston, TX X X

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


Addendum 1, May 2015 xxxi


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Seamands, Patrick A. Laclede Gas Co., St. Louis, MO X X X X X X Chair

Sher, Philip Philip Sher Pipeline Consultant, Cheshire, CT

2nd V Chair X

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

Shuttlesworth, D. Kevin NorthWestern Energy, Butte, MT X X X

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

Slagle, Richard L. AGL Resources, Atlanta, GA X X X Chair X

Spangler, David Washington Gas Light Co., Springfield, VA X X X

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

Taylor, William E. CenterPoint Energy, Shreveport, LA X X X

Terzian, David National Grid, Waltham, MA X X

Themig, Jerome S. Ameren Illinois Utilities, Springfield, IL X X X Chair X

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


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

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

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

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

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

Wasson, Ben Alyeska Pipeline Service Co. Anchorage, AK X X X

Weber, David E. Consulting Engineer, Barnstable, MA X X X X

Wells, William M. New Jersey Natural Gas Co., Wall, NJ X X X

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

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


Addendum 1, May 2015 xxxvii

EDITORIAL NOTES FOR THE HISTORICAL RECONSTRUCTION OF PARTS 191 AND 192

Part 191 became effective on February 9, 1970. Part 192 became effective on November 12, 1970. Subsequent amendments have been issued with some adding new sections and some amending pre-existing sections. The date following the text listing (i.e., Section heading) of this Guide is the effective date of the latest amendment (if any). To aid the user in reconstructing the history of a particular section, the user is advised that the complete text of Parts 191 and 192 as originally issued, plus all amendments through Amdts. 191-15 and 192-93, are contained in AGA X69804, "Historical Collection of Natural Gas Pipeline Safety Regulations." Otherwise, refer to the Federal Register website for amendments. Additionally, to aid the user, the following tabulations of amendments are provided.

HISTORICAL RECONSTRUCTION OF PART 191 (Complete through Amdt. 191-23)

Part 191 Section

Effective Date of Original Version if other than 2/09/70

Amendments (if any)

191.1 191-5, 191-6, 191-11, 191-12, 191-15, RIN 2137-AD77, 191-21

191.3 191-5, 191-10, 191-12, RIN 2137-AD43, RIN 2137-AD77, 191-21

191.5 191-1, 191-4, 191-5, 191-8, 191-21 191.7 191-3, 191-4, 191-5, 191-6, 191-16,

RIN 2137-AD77, RIN 2137-AE29, RIN 2137-AE29 (#2), 191-21, 191-23

191.9 191-3, 191-5, 191-21 191.11 191-2, 191-5, 191-21 191.12 04/04/11 191-22 191.13 191-5 191.15 191-5, 191-21 191.17 191-5, 191-21 [191.19] 191-3,191-10, 191-21 (removed) 191.21 06/04/84 191-5, 191-13, 191-21 191.22 01/01/11 191-21 191.23 09/29/88 191-6, 191-14 191.25 09/29/88 191-6, 191-7, 191-8, 191-10, 191-23 [191.27] 01/06/92 191-9, 191-14, RIN 2137-AD77,

RIN 2137-AE29, RIN 2137-AE29 (#2), 191-23 (Removed)

191.29 10/01/15 191-23


xxxviii

Reserved


xli

HISTORICAL RECORD OF AMENDMENTS TO PART 191 (Continued)

Amdt 191-

Subject Vol FR Pg# Published Date

Docket or RIN No.

Effective Date

Affected Sections 191.

16

(Shown as 15)

Producer - Operated Outer Continental Shelf Natural Gas and Hazardous Liquid Pipelines that Cross Directly Into State Waters

68 FR 46109 08/05/03 RSPA 99-6132

09/04/03 1

17

(Shown as 16)

Periodic Updates 69 FR 32886 06/14/04 RSPA 99-6106

07/14/04 7

[18] Agency Reorganization 70 FR 11135 03/08/05 RIN 2137-AD77

03/08/05 1, 3, 7, 27

[19] Administrative Procedures, Address Updates, and Technical Amendments*

73 FR 16562 03/28/08 RIN 2137-AE29

04/28/08 7, 27

[20] Administrative Procedures, Address Updates, and Technical Amendments [Adopts interim final rule with modifications.]

74 FR 2889 01/16/09 RIN 2137-AE29

[Ref. as (#2)]

02/17/09 7, 27

21 Updates to Pipeline and Liquefied Natural Gas Reporting Requirements

75 FR 72878 11/26/10 RIN 2137-AE33

01/01/11 1, 3, 5, 7, 9, 11, 15, 17, 19, 21, 22


Addendum 1, May 2015 xlii


Amdt 191-


Docket or RIN No.

Effective Date


22 Mechanical Fitting Failure Reporting Requirements

76 FR 5494 02/01/11 RIN 2137-AE60

04/04/11 12

23 Miscellaneous Changes to Pipeline Safety Regulations

80 FR 12762 03/11/15 RIN 2137-AE59

10/01/15 7, 25, 27, 29

* Issued as a Direct Final Rule (DFR) or Interim Final Rule.


Addendum 1, May 2015 xliii

HISTORICAL RECONSTRUCTION OF PART 192

(Complete through Amendment 192-120)

Part 192 Subpart

Part 192 Section


Amendments (if any)

SUBPART A – GENERAL

192.1 192-27, 192-67, 192-78, 192-81, 192-92, RIN 2137-AD77, 192-102, 192-103

192.3 192-13, 192-27, 192-58, 192-67, 192-72 + Ext., 192-78, 192-81, 192-85, 192-89, RIN 2137-AD43, 192-93, 192-94, 192-98, RIN 2137-AD77, 192-112, 192-114, 192-120

192.5 192-27, 192-56, 192-78, 192-85 192.7 192-37, 192-51, 192-68, 192-78,

192-94, RIN 2137-AD77, 192-99, 192-102, 192-103, RIN 2137-AE29, RIN 2137-AE25, RIN 2137-AE29 (#2), RIN 2137-AE42, 192-112, 192-114, 192-119

192.8 04/14/06 192-102 192.9 192-72 + Ext., 192-95 Corr., 192-102,

192-120 192.10 03/19/98 192-81, RIN 2137-AD77 192.11 11/13/72 192-68, 192-75, 192-78, 192-119 [192.12] 192-10, 192-36 (removed) 192.13 192-27, 192-30, 192-102 192.14 12/30/77 192-30 192.15 192.16 09/13/95 192-74, 192-74A, 192-84 [192.17] 01/01/71 192-1, 192-27A Ext., 192-38

(removed)

SUBPART B – 192.51 MATERIALS 192.53 192.55 192-3, 192-12, 192-51, 192-68,

192-85, 192-119 192.57 192-62 (removed and reserved) 192.59 192-19, 192-58, 192-119 192.61 192-62 (removed and reserved) 192.63 192-3, 192-31, 192-31A, 192-61,

192-61A, 192-62, 192-68, 192-76, 192-114, 192-119

192.65 192-12, 192-17, 192-68, 192-114, 192-119, 192-120


Addendum 1, May 2015 xliv

HISTORICAL RECONSTRUCTION OF PART 192 (Continued)

Part 192 Subpart

Part 192 Section


Amendments (if any)

SUBPART C – PIPE 192.101 DESIGN 192.103 192.105 192-47, 192-85 192.107 192-78, 192-84, 192-85 192.109 192-85 192.111 192-27 192.112 12/22/08 RIN 2137-AE25, 192-111, 192-119,

192-120 192.113 192-37, 192-51, 192-62, 192-68,

192-85, 192-94, 192-119 192.115 192-85 192.117 192-37, 192-62 (removed and

reserved) 192.119 192-62 (removed and reserved) 192.121 192-31, 192-78, 192-85, 192-94,

192-103, RIN 2137-AE26, 192-111, 192-114

192.123 192-31, 192-78, 192-85, 192-93, 192-94, 192-103, RIN 2137-AE26, 192-114, 192-119

192.125 192-62, 192-85


Addendum 1, May 2015 xlv

HISTORICAL RECONSTRUCTION OF PART 192 (Continued) Part 192 Subpart

Part 192 Section


Amendments (if any)

SUBPART D – DESIGN 192.141 OF PIPELINE 192.143 192-48, RIN 2137-AE09 COMPONENTS 192.144 08/04/83 192-45, 192-94 192.145 192-3, 192-22, 192-37, 192-62,

192-85, 192-94, 192-103, 192-114, 192-119

192.147 192-62, 192-68, 192-119 192.149 192.150 05/12/94 192-72 + Ext., 192-85, 192-97 192.151 192-85 192.153 192-3, 192-68, 192-85, 192-119,

192-120 192.155 192.157 192.159 192.161 192-27, 192-58 192.163 192-27, 192-37, 192-68, 192-85,

192-119 192.165 192-119, 192-120 192.167 192-27, 192-85 192.169 192.171 192.173 192.175 192-85 192.177 192-58, 192-62, 192-68, 192-85,

192-119 192.179 192-27, 192-78, 192-85 192.181 192.183 192-85 192.185 192.187 192-85 192.189 192-76, 192-119 192.191 192-3, 192-58, 192-114, 192-119 192.193 192.195 192.197 192-85, 192-93 192.199 192-3 192.201 192-9, 192-85 192.203 192-78, 192-85


Addendum 1, May 2015 xlvi


Part 192 Subpart

Part 192 Section


Amendments (if any)

SUBPART E – 192.221 WELDING OF STEEL [192.223] 192-52 (removed) IN PIPELINES 192.225 192-18, 192-22, 192-37, 192-52,

192-94, 192-103, 192-119, 192-120 192.227 192-18, 192-18A, 192-22, 192-37,

192-43, 192-52, 192-75, 192-78, 192-94, 192-103, 192-119, 192-120

192.229 192-18, 192-18A, 192-37, 192-78, 192-85, 192-94, 192-103, 192-119, 192-120

192.231 192.233 192.235 [192.237] 192-37, 192-52 (removed) [192.239] 192-37, 192-52 (removed) 192.241 192-18, 192-18A, 192-37, 192-78,

192-85, 192-94, 192-103, 192-119, 192-120

192.243 192-27, 192-50, 192-78, 192-120 192.245 192-27, 192-46

SUBPART F – 192.271 JOINING OF 192.273 MATERIALS OTHER 192.275 192-62 THAN BY WELDING 192.277 192-62 192.279 192-62, 192-68 192.281 192-34, 192-58, 192-61, 192-68,

192-78, 192-114, 192-119 192.283 07/01/80 192-34 + Ext., 192-34A, 192-34B,

192-68, 192-78, 192-85, 192-94, 192-103, 192-114, 192-119

192.285 07/01/80 192-34 + Ext., 192-34A, 192-34B, 192-93, 192-94, 192-120

192.287 07/01/80 192-34 + Ext., 192-94


Addendum 1, May 2015 xlvii


Part 192 Subpart

Part 192 Section


Amendments (if any)

SUBPART G – 192.301 GENERAL 192.303 CONSTRUCTION 192.305 192-120 REQUIREMENTS FOR 192.307 TRANSMISSION 192.309 192-3, 192-85, 192-88 LINES AND MAINS 192.311 192-93 192.313 192-26, 192-29, 192-49, 192-85 192.315 192-85 192.317 192-27, 192-78 192.319 192-27, 192-78, 192-85 192.321 192-78, 192-85, 192-93, 192-94 192.323 192.325 192-85 192.327 192-27, 192-78, 192-85, 192-98 192.328 12/22/08 RIN 2137-AE25

SUBPART H – 192.351 CUSTOMER METERS, 192.353 192-85, 192-93 SERVICE 192.355 192-58 REGULATORS, AND 192.357 SERVICE LINES 192.359 192-3, 192-85 192.361 192-75, 192-85, 192-93 192.363 192.365 192.367 192-75 192.369 192.371 192-3, 192-85 192.373 192-85 192.375 192-78 192.377 192.379 11/03/72 192-8 192.381 07/22/96 192-79, 192-80, 192-85 192.383 02/03/98 192-83, 192-113, 192-116


xlviii


Part 192 Subpart

Part 192 Section


Amendments (if any)

SUBPART I – 192.451 08/01/71 192-4, 192-27, 192-33 REQUIREMENTS FOR 192.452 12/30/77 192-30, 192-102 CORROSION 192.453 08/01/71 192-4, 192-71 CONTROL 192.455 08/01/71 192-4, 192-28, 192-39, 192-78,

192-85 192.457 08/01/71 192-4, 192-33, 192-93 192.459 08/01/71 192-4, 192-87 192.461 08/01/71 192-4 192.463 08/01/71 192-4 192.465 08/01/71 192-4, 192-27, 192-33, 192-35,

192-35A, 192-85, 192-93, 192-114 192.467 08/01/71 192-4, 192-33 192.469 08/01/71 192-4, 192-27 192.471 08/01/71 192-4 192.473 08/01/71 192-4, 192-33 192.475 08/01/71 192-4, 192-33, 192-78, 192-85 192.476 05/23/07 RIN 2137-AE09 192.477 08/01/71 192-4, 192-33 192.479 08/01/71 192-4, 192-33, 192-93 192.481 08/01/71 192-4, 192-27, 192-33, 192-93 192.483 08/01/71 192-4 192.485 08/01/71 192-4, 192-33, 192-78, 192-88,

192-119 192.487 08/01/71 192-4, 192-88 192.489 08/01/71 192-4 192.490 10/25/05 192-101 192.491 08/01/71 192-4, 192-33, 192-78


Addendum 1, May 2015 xlix


Part 192 Subpart

Part 192 Section


Amendments (if any)

SUBPART J – TEST 192.501 REQUIREMENTS 192.503 192-58, 192-60, 192-60A, 192-120 192.505 192-85, 192-94, 192-120 192.507 192-58, 192-85 192.509 192-58, 192-85 192.511 192-75, 192-85 192.513 192-77, 192-85 192.515 192.517 192-93

SUBPART K – 192.551 UPRATING 192.553 192-78, 192-93 192.555 192.557 192-37, 192-62, 192-85

SUBPART L – 192.601 OPERATIONS 192.603 192-27A Ext., 192-66, 192-71,

192-75, 192-118 192.605 192-27A Ext., 192-59, 192-71,

192-71A, 192-93, 192-112 192.607 192-5, 192-78 (removed and

reserved) 192.609 192.611 192-5, 192-53, 192-63, 192-78,

192-94, RIN 2137-AE25 192.612 01/06/92 192-67, 192-85, 192-98 192.613 192.614 04/01/83 192-40, 192-57, 192-73, 192-78,

192-82, 192-84 + DFR Removal 192.615 192-24, 192-71, 192-112 192.616 02/11/95 192-71, 192-99, 192-103,

RIN 2137-AE17 192.617 192.619 192-3, 192-27, 192-27A, 192-30,

192-78, 192-85, 192-102, 192-103, RIN 2137-AE25

192.620 12/22/08 RIN 2137-AE25, 192-111, 192-120 192.621 192-85 192.623 192-75 192.625 192-2, 192-6, 192-7, 192-14,

192-15, 192-16, 192-21, 192-58, 192-76, 192-78, 192-93

192.627 192.629 192.631 02/01/10 192-112, 192-117


Addendum 1, May 2015 l


Part 192 Subpart

Part 192 Section


Amendments (if any)

SUBPART M – 192.701 MAINTENANCE 192.703 102.705 192-21, 192-43, 192-78 192.706 06/04/75 192-21, 192-43, 192-71 192.707 192-20, 192-20A, 192-27, 192-40,

192-44, 192-73, 192-85 192.709 192-78 192.711 192-27B, 192-88, 192-114 192.713 192-27, 192-88 192.715 192-85 192.717 192-11, 192-27, 192-85, 192-88 192.719 192-54 192.721 192-43, 192-78 192.723 192-43, 192-70, 192-71, 192-94 192.725 192.727 192-8, 192-27, 192-71, 192-89,

RIN 2137-AD77, 192-103, RIN 2137-AE29, RIN 2137-AE29 (#2)

[192.729] 192-71 (removed) 192.731 192-43 [192.733] 192-71 (removed) 192.735 192-119 192.736 10/18/93 192-69, 192-85 [192.737] 192-71 (removed) 192.739 192-43, 192-93, 192-96 192.741 192.743 192-43, 192-55, 192-93, 192-96 192.745 192-43, 192-93 192.747 192-43, 192-93 192.749 192-43, 192-85 192.751 192.753 192-25, 192-85, 192-93 192.755 06/01/76 192-23 [Header] 192-103 (removed) [192.761] 192-91, 192-95 (removed)

SUBPART N – 192.801 10/26/99 192-86 QUALIFICATION OF 192.803 10/26/99 192-86, 192-90 PIPELINE 192.805 10/26/99 192-86, 192-100, 192-120 PERSONNEL 192.807 10/26/99 192-86 192.809 10/26/99 192-86, 192-90, 192-100


Addendum 1, May 2015 li


Part 192 Subpart

Part 192 Section


Amendments (if any)

SUBPART O – Header 02/14/04 192-95, 192-103 PIPELINE INTEGRITY 192.901 02/14/04 192-95 MANAGEMENT 192.903 02/14/04 192-95, 192-103, 192-119 192.905 02/14/04 192-95 192.907 02/14/04 192-95, 192-103 192.909 02/14/04 192-95 192.911 02/14/04 192-95, 192-103 192.913 02/14/04 192-95, 192-103 192.915 02/14/04 192-95 192.917 02/14/04 192-95, 192-103 192.919 02/14/04 192-95 192.921 02/14/04 192-95, 192-103 192.923 02/14/04 192-95, 192-103, 192-114, 192-119 192.925 02/14/04 192-95, 192-103, 192-114, 192-119,

192-120 192.927 02/14/04 192-95, 192-103 192.929 02/14/04 192-95, 192-103 192.931 02/14/04 192-95, 192-103, 192-114, 192-119 192.933 02/14/04 192-95, 192-103, 192-104, 192-119 192.935 02/14/04 192-95, 192-103, 192-114, 192-119 192.937 02/14/04 192-95, 192-103 192.939 02/14/04 192-95, 192-103, 192-114, 192-119 192.941 02/14/04 192-95 192.943 02/14/04 192-95 192.945 02/14/04 192-95, 192-103, 192-115 192.947 02/14/04 192-95 192.949 02/14/04 192-95, RIN 2137-AD77, 192-103,

RIN 2137-AE29, RIN 2137-AE29 (#2), 192-120

192.951 02/14/04 192-95, RIN 2137-AD77, 192-103, RIN 2137-AE29, RIN 2137-AE29 (#2), 192-115

SUBPART P – 192.1001 02/12/10 192-113, 192-116 GAS DISTRIBUTION 192.1003 02/12/10 192-113 PIPELINE INTEGRITY 192.1005 02/12/10 192-113 MANAGEMENT (IM) 192.1007 02/12/10 192-113, 192-116 192.1009 02/12/10 192-113, 192-116 192.1011 02/12/10 192-113 192.1013 02/12/10 192-113 192.1015 02/12/10 192-113


lii


Part 192 Subpart

Part 192 Section


Amendments (if any)

FEDERAL APPENDICES

[App. A] 192-3, 192-10, 192-12, 192-17, 192-18, 192-19, 192-22, 192-32, 192-34 + Ext., 192-37, 192-41, 192-42, 192-51, 192-61, 192-62, 192-64, 192-65, 192-68, 192-76, 192-78, 192-84, 192-95, 192-94 (removed and reserved)

App. B 192-3, 192-12, 192-19, 192-22, 192-32, 192-37, 192-41, 192-51, 192-61, 192-62, 192-65, 192-68, 192-76, 192-85, 192-94, 192-103, 192-114, 192-119

App. C 192-85, 192-94

App. D 08/01/71 192-4

App. E 12/15/03 192-95


Addendum 1, May 2015 lxxiii


Amdt 192-


Docket or RIN No.

Effective Date


119 Periodic Updates of Regulatory References to Technical Standards and Miscellaneous Amendments

80 FR 168 01/05/15 RIN 2137-AE85

03/06/15 7, 11, 55, 59, 63, 65, 112, 113, 123, 145, 147, 153, 163, 165, 177, 189, 191, 225, 227, 229, 241, 281, 283, 485, 735, 903, 923, 925, 931, 933,

935, 939, App. B

120 Miscellaneous Changes to Pipeline Safety Regulations

80 FR 12762 03/11/15 RIN 2137-AE59

10/01/15 3, 9, 65, 112, 153, 165, 225, 227, 229, 241, 243, 285, 305, 503, 505, 620, 805,

925, 949

* Issued as a Direct Final Rule (DFR) or Interim Final Rule.


lxxiv

Reserved

GPTC GUIDE FOR GAS TRANSMISSION, DISTRIBUTION, §191.1 AND GATHERING PIPING SYSTEMS: 2015 Edition

Addendum 1, May 2015 1

PART 191

ANNUAL REPORTS, INCIDENT REPORTS, AND SAFETY-RELATED CONDITION REPORTS

Authority: 49 U.S.C. 5121, 60102, 60103, 60104, 60108, 60117, 60118, 60124, 60132, and 49 CFR 1.97. Source: Originally 35 FR 317, Jan. 8, 1970; currently Amdt. 191-23, 80 FR 12762, Mar. 11, 2015.

§191.1 Scope.

[Effective Date: 01/01/11]

(a) This part prescribes requirements for the reporting of incidents, safety-related conditions, annual pipeline summary data by operators of gas pipeline facilities located in the United States or Puerto Rico, including pipelines within the limits of the Outer Continental Shelf as that term is defined in the Outer Continental Shelf Lands Act (43 U.S.C. 1331). (b) This part does not apply to— (1) Offshore gathering of gas in State waters upstream from the outlet flange of each facility where hydrocarbons are produced or where produced hydrocarbons are first separated, dehydrated, or otherwise processed, whichever facility is farther downstream; (2) Pipelines on the Outer Continental Shelf (OCS) that are producer-operated and cross into State waters without first connecting to a transporting operator’s facility on the OCS, upstream (generally seaward) of the last valve on the last production facility on the OCS. Safety equipment protecting PHMSA-regulated pipeline segments is not excluded. Producing operators for those pipeline segments upstream of the last valve of the last production facility on the OCS may petition the Administrator, or designee, for approval to operate under PHMSA regulations governing pipeline design, construction, operation, and maintenance under 49 CFR 190.9. (3) Pipelines on the Outer Continental Shelf upstream of the point at which operating responsibility transfers from a producing operator to a transporting operator; or (4) Onshore gathering of gas— (i) Through a pipeline that operates at less than 0 psig (0 kPa); (ii) Through a pipeline that is not a regulated onshore gathering line (as determined in §192.8 of this subchapter); and (iii) Within inlets of the Gulf of Mexico, except for the requirements in §192.612. [Amdt. 191-5, 49 FR 18956, May 3, 1984; Amdt. 191-6, 53 FR 24942, July 1, 1988 with Amdt. 191-6 Correction, 53 FR 26560, July 13, 1988; Amdt. 191-11, 61 FR 27789, June 3, 1996 with Amdt. 191-11 Correction, 61 FR 45905, Aug. 30, 1996; Amdt. 191-12, 62 FR 61692, Nov. 19, 1997 with Amdt. 191-12 Confirmation, 63 FR 12659, Mar. 16, 1998; Amdt. 191-15, 68 FR 46109, Aug. 5, 2003; RIN 2137-AD77, 70 FR 11135, Mar. 8, 2005; Amdt. 191-21, 75 FR 72878, Nov. 26, 2010]

GUIDE MATERIAL (a) For offshore pipelines, responsibilities have been assigned to the Department of Transportation and the

Department of the Interior in accordance with their Memorandum of Understanding dated December 10, 1996 (Implemented per Federal Register, Vol. 62, No. 223, November 19, 1997). See Guide Material Appendix G-192-19.


2

(b) State regulations may be more stringent and require additional reporting for operators of intrastate pipelines. A NAPSR document (1st Edition 2011) provides a compendium of these additional state requirements and is available at www.napsr.org.

§191.3 Definitions.


As used in this part and the PHMSA Forms referenced in this part— Administrator means the Administrator, Pipeline and Hazardous Materials Safety Administration or his or her delegate. Gas means natural gas, flammable gas, or gas which is toxic or corrosive; Incident means any of the following events: (1) An event that involves a release of gas from a pipeline, or of liquefied natural gas, liquefied petroleum gas, refrigerant gas, or gas from an LNG facility, and that results in one or more of the following consequences: (i) A death, or personal injury necessitating in-patient hospitalization; (ii) Estimated property damage of $50,000 or more, including loss to the operator and others, or both, but excluding cost of gas lost; (iii) Unintentional estimated gas loss of three million cubic feet or more; (2) An event that results in an emergency shutdown of an LNG facility. Activation of an emergency shutdown system for reasons other than an actual emergency does not constitute an incident. (3) An event that is significant in the judgment of the operator, even though it did not meet the criteria of paragraphs (1) or (2) of this definition. LNG facility means a liquefied natural gas facility as defined in §193.2007 of part 193 of this chapter; Master Meter System means a pipeline system for distributing gas within, but not limited to, a definable area, such as a mobile home park, housing project, or apartment complex, where the operator purchases metered gas from an outside source for resale through a gas distribution pipeline system. The gas distribution pipeline system supplies the ultimate consumer who either purchases the gas directly through a meter or by other means, such as by rents; Municipality means a city, count or any other political subdivision of a state; Offshore means beyond the line of ordinary low water along that portion of the coast of the United States that is in direct contact with the open seas and beyond the line marking the seaward limit of inland waters; Operator means a person who engages in the transportation of gas; Outer Continental Shelf means all submerged lands lying seaward and outside the area of lands beneath navigable waters as defined in Section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control. Person means any individual, firm, joint venture, partnership, corporation, association, state, municipality, cooperative association, or joint stock association, and includes any trustee, receiver, assignee, or personal representative thereof; Pipeline or Pipeline System means all parts of those physical facilities through which gas moves in transportation, including, but not limited to, pipe, valves, and other appurtenance attached to pipe, compressor units, metering stations, regulator stations, delivery stations, holders, and fabricated assemblies. State includes each of the several states, the District of Columbia, and the Commonwealth of Puerto Rico;


3

Transportation of gas means the gathering, transmission, or distribution of gas by pipeline, or the storage of gas in or affecting interstate or foreign commerce. [Amdt. 191-5, 49 FR 18956, May 3, 1984; Amdt. 191-10, 61 FR 18512, Apr. 26, 1996; Amdt. 191-12, 62 FR 61692, Nov. 19, 1997 with Amdt. 191-12 Confirmation, 63 FR 12659, Mar. 16, 1998; RIN 2137-AD43, 68 FR 11748, Mar. 12, 2003; RIN 2137-AD77, 70 FR 11135, Mar. 8, 2005; Amdt. 191-21, 75 FR 72878, Nov. 26, 2010]

GUIDE MATERIAL ADDITIONAL INCIDENT CONSIDERATIONS (a) State regulations may be more stringent and require additional reporting for operators of intrastate

pipelines. (b) "In-patient hospitalization" means hospital admission and at least one overnight stay. (c) Estimated property damage includes, but is not limited to, costs due to: (1) Property damage to operator's facilities and property of others. (2) Facility repair and replacement. (3) Restoration of gas distribution service and relighting customers. (4) Leak locating. (5) Right-of-way cleanup. (6) Environmental cleanup and damage. (d) Items to be considered when determining if an event may be significant include the following. (1) Rupture or explosion. (2) Fire. (3) Loss of service. (4) Evacuation of people in the area. (5) Involvement of local emergency response personnel.

(6) Degree of media involvement. (e) For guidance on calculating gas loss from a damaged pipeline, see Guide Material Appendix G-191-9.

§191.5 Immediate notice of certain incidents.


(a) At the earliest practicable moment following discovery, each operator shall give notice in accordance with paragraph (b) of this section of each incident as defined in §191.3. (b) Each notice required by paragraph (a) of this section must be made to the National Response Center either by telephone to 800–424–8802 (in Washington, DC, 202 267–2675) or electronically at http://www.nrc.uscg.mil and must include the following information: (1) Names of operator and person making report and their telephone numbers. (2) The location of the incident. (3) The time of the incident. (4) The number of fatalities and personal injuries, if any. (5) All other significant facts that are known by the operator that are relevant to the cause of the incident or extent of the damages.


Amendment 1, May 2015 4

[Amdt. 191-1, 36 FR 7507, Apr. 21, 1971; Amdt. 191-4, 47 FR 32719, July 29, 1982; Amdt. 191-5, 49 FR 18956, May 3, 1984; Amdt. 191-8, 54 FR 40878, Oct. 4, 1989; Amdt. 191-21, 75 FR 72878, Nov. 26, 2010]

GUIDE MATERIAL (a) Complete information is not necessary for the initial electronic or telephonic incident report to National

Response Center (NRC). Refer to Guide Material Appendix G-191-1 for a sample worksheet that may be used to compile information for the incident report. The initial incident report should be made within 2 hours of discovery of the incident. Initial report information should include the following.

(1) Name, address, and a 24-hour telephone number of the operator. An operator should consider providing a telephone number where more detailed information can be obtained.

(2) Time and date of incident. (3) Location of incident, provided in a manner that will aid agencies in locating the site on maps. GPS

coordinates, addresses and ZIP codes, and cross streets are useful. (4) Facilities involved. (5) Number of fatalities or injuries, if known. (6) Estimate of property damage. (7) Type of product released, and an estimate of the quantity released. For guidance on calculating

gas loss from a damaged pipeline, see Guide Material Appendix G-191-9. (8) Evacuations, if known. (9) The responsible party, if known. (10) Weather conditions at the incident site. (b) If an incident report has been made and further investigation reveals that the event was not an "incident,"

and therefore not reportable, the report should be nullified with a letter. This letter should be sent to the Information Resources Manager at the address specified in §191.7 within 30 days of the event. The letter should reference the NRC incident report number issued when the initial notification was made and briefly explain why the incident report is being nullified. Incident reports cannot be removed from the database, but the letter may help ensure accurate PHMSA-OPS records.

(c) Operators should consider making an additional report if there is a significant change in the data

previously provided to the NRC. A significant change may include an increase or decrease in the number of injuries or fatalities previously reported, or a revised estimate of property damage that is at least 10 times that previously reported. Consideration should be given to making an additional report up to 48 hours following the initial report. The operator should clearly report to the NRC that additional information is being provided and give the NRC the initial report’s assigned NRC Report Number. However, any report following the initial report will result in an additional NRC Report Number being created for the same event. All related NRC Report Numbers should be referenced in the PHMSA-OPS electronic or written incident report (see §§191.9 and 191.15).

(d) For intrastate pipelines, it is necessary to comply with federal reporting requirements even though an

"incident" has been reported to the appropriate state agency.

§191.7 Report submission requirements.

▌[Effective Date: 10/01/15]

(a) General. Except as provided in paragraphs (b) and (e) of this section, an operator must submit each report required by this part electronically to the Pipeline and Hazardous Materials Safety Administration at http://portal.phmsa.dot.gov/pipeline unless an alternative reporting method is



authorized in accordance with paragraph (d) of this section. (b) Exceptions. An operator is not required to submit a safety-related condition report (§191.25) electronically. (c) Safety-related conditions. An operator must submit concurrently to the applicable State agency a safety-related condition report required by §191.23 for intrastate pipeline transportation or when the State agency acts as an agent of the Secretary with respect to interstate transmission facilities. (d) Alternative Reporting Method. If electronic reporting imposes an undue burden and hardship, an operator may submit a written request for an alternative reporting method to the Information Resources Manager, Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, PHP–20, 1200 New Jersey Avenue, SE, Washington DC 20590. The request must describe the undue burden and hardship. PHMSA will review the request and may authorize, in writing, an alternative reporting method. An authorization will state the period for which it is valid, which may be indefinite. An operator must contact PHMSA at 202–366–8075, or electronically to [email protected] or make arrangements for submitting a report that is due after a request for alternative reporting is submitted but before an authorization or denial is received. (e) National Pipeline Mapping System (NPMS). An operator must provide the NPMS data to the address identified in the NPMS Operator Standards manual available at www.npms.phmsa.dot.gov or by contacting the PHMSA Geographic Information Systems Manager at (202) 366-4595. [Amdt. 191-3, 46 FR 37250, July 20, 1981; Amdt. 191-4, 47 FR 32719, July 29, 1982; Amdt. 191-5, 49 FR 18956, May 3, 1984; Amdt. 191-6, 53 FR 24942, July 1, 1988 with Amdt. 191-6 Correction, 53 FR 26560, July 13, 1988; Amdt. 191-16, 69 FR 32886, June 14, 2004; RIN 2137-AD77, 70 FR 11135, Mar. 8, 2005; RIN 2137-AE29, 73 FR 16562, Mar. 28, 2008; RIN 2137-AE29 (#2), 74 FR 2889, Jan. 16, 2009; Amdt. 191-21, 75 FR 72878, Nov. 26, 2010; Amdt. 191-23, 80 FR 12762, Mar. 11, 2015]

GUIDE MATERIAL

No guide material necessary.

§191.9 Distribution system: Incident report.


(a) Except as provided in paragraph(c) of this section, each operator of a distribution pipeline system shall submit Department of Transportation Form RSPA F 7100.1 as soon as practicable but not more than 30 days after detection of an incident required to be reported under §191.5. (b) When additional relevant information is obtained after the report is submitted under paragraph (a) of this section, the operator shall make supplementary reports as deemed necessary with a clear reference by date and subject to the original report. (c) Master meter operators are not required to submit an incident report as required by this section. [Amdt. 191-3, 46 FR 37250, July 20, 1981; Amdt. 191-5, 49 FR 18956, May 3, 1984; Amdt. 191-21, 75 FR 72878, Nov. 26, 2010]

GUIDE MATERIAL See Guide Material Appendix G-191-2, Form PHMSA F 7100.1 and related instructions. Report forms and instructions can be downloaded from the PHMSA-OPS website at www.phmsa.dot.gov/pipeline/library/forms. Additional state requirements may exist for intrastate facilities.


6

§191.11 Distribution system: Annual report.


(a) General. Except as provided in paragraph (b) of this section, each operator of a distribution pipeline system must submit an annual report for that system on DOT Form PHMSA F7100.1–1. This report must be submitted each year, not later than March 15, for the preceding calendar year. (b) Not required. The annual report requirement in this section does not apply to a master meter system or to a petroleum gas system that serves fewer than 100 customers from a single source. [Amdt. 191-2, 37 FR 1172, Jan. 26, 1972; Amdt. 191-5, 49 FR 18956, May 3, 1984; Amdt. 191-21, 75 FR 72878, Nov. 26, 2010]

GUIDE MATERIAL See Guide Material Appendix G-191-3, Form PHMSA F 7100.1-1 and related instructions. Report forms and instructions can be downloaded from the PHMSA-OPS website at www.phmsa.dot.gov/pipeline/library/forms. Additional state requirements may exist for intrastate facilities.

§191.12 Distribution systems: Mechanical fitting failure reports.


Each mechanical fitting failure, as required by §192.1009, must be submitted on a Mechanical Fitting Failure Report Form PHMSA F–7100.1–2. An operator must submit a mechanical fitting failure report for each mechanical fitting failure that occurs within a calendar year not later than March 15 of the following year (for example, all mechanical failure reports for calendar year 2011 must be submitted no later than March 15, 2012). Alternatively, an operator may elect to submit its reports throughout the year. In addition, an operator must also report this information to the State pipeline safety authority if a State has obtained regulatory authority over the operator’s pipeline. [Issued by Amdt. 191-22, 76 FR 5494, Feb. 1, 2011]

GUIDE MATERIAL 1 GENERAL See Guide Material Appendix G-191-4, Form PHMSA F 7100.1-2 and related instructions. Report forms

and instructions can be downloaded from the PHMSA-OPS website at: www.phmsa.dot.gov/pipeline/library/forms Section 191.7 requires operators to submit mechanical fitting failure reports electronically to PHMSA

unless an alternative reporting method is authorized. For the definition of mechanical fitting, see §192.1001. Additional state requirements may exist for intrastate facilities.



facility that contains or processes gas or LNG. (b) A report is not required for any safety-related condition that- (1) Exists on a master meter system or a customer-owned service line; (2) Is an incident or results in an incident before the deadline for filing the safety-related condition report; (3) Exists on a pipeline (other than an LNG facility) that is more than 220 yards (200 meters) from any building intended for human occupancy or outdoor place of assembly, except that reports are required for conditions within the right-of-way of an active railroad, paved road, street, or highway; or (4) Is corrected by repair or replacement in accordance with applicable safety standards before the deadline for filing the safety-related condition report, except that reports are required for conditions under paragraph (a)(1) of this section other than localized corrosion pitting on an effectively coated and cathodically protected pipeline. [Issued by Amdt. 191-6, 53 FR 24942, July 1, 1988 with Amdt. 191-6 Correction, 53 FR 26560, July 13, 1988; Amdt. 191-14, 63 FR 37500, July 13, 1998]

GUIDE MATERIAL (a) For the purpose of Safety-Related Condition Reports, "in-service facilities" are those that are pressurized

with gas, regardless of flow conditions. Facilities that are not "in-service" are completely depressurized and isolated from all pressurized facilities by valves or physical separation.

(b) See Guide Material Appendix G-191-7 for a chart useful in determining if reports must be filed. (c) See guide material under §192.617 for failure investigation, when applicable. (d) If the MAOP plus the build-up allowed for operation of pressure-limiting or control devices on a

transmission line is exceeded, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 ("Act")(Section 23(b)) requires the operator to notify the Secretary of Transportation, and appropriate state agencies if the pipeline is subject to state regulations, on or before the fifth calendar day of the exceedance. PHMSA-OPS issued Advisory Bulletin ADB-2012-11 (77 FR 75699, Dec. 21, 2012; reference Guide Material Appendix G-192-1, Section 2) to advise owners and operators of gas transmission pipeline facilities of new reporting requirements in the Act. The Act requires reporting the exceedance even if the condition is corrected within the reporting timeframe. The Advisory Bulletin requests operators to submit information comparable to that required for a safety-related condition (see Guide Material Appendix G-191-8). The operator should note that the reporting requirement for an exceedance is calendar days, as opposed to the safety-related conditions requirement of working days that does not include Saturdays, Sundays, or federal holidays.

§191.25 Filing safety-related condition reports.


(a) Each report of a safety-related condition under §191.23(a) must be filed (received by OPS within five working days, not including Saturday, Sunday, or Federal Holidays) after the day a representative of the operator first determines that the condition exists, but not later than 10 working days after the day a representative of the operator discovers the condition. Separate conditions may be described in a single report if they are closely related. Reports may be transmitted by electronic mail to [email protected] or by facsimile at (202) 366-7128.



(b) The report must be headed "Safety-Related Condition Report" and provide the following information: (1) Name and principal address of operator. (2) Date of report. (3) Name, job title, and business telephone number of person submitting the report. (4) Name, job title, and business telephone number of person who determined that the condition exists. (5) Date condition was discovered and date condition was first determined to exist. (6) Location of condition, with reference to the state (and town, city, or county) or offshore site, and as appropriate, nearest street address, offshore platform, survey station number, milepost, landmark, or name of pipeline. (7) Description of the condition, including circumstances leading to its discovery, any significant effects of the condition on safety, and the name of the commodity transported or stored. (8) The corrective action taken (including reduction of pressure or shutdown) before the report is submitted and the planned follow-up or future corrective action, including the anticipated schedule for starting and concluding such action. [Issued by Amdt. 191-6, 53 FR 24942, July 1, 1988 with Amdt. 191-6 Correction, 53 FR 26560, July 13, 1988 and Amdt. 191-6 Correction, 53 FR 29800, Aug. 8, 1988; Amdt. 191-7, 54 FR 32342, Aug. 7, 1989; Amdt. 191-8, 54 FR 40878, Oct. 4, 1989; Amdt. 191-10, 61 FR 18512, Apr. 26, 1996; Amdt. 191-23, 80 FR 12762, Mar. 11, 2015]

GUIDE MATERIAL (a) The preamble to Amendment 191-7 ("Interpretation and Statement of Policy Regarding Discovery of

Safety-Related Conditions by Smart Pigs and Instructions to Personnel") states: "Discovery of a potentially reportable condition occurs when an operator's representative has

adequate information from which to conclude the probable existence of a reportable condition. An operator would have adequate information for each anomaly that is physically examined. Absent physical examination, discovery may occur after the data are calibrated if the "adequate information" test is met. However, the adequacy of the information that pig data provide about anomalous conditions is contingent on a concurrent indication from a number of factors from which an operator could conclude the probable existence of a reportable condition. Among these are the sophistication of the pig being used, the reliability of the data, the accuracy of data interpretation, and any other factors known by the operator relative to the condition of the pipeline."

(b) See Guide Material Appendix G-191-8 for a form useful for reporting a safety-related condition. (c) Additional state requirements may exist for intrastate facilities.

§191.27 (Removed.)




§191.29 National Pipeline Mapping System.


(a) Each operator of a gas transmission pipeline or liquefied natural gas facility must provide the following geospatial data to PHMSA for that pipeline or facility: (1) Geospatial data, attributes, metadata and transmittal letter appropriate for use in the National Pipeline Mapping System. Acceptable formats and additional information are specified in the NPMS Operator Standards Manual available at www.npms.phmsa.dot.gov or by contacting the PHMSA Geographic Information Systems Manager at (202) 366-4595. (2) The name of and address for the operator. (3) The name and contact information of a pipeline company employee, to be displayed on a public Web site, who will serve as a contact for questions from the general public about the operator’s NPMS data. (b) The information required in paragraph (a) of this section must be submitted each year, on or before March 15, representing assets as of December 31 of the previous year. If no changes have occurred since the previous year’s submission, the operator must comply with the guidance provided in the NPMS Operator Standards manual available at www.npms.phmsa.dot.gov or contact the PHMSA Geographic Information Systems Manager at (202) 366-4595. [Issued by Amdt. 191-23, 80 FR 12762, Mar. 11, 2015]

GUIDE MATERIAL

No guide material available at present.


16

Reserved

GPTC GUIDE FOR GAS TRANSMISSION, DISTRIBUTION, §192.1 AND GATHERING PIPING SYSTEMS: 2015 Edition SUBPART A


PART 192

MINIMUM FEDERAL SAFETY STANDARDS

Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 60113, 60116, and 60118, 60137; and 49 CFR 1.97.

Source: Originally 35 FR 13248, Aug. 19, 1970; currently Amdt. 192-120, 80 FR 12762, Mar. 11, 2015.

SUBPART A GENERAL

§192.1 What is the scope of this part?


(a) This part prescribes minimum safety requirements for pipeline facilities and the transportation of gas, including pipeline facilities and the transportation of gas within the limits of the outer continental shelf as that term is defined in the Outer Continental Shelf Lands Act (43 U.S.C. 1331). (b) This part does not apply to— (1) Offshore gathering of gas in State waters upstream from the outlet flange of each facility where hydrocarbons are produced or where produced hydrocarbons are first separated, dehydrated, or otherwise processed, whichever facility is farther downstream; (2) Pipelines on the Outer Continental Shelf (OCS) that are producer-operated and cross into State waters without first connecting to a transporting operator’s facility on the OCS, upstream (generally seaward) of the last valve on the last production facility on the OCS. Safety equipment protecting PHMSA-regulated pipeline segments is not excluded. Producing operators for those pipeline segments upstream of the last valve of the last production facility on the OCS may petition the Administrator, or designee, for approval to operate under PHMSA regulations governing pipeline design, construction, operation, and maintenance under 49 CFR 190.9; (3) Pipelines on the Outer Continental Shelf upstream of the point at which operating responsibility transfers from a producing operator to a transporting operator; (4) Onshore gathering of gas— (i) Through a pipeline that operates at less than 0 psig (0 kPa); (ii) Through a pipeline that is not a regulated onshore gathering line (as determined in §192.8); and (iii) Within inlets of the Gulf of Mexico, except for the requirements in §192.612; or (5) Any pipeline system that transports only petroleum gas or petroleum gas/air mixtures to— (i) Fewer than 10 customers, if no portion of the system is located in a public place; or (ii) A single customer, if the system is located entirely on the customer’s premises (no matter if a portion of the system is located in a public place). [Amdt. 192-27, 41 FR 34598, Aug. 16, 1976; Amdt. 192-67, 56 FR 63764, Dec. 5, 1991; Amdt. 192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996; Amdt. 192-81, 62 FR 61692, Nov. 19, 1997 with Amdt. 192-81 Confirmation, 63 FR 12659, Mar. 16, 1998; Amdt. 192-92, 68



FR 46109, Aug. 5, 2003; RIN 2137-AD77, 70 FR 11135, Mar. 8, 2005; Amdt. 192-102, 71 FR 13289, Mar. 15, 2006; Amdt. 192-103, 72 FR 4655, Feb. 1, 2007]

GUIDE MATERIAL (a) The guide material presented in this Guide includes information and some acceptable methods to assist

the operator in complying with the Minimum Federal Safety Standards. The recommendations contained in the Guide are based on sound engineering principles, developed by a committee balanced in accordance with accepted committee procedures, and must be applied by the use of sound and competent engineering judgment. The guide material is advisory in nature and should not restrict the operator from using other methods of complying. In addition, the operator is cautioned that the guide material may not be adequate under all conditions encountered.

(b) While the GPTC Guide is intended principally to guide operators of natural gas pipelines, it is a valuable

reference for operators of other pipelines covered by Part 192. The user is cautioned that the unique properties and characteristics associated with other gases (e.g., toxicity, density, corrosivity, and temperature extremes) may require special engineering, operations, and maintenance considerations. Also, the unique properties and toxicity of other gases can represent significant hazards that need to be considered but are not specifically addressed in the Guide. Operators of petroleum gas distribution systems may benefit from information provided in the "Training Guide for Operators of Small LP Gas Systems" (also referred to as "Guidance Manual") available at www.phmsa.dot.gov/pipeline/tq/manuals.

(c) As used in the Guide, the terms Personnel, Employees, and Workers refer to operator employees and,

unless specifically noted otherwise, include other personnel used by operators to perform Part 192 functions.

(d) The operator is responsible for the work of a contractor performing tasks covered under Part 192. The

operator should ensure that contract personnel are familiar with applicable procedures prior to the start of work.

(e) A reference for hydrogen pipelines is OPS Report No. DOT.RSPA/DMT-10-85-1, "Safety Criteria for the

Operation of Gaseous Hydrogen Pipelines," (Discontinued). (f) For offshore pipelines, responsibilities have been assigned to the Department of Transportation and the

Department of the Interior in accordance with their Memorandum of Understanding dated December 10, 1996 (Implemented per Federal Register, Vol. 62, No. 223, November 19, 1997). See Guide Material Appendix G-192-19.

(g) Additional state requirements may exist for intrastate facilities. A NAPSR document (1st Edition 2011)

provides a compendium of these additional state requirements and is available at www.napsr.org.

§192.3 Definitions.


As used in this part: Abandoned means permanently removed from service. Active corrosion means continuing corrosion that, unless controlled, could result in a condition that is detrimental to public safety. Administrator means the Administrator, Pipeline and Hazardous Materials Safety Administration or his or her delegate.


19

Alarm means an audible or visible means of indicating to the controller that equipment or processes are outside operator-defined, safety-related parameters. Control room means an operations center staffed by personnel charged with the responsibility for remotely monitoring and controlling a pipeline facility. Controller means a qualified individual who remotely monitors and controls the safety-related operations of a pipeline facility via a SCADA system from a control room, and who has operational authority and accountability for the remote operational functions of the pipeline facility. Customer meter means the meter that measures the transfer of gas from an operator to a consumer. Distribution line means a pipeline other than a gathering or transmission line. Electrical survey means a series of closely spaced pipe-to-soil readings over pipelines which are subsequently analyzed to identify locations where a corrosive current is leaving the pipeline. Exposed underwater pipeline means an underwater pipeline where the top of the pipe protrudes above the underwater natural bottom (as determined by recognized and generally accepted practices) in waters less than 15 feet (4.6 meters) deep, as measured from mean low water. Gas means natural gas, flammable gas, or gas which is toxic or corrosive. Gathering line means a pipeline that transports gas from a current production facility to a transmission line or main. Gulf of Mexico and its inlets means the waters from the mean high water mark of the coast of the Gulf of Mexico and its inlets open to the sea (excluding rivers, tidal marshes, lakes and canals) seaward to include the territorial sea and Outer Continental Shelf to a depth of 15 feet (4.6 meters), as measured from the mean low water. Hazard to navigation means, for the purposes of this part, a pipeline where the top of the pipe is less than 12 inches (305 millimeters) below the underwater natural bottom (as determined by recognized and generally accepted practices) in waters less than 15 feet (4.6 meters) deep, as measured from the mean low water. High pressure distribution system means a distribution system in which the gas pressure in the main is higher than the pressure provided to the customer. Line section means a continuous run of transmission line between adjacent compressor stations, between a compressor station and storage facilities, between a compressor station and a block valve, or between adjacent block valves. Listed specification means a specification listed in section I of Appendix B of this part. Low-pressure distribution system means a distribution system in which the gas pressure in the main is substantially the same as the pressure provided to the customer. Main means a distribution line that serves as a common source of supply for more than one service line. Maximum actual operating pressure means the maximum pressure that occurs during normal operations over a period of 1 year. Maximum allowable operating pressure (MAOP) means the maximum pressure at which a pipeline or segment of a pipeline may be operated under this part. Municipality means a city, county, or any other political subdivision of a state. Offshore means beyond the line of ordinary low water along that portion of the coast of the United States that is in direct contact with the open seas and beyond the line marking the seaward limit of inland waters. Operator means a person who engages in the transportation of gas. Outer Continental Shelf means all submerged lands lying seaward and outside the area of lands beneath navigable waters as defined in Section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control. Person means any individual, firm, joint venture, partnership, corporation, association, state, municipality, cooperative association, or joint stock association, and including any trustee, receiver, assignee, or personal representative thereof. Petroleum gas means propane, propylene, butane, (normal butane or isobutanes), and butylene (including isomers), or mixtures composed predominantly of these gases, having a vapor pressure



not exceeding 208 psi (1434 kPa) gage at 100 oF (38 oC). Pipe means any pipe or tubing used in the transportation of gas, including pipe-type holders. Pipeline means all parts of those physical facilities through which gas moves in transportation, including pipe, valves, and other appurtenance attached to pipe, compressor units, metering stations, regulator stations, delivery stations, holders, and fabricated assemblies. Pipeline environment includes soil resistivity (high or low), soil moisture (wet or dry), soil contaminants that may promote corrosive activity, and other known conditions that could affect the probability of active corrosion. Pipeline facility means 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. Service line means a distribution line that transports gas from a common source of supply to an individual customer, to two adjacent or adjoining residential or small commercial customers, or to multiple residential or small commercial customers served through a meter header or manifold. A service line ends at the outlet of the customer meter or at the connection to a customer's piping, whichever is further downstream, or at the connection to customer piping if there is no meter. Service regulator means the device on a service line that controls the pressure of gas delivered from a higher pressure to the pressure provided to the customer. A service regulator may serve one customer or multiple customers through a meter header or manifold. SMYS means specified minimum yield strength is: (1) For steel pipe manufactured in accordance with a listed specification, the yield strength specified as a minimum in that specification; or (2) For steel pipe manufactured in accordance with an unknown or unlisted specification, the yield strength determined in accordance with §192.107(b). State means each of the several states, the District of Columbia, and the Commonwealth ofPuerto Rico. Supervisory Control and Data Acquisition (SCADA) system means a computer-based system or systems used by a controller in a control room that collects and displays information about a pipeline facility and may have the ability to send commands back to the pipeline facility. Transmission line means a pipeline, other than a gathering line, that: (1) Transports gas from a gathering line or storage facility to a distribution center, storage facility, or large volume customer that is not down-stream from a distribution center; (2) operates at a hoop stress of 20 percent or more of SMYS; or (3) transports gas within a storage field. Note: A large volume customer may receive similar volumes of gas as a distribution center, and includes factories, power plants, and institutional users of gas. Transportation of gas means the gathering, transmission, or distribution of gas by pipeline or the storage of gas, in or affecting interstate or foreign commerce. Welder means a person who performs manual or semi-automatic welding. Welding operator means a person who operates machine or automatic welding equipment. [Amdt. 192-13, 38 FR 9083, Apr. 10, 1973; Amdt. 192-27, 41 FR 34598, Aug. 16, 1976; Amdt. 192-58, 53 FR 1633, Jan. 21, 1988; Amdt. 192-67, 56 FR 63764, Dec. 5, 1991; Amdt. 192-72, 59 FR 17275, Apr. 12, 1994 with Amdt. 192-72 Ext., 59 FR 49896, Sept. 30, 1994, Amdt. 192-72 Ext. Correction, 59 FR 52863, Oct. 19, 1994 and Amdt. 192-72 Ext., 60 FR 7133, Feb. 7, 1995; Amdt. 192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996; Amdt. 192-81, 62 FR 61692, Nov. 19, 1997 with Amdt. 192-81 Confirmation, 63 FR 12659, Mar. 16, 1998; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-89, 65 FR 54440, Sept. 8, 2000; RIN 2137-AD43, 68 FR 11748, Mar. 12, 2003; Amdt. 192-93, 68 FR 53895, Sept. 15, 2003; Amdt. 192-94, 69 FR 32886, June 14, 2004 with Amdt. 192-94 Correction, 69 FR 54591, Sept. 9, 2004 and Amdt. 192-94 DFR [Correction], 70 FR 3147, Jan. 21, 2005; Amdt. 192-98, 69 FR 48400, Aug. 10, 2004; RIN 2137-AD77, 70 FR 11135, Mar. 8, 2005; Amdt. 192-112, 74 FR 63310, Dec. 3, 2009; Amdt. 192-114, 75 FR 48593, Aug. 11, 2010; Amdt. 192-120, 80 FR 12762, Mar. 11, 2015]



Yield strength is the strength at which a material exhibits a specified limiting permanent set, or produces a specified total elongation under load. The specified limiting set or elongation is usually expressed as a percentage of gage length, and its values are specified in the various material specifications acceptable under this Guide.

GLOSSARY OF COMMONLY USED ABBREVIATIONS

Note: For added organizational abbreviations, see Guide Material Appendix G-192-1, Sections 4 and 5.

Abbreviation Meaning

ABS acrylonitrile-butadiene-styrene ACVG alternating current voltage gradient AOC abnormal operating condition ASV automatic shut-off valve BAP baseline assessment plan CAB cellulose acetate butyrate CDA confirmatory direct assessment CGI combustible gas indicator CIS close-interval survey CP cathodic protection CTS copper tube size DA direct assessment DCVG direct current voltage gradient DIMP Distribution Integrity Management Program ECDA external corrosion direct assessment EFV excess flow valve EFVB excess flow valve – bypass (automatic reset) EFVNB excess flow valve – non-bypass (manual reset) ERW electric resistance welded ESD emergency shutdown FAQ frequently asked question FBE fusion bonded epoxy FRP fiberglass reinforced plastic GIS geographic information system GMA Guide Material Appendix GPS global positioning system HCA high consequence area HDB hydrostatic design basis HFI hydrogen flame ionization

TABLE 192.3i (Continued)


28

GLOSSARY OF COMMONLY USED ABBREVIATIONS (Continued)

Abbreviation Meaning

IBR Incorporated by reference (see §192.7) IC internal corrosion ICDA internal corrosion direct assessment ICS Incident Command System ILI in-line inspection IMP integrity management program IPS iron pipe size IR drop voltage drop LEL lower explosive limit LNG liquefied natural gas LPG liquid or liquefied petroleum gas LTHS long-term hydrostatic strength MAOP maximum allowable operating pressure MIC microbiologically influenced corrosion MOC management of change MOP maximum operating pressure MRS minimum required strength NAPSR National Association of Pipeline Safety Representatives NDE nondestructive evaluation NPS nominal pipe size O&M operations and maintenance OCS outer continental shelf OQ operator qualification PA polyamide P&M measures preventive and mitigative measures PDB pressure design basis PE polyethylene PIC potential impact circle PIR potential impact radius PVC poly (vinyl chloride), also written as polyvinyl chloride RCV remote control valve SCADA supervisory control and data acquisition SCC stress corrosion cracking SCCDA stress corrosion cracking direct assessment SDB strength design basis SDR standard dimension ratio SME subject matter expert SMYS specified minimum yield strength USGS United States Geological Survey USCG United States Coast Guard

TABLE 192.3i



§192.9 What requirements apply to gathering lines?


(a) Requirements. An operator of a gathering line must follow the safety requirements of this part as prescribed by this section. (b) Offshore lines. An operator of an offshore gathering line must comply with requirements of this part applicable to transmission lines, except the requirements in §192.150 and in subpart O of this part. (c) Type A lines. An operator of a Type A regulated onshore gathering line must comply with the requirements of this part applicable to transmission lines, except the requirements in §192.150 and in subpart O of this part. However, an operator of a Type A regulated onshore gathering line in a Class 2 location may demonstrate compliance with subpart N by describing the processes it uses to determine the qualification of persons performing operations and maintenance tasks. (d) Type B lines. An operator of a Type B regulated onshore gathering line must comply with the following requirements: (1) If a line is new, replaced, relocated, or otherwise changed, the design, installation, construction, initial inspection, and initial testing must be in accordance with requirements of this part applicable to transmission lines; (2) If the pipeline is metallic, control corrosion according to requirements of subpart I of this part applicable to transmission lines; (3) Carry out a damage prevention program under §192.614; (4) Establish a public education program under §192.616; (5) Establish the MAOP of the line under §192.619; and (6) Install and maintain line markers according to the requirements for transmission lines in §192.707. (7) Conduct leakage surveys in accordance with §192.706 using leak detection equipment and promptly repair hazardous leaks that are discovered in accordance with §192.703(c). (e) Compliance deadlines. An operator of a regulated onshore gathering line must comply with the following deadlines, as applicable. (1) An operator of a new, replaced, relocated, or otherwise changed line must be in compliance with the applicable requirements of this section by the date the line goes into service, unless an exception in §192.13 applies. (2) If a regulated onshore gathering line existing on April 14, 2006 was not previously subject to this part, an operator has until the date stated in the second column to comply with the applicable requirement for the line listed in the first column, unless the Administrator finds a later deadline is justified in a particular case:

Requirement Compliance deadline

Control corrosion according to Subpart I requirements for transmission lines.

April 15, 2009

Carry out a damage prevention program under §192.614.

October 15, 2007

Establish MAOP under §192.619. October 15, 2007 Install and maintain line markers under §192.707. April 15, 2008 Establish a public education program under §192.616

April 15, 2008

Other provisions of this part as required by paragraph (c) of this section for Type A lines.

April 15, 2009



(3) If, after April 14, 2006, a change in class location or increase in dwelling density causes an onshore gathering line to be a regulated onshore gathering line, the operator has 1 year for Type B lines and 2 years for Type A lines after the line becomes a regulated onshore gathering line to comply with this section. [Amdt. 192-72, 59 FR 17275, Apr. 12, 1994 with Amdt. 192-72 Ext., 59 FR 49896, Sept. 30, 1994, Amdt. 192-72 Ext. Correction, 59 FR 52863, Oct. 19, 1994 and Amdt. 192-72 Ext., 60 FR 7133, Feb. 7, 1995; Amdt. 192-95, Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004; Amdt. 192-102, 71 FR 13289, Mar. 15, 2006; Amdt. 192-120, 80 FR 12762, Mar. 11, 2015]

GUIDE MATERIAL

This guide material is under review following Amendment 192-120. See §192.1 for gathering lines excluded from the provisions of Part 192. Also, see the "Glossary of Commonly Used Terms" under §192.3 for definition of "otherwise changed."

§192.10 Outer continental shelf pipelines.


Operators of transportation pipelines on the Outer Continental Shelf (as defined in the Outer Continental Shelf Lands Act (43 U.S.C. 1331) must identify on all their respective pipelines the specific points at which operating responsibility transfers to a producing operator. For those instances in which the transfer points are not identifiable by a durable marking, each operator will have until September 15, 1998 to identify the transfer points. If it is not practicable to durably mark a transfer point and the transfer point is located above water, the operator must depict the transfer point on a schematic located near the transfer point. If a transfer point is located subsea, then the operator must identify the transfer point on a schematic which must be maintained at the nearest upstream facility and provided to PHMSA upon request. For those cases in which adjoining operators have not agreed on a transfer point by September 15, 1998 the Regional Director and the MMS Regional Supervisor will make a joint determination of the transfer point. [Issued by Amdt. 192-81, 62 FR 61692, Nov. 19, 1997 with Amdt. 192-81 Confirmation, 63 FR 12659, Mar. 16, 1998; RIN 2137-AD77, 70 FR 11135, Mar. 8, 2005]

GUIDE MATERIAL


§192.11 Petroleum gas systems.


(a) Each plant that supplies petroleum gas by pipeline to a natural gas distribution system must meet the requirements of this part and NFPA 58 and 59 (incorporated by reference, see §192.7).



(b) Each pipeline system subject to this part that transports only petroleum gas or petroleum gas/air mixtures must meet the requirements of this part and of ANSI/NFPA 58 and 59. (c) In the event of a conflict between this part and NFPA 58 and 59 (incorporated by reference, see §192.7), NFPA 58 and 59 prevail. [Amdt. 192-68, 58 FR 14519, Mar. 18, 1993; Amdt. 192-75, 61 FR 18512, Apr. 26, 1996 with Amdt. 192-75 Correction, 61 FR 38403, July 24, 1996; Amdt. 192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996; Amdt. 192-119, 80 FR 168, Jan. 5, 2015]

GUIDE MATERIAL 1 GENERAL 1.1 Introduction. Personnel involved in the design, construction, operation, and maintenance of petroleum gas systems

should be thoroughly familiar with the applicable provisions of the Federal Regulations and referenced NFPA Standards (see §192.7 for IBR).

Figure 192.11A depicts the standards applicable to petroleum gas plants that supplement natural gas

systems, as described in §192.11(a).

PETROLEUM GAS STORAGE/VAPORIZATION

FACILITIES (USED TO SUPPLEMENT NATURAL

GAS DISTRIBUTION SYSTEM)

STORAGE VESSEL

VAPORIZER

(RE: TITLE 49 CFR PART 192, NFPA 58 AND 59)

Outlet of regulation

NATURAL GAS DISTRIBUTION PIPING SYSTEM

(RE: TITLE 49 CFR PART 192)

District Regulator Station

Customer Meter

CUSTOMER FUEL PIPING

(RE: NFPA 54, (ANSI Z223.1))

Point of Petroleum Gas/Air Injection

Distribution Main

Distribution Service Line

Outlet of meter or connection to customer’s piping, whichever is farther downstream

FIGURE 192.11A


44

Figure 192.11B depicts the standards applicable to pipeline systems for petroleum gas or petroleum gas/air mixtures, as described in §192.11(b).

1.2 Application of referenced codes. (a) General. The referenced NFPA Standards are applicable unless otherwise superseded, in whole or

in part, by local governmental agency codes, rules, or regulations having jurisdiction. (b) Plant and storage facilities. These facilities include storage tanks and all piping and equipment to

the outlet of the first pressure regulator. Utility plant facilities having a total water storage capacity greater than 4,000 gallons are covered by NFPA 59. All other plant and storage installations should comply with NFPA 58.

(c) Distribution piping. This includes the pipeline from the outlet of the first pressure regulator to: (1) The outlet of the customer meter or the connection to the customer's piping, whichever is farther

downstream; or (2) The connection to the customer's piping if there is no customer meter. (d) Customer piping. This includes all piping and facilities downstream of the distribution piping. These

facilities are not included in the scope of 49 CFR 192. NFPA 54/ANSI Z223.1 (National Fuel Gas Code) referenced in Figures 192.11A and 192.11B is applicable unless otherwise superseded by the laws, regulations, or building codes of a local jurisdictional authority.

1.3 Conflict between referenced codes.

If the referenced NFPA Standards are silent or non-specific on a subject for which requirements exist in Part 192, then a conflict does not exist and operators should comply with Part 192 requirements.

1.4 Reference.

Operators of petroleum gas distribution and master meter systems may benefit from information provided in the "Training Guide for Operators of Small LP Gas Systems" (also referred to as "Guidance Manual") available at www.phmsa.dot.gov/pipeline/tq/manuals.

PETROLEUM GAS STORAGE/VAPORIZATION

FACILITIES

STORAGE VESSEL

VAPORIZER


Outlet of 1st cut regulation

PETROLEUM GAS DISTRIBUTION PIPING SYSTEM


Overpressure Protection

Customer Meter

(In some cases, this may not exist, except for the customer meter)

CUSTOMER FUEL PIPING

(RE: NFPA 54, (ANSI Z223.1))

Outlet of meter or connection to customer’s piping, whichever is farther downstream

FIGURE 192.11B

GPTC GUIDE FOR GAS TRANSMISSION, DISTRIBUTION, §192.63 AND GATHERING PIPING SYSTEMS: 2015 Edition SUBPART B


GUIDE MATERIAL

This guide material is under review following Amendment 192-119. (a) The manufacturer marks the pipe and fittings with the maximum temperature at which the pipe and

fittings have been qualified for use. For example: PE 2406/PE 2708 CDC - The first letter following the 4-digit number designates the maximum temperature at which the piping material’s hydrostatic design basis (HDB) has been established and, thus, the maximum temperature at which the pipe can be used. The second letter indicates the HDB for the piping material at that maximum temperature and the third letter is the categorized melt index (actual values are listed in ASTM D2513 - see §192.7 for IBR). The first letter designations from ASTM D2513 are as follows.

A=100 oF B=120 oF C=140 oF D=160 oF E=180 oF Note: The HDB expresses the long-term strength of a thermoplastic material in terms of a series of

standard strength categories (i.e., 1600 psi, 1250 psi, 1000 psi, etc.) which have been established in accordance with ASTM D2837. Specific HDBs can be obtained from the manufacturer and from the Plastics Pipe Institute (PPI).

(b) Thermoplastic pipe manufactured prior to August 16, 1978 may not be marked with the appropriate code

letters for elevated temperature operation. Operators who have installed such pipe should take proper precautions to ensure the pipe is used only within the actual temperature and stress limits for which it was tested and qualified. See §192.123(b)(2).

§192.65 Transportation of pipe.


(a) Railroad. In a pipeline to be operated at a hoop stress of 20 percent or more of SMYS, an operator may not install pipe having an outer diameter to wall thickness of 70 to 1, or more, that is transported by railroad unless the transportation is performed by API RP 5L1 (incorporated by reference, see §192.7). (b) Ship or barge. In a pipeline to be operated at a hoop stress of 20 percent or more of SMYS, an operator may not use pipe having an outer diameter to wall thickness ratio of 70 to 1, or more, that is transported by ship or barge on both inland and marine waterways unless the transportation is performed in accordance with API RP 5LW (incorporated by reference, see §192.7). (c) Truck. In a pipeline to be operated at a hoop stress of 20 percent or more of SMYS, an operator may not use pipe having an outer diameter to wall thickness ratio of 70 to 1, or more, that is transported by truck unless the transportation is performed in accordance with API RP 5LT (incorporated by reference, see § 192.7). [Amdt. 192-12, 38 FR 4760, Feb. 22, 1973; Amdt. 192-17, 40 FR 6345, Feb. 11, 1975 with Amdt. 192-17 Correction, 40 FR 24361, June 6, 1975; Amdt. 192-68, 58 FR 14519, Mar. 18, 1993; Amdt. 192-114, 75 FR 48593, Aug. 11, 2010; Amdt. 192-119, 80 FR 168, Jan. 5, 2015; Amdt. 192-120, 80 FR 12762, Mar. 11, 2015]

GPTC GUIDE FOR GAS TRANSMISSION, DISTRIBUTION, §192.65 AND GATHERING PIPING SYSTEMS: 2015 Edition SUBPART B


GUIDE MATERIAL

This guide material is under review following Amendment 192-119. See Guide Material Appendix G-192-9.

GPTC GUIDE FOR GAS TRANSMISSION, DISTRIBUTION, 192.111 AND GATHERING PIPING SYSTEMS: 2015 Edition SUBPART C


2 DESIGN OF UNCASED PIPELINE CROSSINGS OF HIGHWAYS AND RAILROADS (§192.111(b)(1), (b)(2) and (c)) See Guide Material Appendix G-192-15.

§192.112 Additional design requirements for steel pipe using alternative maximum allowable operating pressure.


For a new or existing pipeline segment to be eligible for operation at the alternative maximum allowable operating pressure (MAOP) calculated under §192.620, a segment must meet the following additional design requirements. Records for alternative MAOP must be maintained, for the useful life of the pipeline, demonstrating compliance with these requirements:


62

To address this design issue: The pipeline segment must meet these additional requirements:

(a) General standards for the steel pipe.

(1) The plate, skelp, or coil used for the pipe must be micro-alloyed, fine grain, fully killed, continuously cast steel with calcium treatment.

(2) The carbon equivalents of the steel used for pipe must not exceed 0.25 percent by weight, as calculated by the Ito-Bessyo formula (Pcm formula) or 0.43 percent by weight, as calculated by the International Institute of Welding (IIW) formula.

(3) The ratio of the specified outside diameter of the pipe to the specified wall thickness must be less than 100. The wall thickness or other mitigative measures must prevent denting and ovality anomalies during construction, strength testing and anticipated operational stresses.

(4) The pipe must be manufactured using API Spec 5L, product specification level 2 (incorporated by reference, see §192.7) for maximum operating pressures and minimum and maximum operating temperatures and other requirements under this section.

(b) Fracture control (1) The toughness properties for pipe must address the potential for initiation, propagation and arrest of fractures in accordance with:

(i) API Spec 5L (incorporated by reference, see §192.7); or (ii) American Society of Mechanical Engineers (ASME)

B31.8 (incorporated by reference, see §192.7); and (iii) Any correction factors needed to address pipe grades,

pressures, temperatures, or gas compositions not expressly addressed in API Spec 5L, product specification level 2 or ASME B31.8 (incorporated by reference, see §192.7).

(2) Fracture control must: (i) Ensure resistance to fracture initiation while addressing

the full range of operating temperatures, pressures, gas compositions, pipe grade and operating stress levels, including maximum pressures and minimum temperatures for shut-in conditions, that the pipeline is expected to experience. If these parameters change during operation of the pipeline such that they are outside the bounds of what was considered in the design evaluation, the evaluation must be reviewed and updated to assure continued resistance to fracture initiation over the operating life of the pipeline;

(ii) Address adjustments to toughness of pipe for each grade used and the decompression behavior of the gas at operating parameters;

(iii) Ensure at least 99 percent probability of fracture arrest within eight pipe lengths with a probability of not less than 90 percent within five pipe lengths; and


63


(b) Fracture control (continued)

(iv) Include fracture toughness testing that is equivalent to that described in supplementary requirements SR5A, SR5B, and SR6 of API Specification 5L (incorporated by reference, see §192.7) and ensures ductile fracture and arrest with the following exceptions:

(A) The results of the Charpy impact test prescribed in SR5A must indicate at least 80 percent minimum shear area for any single test on each heat of steel; and

(B) The results of the drop weight test prescribed in SR6 must indicate 80 percent average shear area with a minimum single test result of 60 percent shear area for any steel test samples. The test results must ensure a ductile fracture and arrest.

(3) If it is not physically possible to achieve the pipeline toughness properties of paragraphs (b)(1) and (2) of this section, additional design features, such as mechanical or composite crack arrestors and/or heavier walled pipe of proper design and spacing, must be used to ensure fracture arrest as described in paragraph (b)(2)(iii) of this section.

(c) Plate/coil quality control (1) There must be an internal quality management program at all mills involved in producing steel, plate, coil, skelp, and/or rolling pipe to be operated at alternative MAOP. These programs must be structured to eliminate or detect defects and inclusions affecting pipe quality.

(2) A mill inspection program or internal quality management program must include (i) and either (ii) or (iii):

(i) An ultrasonic test of the ends and at least 35 percent of the surface of the plate/coil or pipe to identify imperfections that impair serviceability such as laminations, cracks, and inclusions. At least 95 percent of the lengths of pipe manufactured must be tested. For all pipelines designed after December 22, 2008, the test must be done in accordance with ASTM A578/A578M Level B, or API Spec 5L Paragraph 7.8.10 (incorporated by reference, see §192.7) or equivalent method, and either

(ii) A macro etch test or other equivalent method to identify inclusions that may form centerline segregation during the continuous casting process. Use of sulfur prints is not an equivalent method. The test must be carried out on the first or second slab of each sequence graded with an acceptance criteria of one or two on the Mannesmann scale or equivalent; or




(c) Plate/coil quality control (continued)

(iii) A quality assurance monitoring program implemented by the operator that includes audits of: (a) all steelmaking and casting facilities, (b) quality control plans and manufacturing procedure specifications, (c) equipment maintenance and records of conformance, (d) applicable casting superheat and speeds, and (e) centerline segregation monitoring records to ensure mitigation of centerline segregation during the continuous casting process.

(d) Seam quality control (1) There must be a quality assurance program for pipe seam welds to assure tensile strength provided in API Spec 5L (incorporated by reference, see §192.7) for appropriate grades.

(2) There must be a hardness test, using Vickers (Hv10) hardness test method or equivalent test method, to assure a maximum hardness of 280 Vickers of the following:

(i) A cross section of the weld seam of one pipe from each heat plus one pipe from each welding line per day; and

(ii) For each sample cross section, a minimum of 13 readings (three for each heat affected zone, three in the weld metal, and two in each section of pipe base metal).

(3) All of the seams must be ultrasonically tested after cold expansion and mill hydrostatic testing.

(e) Mill hydrostatic test (1) All pipe to be used in a new pipeline segment installed after October 1, 2015, must be hydrostatically tested at the mill at a test pressure corresponding to a hoop stress of 95 percent SMYS for 10 seconds.

(2) Pipe in operation prior to December 22, 2008, must have been hydrostatically tested at the mill at a test pressure corresponding to a hoop stress of 90 percent SMYS for 10 seconds.

(3) Pipe in operation on or after December 22, 2008, but before October 1, 2015, must have been hydrostatically tested at the mill at a test pressure corresponding to a hoop stress of 95 percent SMYS for 10 seconds. The test pressure may include a combination of internal test pressure and the allowance for end loading stresses imposed by the pipe mill hydrostatic testing equipment as allowed by "ANSI/API Spec 5L" (incorporated by reference, see §192.7).

(f) Coating (1) The pipe must be protected against external corrosion by a non-shielding coating.

(2) Coating on pipe used for trenchless installation must be non-shielding and resist abrasions and other damage possible during installation.

(3) A quality assurance inspection and testing program for the coating must cover the surface quality of the bare pipe, surface cleanliness and chlorides, blast cleaning, application temperature control, adhesion, cathodic disbondment, moisture permeation, bending, coating thickness, holiday detection, and repair.


65


(g) Fittings and flanges (1) There must be certification records of flanges, factory induction bends and factory weld ells. Certification must address material properties such as chemistry, minimum yield strength and minimum wall thickness to meet design conditions.

(2) If the carbon equivalents of flanges, bends and ells are greater than 0.42 percent by weight, the qualified welding procedures must include a pre-heat procedure.

(3) Valves, flanges and fittings must be rated based upon the required specification rating class for the alternative MAOP.

(h) Compressor stations (1) A compressor station must be designed to limit the temperature of the nearest downstream segment operating at alternative MAOP to a maximum of 120 degrees Fahrenheit (49 degrees Celsius) or the higher temperature allowed in paragraph (h)(2) of this section unless a long-term coating integrity monitoring program is implemented in accordance with paragraph (h)(3) of this section.

(2) If research, testing and field monitoring tests demonstrate that the coating type being used will withstand a higher temperature in long-term operations, the compressor station may be designed to limit downstream piping to that higher temperature. Test results and acceptance criteria addressing coating adhesion, cathodic disbondment, and coating condition must be provided to each PHMSA pipeline safety regional office where the pipeline is in service at least 60 days prior to operating above 120 degrees Fahrenheit (49 degrees Celsius). An operator must also notify a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State.

(3) Pipeline segments operating at alternative MAOP may operate at temperatures above 120 degrees Fahrenheit (49 degrees Celsius) if the operator implements a long-term coating integrity monitoring program. The monitoring program must include examinations using direct current voltage gradient (DCVG), alternating current voltage gradient (ACVG), or an equivalent method of monitoring coating integrity. An operator must specify the periodicity at which these examinations occur and criteria for repairing identified indications. An operator must submit its long-term coating integrity monitoring program to each PHMSA pipeline safety regional office in which the pipeline is located for review before the pipeline segments may be operated at temperatures in excess of 120 degrees Fahrenheit (49 degrees Celsius). An operator must also notify a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State.



[Issued by RIN 2137-AE25, 73 FR 62148, Oct. 17, 2008; Eff. date stayed by 73 FR 72737, Dec. 1, 2008; Amdt. 192-111, 74 FR 62503, Nov. 30, 2009; Amdt. 192-119, 80 FR 168, Jan. 5, 2015; Amdt. 192-120, 80 FR 12762, Mar. 11, 2015]

Guide Material


§192.113 Longitudinal joint factor (E) for steel pipe.


The longitudinal joint factor to be used in the design formula in §192.105 is determined in accordance with the following table:

Specification

Pipe Class

Longitudinal Joint Factor (E)

ASTM A 53/A53M ASTM A 106 ASTM A 333/A 333M ASTM A 381 ASTM A 671

Seamless Electric resistance welded Furnace butt welded Seamless Seamless Electric resistance welded Double submerged arc welded Electric-fusion-welded

1.00 1.00 0.60 1.00 1.00 1.00 1.00 1.00

ASTM A 672 ASTM A 691 API Spec 5L Other Other

Electric-fusion-welded Electric-fusion-welded Seamless Electric resistance welded Electric flash welded Submerged arc welded Furnace butt welded Pipe over 4 inches (102 millimeters) Pipe 4 inches (102 millimeters) or less

1.00 1.00 1.00 1.00 1.00 1.00 0.60 0.80 0.60

If the type of longitudinal joint cannot be determined, the joint factor to be used must not exceed that designated for "Other". [Amdt. 192-37, 46 FR 10157, Feb. 2, 1981; Amdt. 192-51, 51 FR 15333, Apr. 23, 1986; Amdt. 192-62, 54 FR 5625, Feb. 6, 1989; Amdt. 192-68, 58 FR 14519, Mar. 18, 1993; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-94, 69 FR 32886, June 14, 2004; Amdt. 192-119, 80 FR 168, Jan. 5, 2015]

GUIDE MATERIAL Manufacture of furnace lap-welded pipe was discontinued and process deleted from API Spec 5L in 1962.


67

§192.115 Temperature derating factor (T) for steel pipe.


The temperature derating factor to be used in the design formula in §192.105 is determined as follows:

Gas temperature in degrees

Fahrenheit (Celsius)

Temperature derating

factor ( T )

250 oF (121 oC) or less 300 oF (149 oC) 350 oF (177 oC) 400 oF (204 oC) 450 oF (232 oC)

1.000 0.967 0.933 0.900 0.867

For intermediate gas temperatures, the derating factor is determined by interpolation. [Amdt. 192-85, 63 FR 37500, July 13, 1998]

GUIDE MATERIAL


§192.117 (Removed and reserved.)


§192.119 (Removed and reserved.)


§192.121 Design of plastic pipe.


Subject to the limitations of §192.123, the design pressure for plastic pipe is determined by either of the following formulas: P = 2S t (DF) (D-t)



P = 2S (DF) (SDR-1) Where: P = Design pressure, gauge, psig (kPa).

S = For thermoplastic pipe, the HDB is determined in accordance with the listed specification at a temperature equal to 73 oF (23 oC), 100 oF (38 oC), 120 oF (49 oC), or 140 oF (60 oC). In the absence of an HDB established at the specified temperature, the HDB of a higher temperature may be used in determining a design pressure rating at the specified temperature by arithmetic interpolation using the procedure in Part D.2 of PPI TR-3/2008, HDB/PDB/SDB/MRS Policies (incorporated by reference, see §192.7). For reinforced thermosetting plastic pipe, 11,000 psig (75,842 kPa). [Note: Arithmetic interpolation is not allowed for PA-11 pipe.]

t = Specified wall thickness, inches (mm). D = Specified outside diameter, inches (mm). SDR = Standard dimension ratio, the ratio of the average specified outside diameter to the

minimum specified wall thickness, corresponding to a value from a common numbering system that was derived from the American National Standards Institute preferred number series 10.

DF = 0.32 or = 0.40 for PA-11 pipe produced after January 23, 2009 with a nominal pipe size (IPS or CTS)

4-inch or less, and a SDR of 11 or greater (i.e., thicker pipe wall). [Amdt. 192-31, 43 FR 13880, Apr. 3, 1978 with Amdt. 192-31 Correction, 43 FR 43308, Sept. 25, 1978; Amdt. 192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-94, 69 FR 32886, June 14, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006; RIN 2137-AE26, 73 FR 79002, Dec. 24, 2008; Amdt. 192-111, 74 FR 62503, Nov. 30, 2009; Amdt. 192-114, 75 FR 48593, Aug. 11, 2010]

GUIDE MATERIAL

1 NATURAL GAS

(a) Hydrostatic Design Basis (HDB) values are awarded by the Hydrostatic Stress Board (HSB) of the Plastics Pipe Institute (PPI) and are listed in PPI TR-4, which can be accessed at:

www.plasticpipe.org (b) ASTM D2513 (see §192.7 for IBR) requires elevated temperature HDB listings for plastic piping

materials used at temperatures above 73 °F. PPI publishes elevated temperature HDB values for PE and PA materials in TR-4.

(c) Long-term hydrostatic strength (LTHS) for reinforced thermosetting plastic covered by ASTM D2517 (see §192.7 for IBR) is 11,000 psi.

(d) HDB values apply only to materials meeting all the requirements of ASTM D2513 and are based on engineering test data analyzed in accordance with ASTM D2837, "Standard Test Method for Obtaining Hydrostatic Design Basis for Thermoplastic Pipe Materials or Pressure Design Basis for Thermoplastic Pipe Products."

(e) HDB values at 73 °F for thermoplastic materials covered by ASTM D2513 are listed in Table 192.121i. The values used in the design formula for thermoplastic materials are actually HDB values that are a categorized value of the long-term hydrostatic strength.

GPTC GUIDE FOR GAS TRANSMISSION, DISTRIBUTION, §192.151 AND GATHERING PIPING SYSTEMS: 2015 Edition SUBPART D


3 SIZE LIMITATIONS 3.1 Large-diameter taps. Large-diameter taps using mechanical fittings can reduce the remaining circumferential area below that

required to withstand anticipated longitudinal forces due to pressure, bending, and thermal effects. The operator should anticipate and design for complete circumferential cracking. The operator should confirm that the longitudinal pullout resistance of the fitting is adequate, or provide appropriate restraint, such as a mechanical harness, strapping, or girth (fillet) end welds. For welds, see guide material under §192.713.

3.2 Oversize taps. When an oversize tap (i.e., greater than 25% of the nominal diameter) into cast iron or ductile-iron pipe

is made through a band-type fitting, it is common practice to use a full-encirclement gasket for leak containment in the event of a circumferential crack.

4 SEPARATION To resist longitudinal cracks between taps, taps into cast iron or ductile-iron pipe should be separated

longitudinally by at least the circumference of the pipe being tapped. 5 OTHER See guide material under §192.627 for personnel qualifications, identification of pipe to be tapped, and

suitability for tapping. See §192.627 for tapping pipelines under pressure.

§192.153 Components fabricated by welding.


(a) Except for branch connections and assemblies of standard pipe and fittings joined by circumferential welds, the design pressure of each component fabricated by welding, whose strength cannot be determined, must be established in accordance with paragraph UG-101 of the ASME Boiler and Pressure Vessel Code (BPVC) (Section VIII, Division 1) (incorporated by reference, see §192.7). (b) Each prefabricated unit that uses plate and longitudinal seams must be designed, constructed, and tested in accordance with section 1 of the ASME BPVC (Section VIII, Division 1 or Section VIII, Division 2) (incorporated by reference, see §192.7), except for the following: (1) Regularly manufactured butt-welding fittings. (2) Pipe that has been produced and tested under a specification listed in Appendix B to this part. (3) Partial assemblies such as split rings or collars. (4) Prefabricated units that the manufacturer certifies have been tested to at least twice the maximum pressure to which they will be subjected under the anticipated operating conditions. (c) Orange-peel bull plugs and orange-peel swages may not be used in pipelines that are to operate at a hoop stress of 20 percent or more of the SMYS of the pipe. (d) Except for flat closures designed in accordance with the ASME BPVC (Section VIII, Division 1 or 2), flat closures and fish tails may not be used on pipe that either operates at 100 p.s.i. (689 kPa) gage or more, or is more than 3 inches in (76 millimeters) nominal diameter. (e) A component having a design pressure established in accordance with paragraph (a) or paragraph (b) of this section and subject to the strength testing requirements of §192.505(b) must be tested to at least 1.5 times the MAOP.



[Amdt. 192-3, 35 FR 17659, Nov. 17, 1970; Amdt. 192-68, 58 FR 14519, Mar. 18, 1993 with Amdt. 192-68 Correction, 58 FR 45268, Aug. 27, 1993; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-119, 80 FR 168, Jan. 5, 2015; Amdt. 192-120, 80 FR 12762, Mar. 11, 2015]

GUIDE MATERIAL

Currently under review following Amendment 192-120; previously "No guide material necessary."

§192.155 Welded branch connections.


Each welded branch connection made to pipe in the form of a single connection, or in a header or manifold as a series of connections, must be designed to ensure that the strength of the pipeline system is not reduced, taking into account the stresses in the remaining pipe wall due to the opening in the pipe or header, the shear stresses produced by the pressure acting on the area of the branch opening, and any external loadings due to thermal movement, weight, and vibration.

GUIDE MATERIAL REINFORCEMENT OF WELDED BRANCH CONNECTIONS 1 GENERAL CONSIDERATIONS The following paragraphs provide design recommendations for the usual combinations of loads,

exclusive of excessive external loads. 1.1 Reinforcement rule. The reinforcement in the crotch section of a welded branch connection should be determined by the rule

that the metal area available for reinforcement be equal to or greater than the recommended area defined in 1.2 below as well as in Figure 192.155A in Guide Material Appendix G-192-4.

1.2 Recommended cross-sectional area. The recommended cross-sectional area AR is defined as the product of d times t: AR = d x t Where: d = Length of the finished opening in the header wall measured parallel to the axis of the run. t = Nominal header wall thickness as specified in §192.105. When the pipe wall thickness

includes an allowance for corrosion or erosion, all dimensions used should be those that will result after the anticipated corrosion or erosion has taken place.

1.3 Area available for reinforcement. The area available for reinforcement should be the sum of: (a) The cross-sectional area resulting from any excess thickness available in the header thickness

(over the minimum recommended for the header as defined in 1.2 above) and which lies within the reinforcement area as defined in 1.4 below.

(b) The cross-sectional area resulting from any excess thickness available in the branch wall thickness (over the minimum thickness recommended for the branch and which lies within the reinforcement areas as defined in 1.4 below).



§192.165 Compressor stations: Liquid removal.


(a) Where entrained vapors in gas may liquefy under the anticipated pressure and temperature conditions, the compressor must be protected against the introduction of those liquids in quantities that could cause damage. (b) Each liquid separator used to remove entrained liquids at a compressor station must — (1) Have a manually operable means of removing these liquids. (2) Where slugs of liquid could be carried into the compressors, have either automatic liquid removal facilities, an automatic compressor shutdown device, or a high liquid level alarm; and (3) Be manufactured in accordance with section VIII ASME Boiler and Pressure Vessel Code (BPVC) (incorporated by reference, see §192.7) and the additional requirements of §192.153(e) except that liquid separators constructed of pipe and fittings without internal welding must be fabricated with a design factor of 0.4, or less. [Amdt. 192-119, 80 FR 168, Jan. 5, 2015; Amdt. 192-120, 80 FR 12762, Mar. 11, 2015]

GUIDE MATERIAL

This guide material is under review following Amendment 192-120. (a) Liquid separators that are installed in compressor station piping to protect the compressor from the

introduction of liquid in quantities that could cause damage should be designed in accordance with §192.165(b)(1), (2) and (3).

(b) When liquid removal facilities (e.g., pigging receiver tanks, slug catchers, drips and sumps) are installed

in the pipeline outside the compressor station piping, they should be designed as fabricated assemblies rather than as part of the station piping.

§192.167 Compressor stations: Emergency shutdown.


(a) Except for unattended field compressor stations of 1,000 horsepower (746 kilowatts) or less, each compressor station must have an emergency shutdown system that meets the following: (1) It must be able to block gas out of the station and blow down the station piping. (2) It must discharge gas from the blowdown piping at a location where the gas will not create a hazard. (3) It must provide means for the shutdown of gas compression equipment, gas fires, and electrical facilities in the vicinity of gas headers and in the compressor building, except, that— (i) Electrical circuits that supply emergency lighting required to assist station personnel in evacuating the compressor building and the area in the vicinity of the gas headers must remain energized; and (ii) Electrical circuits needed to protect equipment from damage may remain energized. (4) It must be operable from at least two locations, each of which is— (i) Outside the gas area of the station;



(ii) Near the exit gates, if the station is fenced, or near emergency exits, if not fenced; and (iii) Not more than 500 feet (153 meters) from the limits of the station. (b) If a compressor station supplies gas directly to a distribution system with no other adequate source of gas available, the emergency shutdown system must be designed so that it will not function at the wrong time and cause an unintended outage on the distribution system. (c) On a platform located offshore or in inland navigable waters, the emergency shutdown system must be designed and installed to actuate automatically by each of the following events: (1) In the case of an unattended compressor station— (i) When the gas pressure equals the maximum allowable operating pressure plus 15 percent; or (ii) When an uncontrolled fire occurs on the platform; and (2) In the case of a compressor station in a building— (i) When an uncontrolled fire occurs in the building; or (ii) When the concentration of gas in air reaches 50 percent or more of the lower explosive limit in a building which has a source of ignition. For the purpose of paragraph (c)(2)(ii) of this section, an electrical facility that conforms to Class 1, Group D of the National Electrical Code is not a source of ignition. [Amdt. 192-27, 41 FR 34598, Aug. 16, 1976; Amdt. 192-85, 63 FR 37500, July 13, 1998]

GUIDE MATERIAL (a) All emergency valves and controls should be identified by signs. All important gas pressure piping

should be identified as to functions by signs or color codes. (b) For blowdown considerations, see guide material under §§192.161 and 192.179.

§192.169 Compressor stations: Pressure limiting devices.


(a) Each compressor station must have pressure relief or other suitable protective devices of sufficient capacity and sensitivity to ensure that the maximum allowable operating pressure of the station piping and equipment is not exceeded by more than 10 percent. (b) Each vent line that exhausts gas from the pressure relief valves of a compressor station must extend to a location where the gas may be discharged without hazard.

GUIDE MATERIAL An adequate relief device or automatic compressor shutdown device should be installed in the discharge line of each compressor between the gas compressor and the first discharge block valve. The relieving capacity of the relief device should be equal to or greater than the capacity of the compressor. If the relief devices on the compressor do not prevent the possibility of overpressuring the piping, as specified in §192.169(a), additional relieving device(s) should be installed on the piping to prevent it from being overpressured.

GPTC GUIDE FOR GAS TRANSMISSION, DISTRIBUTION, §192.221 AND GATHERING PIPING SYSTEMS: 2015 Edition Subpart E


SUBPART E WELDING OF STEEL IN PIPELINES

§192.221 Scope.


(a) This subpart prescribes minimum requirements for welding steel materials in pipelines. (b) This subpart does not apply to welding that occurs during the manufacture of steel pipe or steel pipeline components.

GUIDE MATERIAL Welding terms used in this Guide generally conform to the standard definitions established by the American Welding Society and contained in AWS Publication A3.0 "Standard Welding Terms and Definitions." See definition of "Pipe Manufacturing Processes" in the guide material under §192.3 for exceptions.

§192.223 (Removed.)


§192.225 Welding procedures.


(a) Welding must be performed by a qualified welder or welding operator in accordance with welding procedures qualified under section 5, section 12, or Appendix A of API Std 1104 (incorporated by reference, see §192.7) or section IX ASME Boiler and Pressure Vessel Code (BPVC) (incorporated by reference, see §192.7), to produce welds which meet the requirements of this subpart. The quality of the test welds used to qualify welding procedures must be determined by destructive testing in accordance with the referenced welding standard(s). (b) Each welding procedure must be recorded in detail, including the results of the qualifying tests. This record must be retained and followed whenever the procedure is used. [Amdt. 192-18, 40 FR 10181, Mar. 5, 1975; Amdt. 192-22, 41 FR 13589, Mar. 31, 1976; Amdt. 192-37, 46 FR 10157, Feb. 2, 1981; Amdt. 192-52, 51 FR 20294, June 4, 1986; Amdt. 192-94, 69 FR 32886, June 14, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006; Amdt. 192-119, 80 FR 168, Jan. 5, 2015; Amdt. 192-120, 80 FR 12762, Mar. 11, 2015]

GUIDE MATERIAL (a) Additional references for welding procedures include the following. (1) ASME B31.8, "Gas Transmission and Distribution Piping Systems." (2) API Std 1104, "Welding of Pipelines and Related Facilities," Appendix B, "In-Service Welding" (see

§192.7 for IBR).



(b) Information on preheating and stress relieving of welded connections can be found in the above references. Preheating and stress relieving should be performed in accordance with the qualified welding procedure being used.

§192.227 Qualification of welders.


(a) Except as provided in paragraph (b) of this section, each welder or welding operator must be qualified in accordance with section 6, section 12, or Appendix A of API Std 1104 (incorporated by reference, see §192.7), or section IX of ASME Boiler and Pressure Vessel Code (BPVC) (incorporated by reference, see §192.7). However, a welder or welding operator qualified under an earlier edition than the edition listed in §192.7 may weld but may not re-qualify under that earlier edition. (b) A welder may qualify to perform welding on pipe to be operated at a pressure that produces a hoop stress of less than 20 percent of SMYS by performing an acceptable test weld, for the process to be used, under the test set forth in section I of Appendix C of this part. Each welder who is to make a welded service line connection to a main must first perform an acceptable test weld under section II of Appendix C of this part as a requirement of the qualifying test. [Amdt. 192-18, 40 FR 10181, Mar. 5, 1975 with Amdt. 192-18A, 40 FR 27222, June 27, 1975; Amdt. 192-22, 41 FR 13589, Mar. 31, 1976; Amdt. 192-37, 46 FR 10157, Feb. 2, 1981; Amdt. 192-43, 47 FR 46850, Oct. 21, 1982; Amdt. 192-52, 51 FR 20294, June 4, 1986; Amdt. 192-75, 61 FR 18512, Apr. 26, 1996 with Amdt. 192-75 Correction, 61 FR 38403, July 24, 1996; Amdt. 192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996; Amdt. 192-94, 69 FR 32886, June 14, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006; Amdt. 192-103, 72 FR 4655, Feb. 1, 2007; Amdt. 192-119, 80 FR 168, Jan. 5, 2015; Amdt. 192-120, 80 FR 12762, Mar. 11, 2015]

GUIDE MATERIAL

This guide material is under review following Amendment 192-120. It is the operator's responsibility to ensure that all welding is performed by qualified welders. The ability of welders to make sound welds should be determined by test welds using previously qualified welding procedures. The evaluation of test welds may be conducted by qualified operator personnel or testing laboratories.

§192.229 Limitations on welders.


(a) No welder or welding operator whose qualification is based on nondestructive testing may weld compressor station pipe and components. (b) A welder or welding operator may not weld with a particular welding process unless, within the preceding 6 calendar months, the welder or welding operator was engaged in welding with that process. (c) A welder or welding operator qualified under §192.227(a)— (1) May not weld on pipe to be operated at a pressure that produces a hoop stress of 20 percent or more of SMYS unless within the preceding 6 calendar months the welder or welding operator has had one weld tested and found acceptable under either section 6, section 9, section 12



or Appendix A of API Std 1104 (incorporated by reference, see §192.7). Alternatively, welders or welding operators may maintain an ongoing qualification status by performing welds tested and found acceptable under the above acceptance criteria at least twice each calendar year, but at intervals not exceeding 71⁄2 months. A welder or welding operator qualified under an earlier edition of a standard listed in §192.7 of this part may weld, but may not re-qualify under that earlier edition; and, (2) May not weld on pipe to be operated at a pressure that produces a hoop stress of less than 20 percent of SMYS unless the welder or welding operator is tested in accordance with paragraph (c)(1) of this section or re-qualifies under paragraph (d)(1) or (d)(2) of this section. (d) A welder or welding operator qualified under §192.227(b) may not weld unless— (1) Within the preceding 15 calendar months, but at least once each calendar year, the welder or welding operator has re-qualified under §192.227(b); or (2) Within the preceding 71⁄2 calendar months, but at least twice each calendar year, the welder or welding operator has had— (i) A production weld cut out, tested, and found acceptable in accordance with the qualifying test; or (ii) For a welder who works only on service lines 2 inches (51 millimeters) or smaller in diameter, the welder has had two sample welds tested and found acceptable in accordance with the test in section III of Appendix C of this part. [Amdt. 192-18, 40 FR 10181, Mar. 5, 1975 with Amdt. 192-18A, 40 FR 27222, June 27, 1975; Amdt. 192-37, 46 FR 10157, Feb. 2, 1981; Amdt. 192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-94, 69 FR 32886, June 14, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006; Amdt. 192-119, 80 FR 168, Jan. 5, 2015; Amdt. 192-120, 80 FR 12762, Mar. 11, 2015]

GUIDE MATERIAL

This guide material is under review following Amendment 192-120. A welding "process" is one element of a welding "procedure." Processes commonly used in pipeline welding procedures include the following: (a) Shielded metal-arc. (b) Submerged arc. (c) Gas tungsten-arc. (d) Gas metal-arc. (e) Flux-cored arc. (f) Oxyacetylene. (g) Flash.

§192.231 Protection from weather.


The welding operation must be protected from weather conditions that would impair the quality of the completed weld.

GUIDE MATERIAL



122

§192.233 Miter joints.


(a) A miter joint on steel pipe to be operated at a pressure that produces a hoop stress of 30 percent or more of SMYS may not deflect the pipe more than 3 degrees. (b) A miter joint on steel pipe to be operated at a pressure that produces a hoop stress of less than 30 percent, but more than 10 percent, of SMYS may not deflect the pipe more than 12½ degrees and must be a distance equal to one pipe diameter or more away from any other miter joint, as measured from the crotch of each joint. (c) A miter joint on steel pipe to be operated at a pressure that produces a hoop stress of 10 percent or less of SMYS may not deflect the pipe more than 90 degrees.

GUIDE MATERIAL


§192.235 Preparation for welding.


Before beginning any welding, the welding surfaces must be clean and free of any material that may be detrimental to the weld, and the pipe or component must be aligned to provide the most favorable condition for depositing the root bead. This alignment must be preserved while the root bead is being deposited.

GUIDE MATERIAL 1 BUTT WELDS (a) Proper alignment of pipe ends must be achieved prior to and maintained during position or roll

welding. (§192.235) (b) Spacing between abutting pipe ends should not exceed the limits specified in the welding procedure

used to make the weld. (c) Alignment of pipe ends should minimize the offset between their surfaces. Any offsets should be

uniformly distributed around the circumference of the pipe ends and be within the permissible tolerances for those pipe segments.

(d) Proper care should be exercised during alignment to ensure that pipe joints are not placed under stress. Hammering of pipe ends to achieve alignment should be minimized.

(e) The following may be used singularly or in combination, if needed, to ensure proper pipe alignment while the root bead is being deposited.

(1) Internal or external alignment clamps. (2) Jack stands. (3) Spirit levels and squares. (4) Jigs. (5) Spacers (e.g., backing rings / "chill rings"). (6) Cranes, hoists, or skids.



(7) Tack welds. (f) The following problems may be caused by failure to achieve and maintain proper pipe alignment

during welding. (1) Excessive width of the root opening. (2) High-low misalignment. (3) Inadequate joint penetration of the root bead. (g) Some acceptable end preparations are shown in Figures 192.235A and 192.235B of Guide Material

Appendix G-192-5. 2 FILLET WELDS Minimum dimensions for fillet welds used in the attachment of slip-on flanges and for socket-welded

joints are shown in Figure 192.235C of Guide Material Appendix G-192-5. Similar minimum dimensions for fillet welds used in branch connections are shown in Figures 192.155B and 192.155C of Guide Material Appendix G-192-4.

3 SEAL WELDS Where threaded joints are seal-welded, the weld should not be considered as contributing to the

strength of the joint. 4 MITER WELDS In making mitered joints, care should be taken to ensure proper groove spacing, alignment, and full

penetration. In cutting miter joints, the cutting torch should be held so that the entire cut surface is in the same plane. The miter cut should be followed by a beveling cut, leaving 1/32 inch to 1/16 inch of shoulder at the inner wall. The included angle of the resultant welding groove should be at least 60 degrees.

§192.237 (Removed.)


§192.239 (Removed.)


§192.241 Inspection and test of welds.


(a) Visual inspection of welding must be conducted by an individual qualified by appropriate training and experience to ensure that: (1) The welding is performed in accordance with the welding procedure; and (2) The weld is acceptable under paragraph (c) of this section.



(b) The welds on a pipeline to be operated at a pressure that produces a hoop stress of 20 percent or more of SMYS must be nondestructively tested in accordance with §192.243, except that welds that are visually inspected and approved by a qualified welding inspector need not be nondestructively tested if — (1) The pipe has a nominal diameter of less than 6 inches (152 millimeters); or (2) The pipeline is to be operated at a pressure that produces a hoop stress of less than 40 percent of SMYS and the welds are so limited in number that nondestructive testing is impractical. (c) The acceptability of a weld that is nondestructively tested or visually inspected is determined according to the standards in section 9 or Appendix A of API Std 1104 (incorporated by reference, see §192.7). Appendix A of API Std 1104 may not be used to accept cracks. [Amdt. 192-18, 40 FR 10181, Mar. 5, 1975 with Amdt. 192-18A, 40 FR 27222, June 27, 1975; Amdt. 192-37, 46 FR 10157, Feb. 2, 1981; Amdt. 192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-94, 69 FR 32886, June 14, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006; Amdt. 192-119, 80 FR 168, Jan. 5, 2015; Amdt. 192-120, 80 FR 12762, Mar. 11, 2015]

GUIDE MATERIAL

This guide material is under review following Amendment 192-120. 1 VISUAL WELDING INSPECTION The inspection measures listed below should be performed as applicable before, during, and after the

welding process to ensure good quality workmanship for every weld made. Consideration should be given to nondestructively testing, repairing, or cutting out any weld with questionable acceptability under Section 9 of API Std 1104 (see §192.7 for IBR).

(a) Before welding: (1) Inspect the weld joint geometry and verify the fit-up for proper alignment. (2) Inspect surfaces to be welded for cleanliness. (3) Verify any temperature requirements for pre-heat, interpass, and post-heat treatments. (4) If applicable, ensure that pre-heat treatment has been properly applied. (b) During welding: (1) Visually inspect the stringer (initial or root pass) bead before subsequent beads are applied.

Each bead inspected should be examined for defects that may make the weld unacceptable, such as the following.

(i) Incomplete fusion. (ii) Slag inclusion. (iii) Porosity. (iv) Cracks. (v) Undercutting. (vi) Bead concavity. (2) Verify the following. (i) Interpass cleanliness. (ii) Temperature requirements. (iii) Weld speed. (iv) Time limits between passes. (c) After welding: (1) Inspect the configuration and dimensions of the completed weld for acceptability under the

welding specification. (2) If applicable, ensure that post-heat treatment has been properly applied.



2 INSPECTOR QUALIFICATIONS (a) An operator’s welding procedures should specify the personnel who may perform visual inspection

of welding, as well as the level of training and experience needed. Visual inspection may be performed by one or more of the following.

(1) The qualified person making the weld. (2) An additional qualified welder. (3) A Certified Welding Inspector (CWI). (4) A qualified person who is neither a welder nor a CWI. (b) Visual inspection may be performed by either qualified operator personnel or qualified contract

personnel. (c) In determining whether an individual has appropriate training and experience, consideration should

be given to the following. (1) Welding education or an individual’s qualification examination results, if any. (2) Knowledge of applicable welding processes. (d) The documentation of inspector qualifications should be retained.

§192.243 Nondestructive testing.


(a) Nondestructive testing of welds must be performed by any process, other than trepanning, that will clearly indicate defects that may affect the integrity of the weld. (b) Nondestructive testing of welds must be performed — (1) In accordance with written procedures; and

(2) By persons who have been trained and qualified in the established procedures and with the equipment employed in testing. (c) Procedures must be established for the proper interpretation of each nondestructive test of a weld to ensure the acceptability of the weld under §192.241(c). (d) When nondestructive testing is required under §192.241(b), the following percentages of each day's field butt welds, selected at random by the operator, must be nondestructively tested over their entire circumference: (1) In Class 1 locations, except offshore, at least 10 percent. (2) In Class 2 locations, at least 15 percent. (3) In Class 3 and Class 4 locations, at crossing of major or navigable rivers, offshore, and within railroad or public highway rights-of way, including tunnels, bridges, and overhead road crossings, 100 percent unless impracticable, in which case at least 90 percent. Nondestructive testing must be impracticable for each girth weld not tested. (4) At pipeline tie-ins, including tie-ins of replacement sections, 100 percent. (e) Except for a welder or welding operator whose work is isolated from the principal welding activity, a sample of each welder or welding operator's work for each day must be nondestructively tested, when nondestructive testing is required under §192.241(b). (f) When nondestructive testing is required under §192.241(b), each operator must retain, for the life of the pipeline, a record showing by milepost, engineering station, or by geographic feature, the number of girth welds made, the number nondestructively tested, the number rejected, and the disposition of the rejects. [Amdt. 192-27, 41 FR 34598, Aug. 16, 1976; Amdt. 192-50, 50 FR 37192, Sept. 12, 1985; Amdt. 192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996; Amdt. 192-120, 80 FR 12762, Mar. 11, 2015]


126

GUIDE MATERIAL 1 METHODS (§192.243(a)) The most prevalent methods for through-the-wall inspection are radiography and ultrasonics. For

surface examination, dye penetrant or magnetic particle inspections are useful. 2 RECORDS (§192.243(f)) The required written records that are to be retained for the life of any pipeline may be in any form that

documents all the required information. It is recognized that the process of obtaining and storing permanent visual records of nondestructive testing results is impractical, not feasible, or both.

§192.245 Repair or removal of defects.


(a) Each weld that is unacceptable under §192.241(c) must be removed or repaired. Except for welds on an offshore pipeline being installed from a pipeline vessel, a weld must be removed if it has a crack that is more than 8 percent of the weld length. (b) Each weld that is repaired must have the defect removed down to sound metal and the segment to be repaired must be preheated if conditions exist which would adversely effect the quality of the weld repair. After repair, the segment of the weld that was repaired must be inspected to ensure its acceptability. (c) Repair of a crack, or of any defect in a previously repaired area must be in accordance with written weld repair procedures that have been qualified under §192.225. Repair procedures must provide that the minimum mechanical properties specified for the welding procedure used to make the original weld are met upon completion of the final weld repair. [Amdt. 192-27, 41 FR 34598, Aug. 16, 1976; Amdt. 192-46, 48 FR 48669, Oct. 20, 1983]

GUIDE MATERIAL

References for repair include the following sections of API Std 1104, "Welding of Pipelines and Related Facilities" (see §192.7). (a) Section 10, "Repair and Removal of Defects." (b) Section B.7, "Repair and Removal of Defects" in Appendix B, "In-Service Welding."

GPTC GUIDE FOR GAS TRANSMISSION, DISTRIBUTION, §192.283 AND GATHERING PIPING SYSTEMS: 2015 Edition SUBPART F

137

2 PROCEDURE QUALIFICATION (Plastic-to-plastic and plastic-to-metal) 2.1 Procedure and qualification for joints and permanent repairs. (Plastic-to-plastic and plastic-to-metal) (a) Solvent cement, heat fusion, and adhesive. (Plastic-to-plastic) (1) Procedure. A separate procedure should be established for each plastic compound and for

each method of joining. The procedure specification should include at least the following. (i) Plastic compound or compounds. (ii) Joint design. (iii) Size and thickness range. (iv) Method of joining. (v) Curing or set-up time. (vi) Temperature limits. (vii) Temperature of the heating tool. (viii) Proper end finishing. (ix) Tools and equipment. (x) Joining or repair technique. See 3 of the guide material under §192.281. (2) Qualification. The procedure specification should be considered qualified if test assemblies of

joints or repairs made in accordance with the procedure specification meet the requirements of 2.2 below. The test assemblies should be cured, set, or hardened in accordance with the manufacturer's recommendations.

(b) Mechanical. (Plastic-to-plastic and plastic-to-metal) (1) Procedure. A separate procedure should be established for each kind and type of mechanical

fitting to be used for making a joint or repair. It should include at least the following. (i) Kind and type of plastic material(s). (ii) Other piping elements to be joined to the plastic. (iii) Joint design. (iv) Size and thickness range. (v) Type of mechanical fitting. (vi) Tools and equipment. (vii) Joining and repair procedure. (2) Qualification. To qualify the procedure specification, test assemblies of joints or repairs should

be made in accordance with the procedure specifications and tested in accordance with 2.2 below. The test assemblies may be restrained to the same extent that they would be in service. These assemblies should be sectioned or dismantled to inspect for damage to the plastic pipe. The procedure should be rejected if there is evidence of damage that would reduce the service life of an installed joint or repair.

(3) Other considerations. See 3.5 of the guide material under §192.281. 2.2 Test requirements. (Plastic-to-plastic and plastic-to-metal) Test assemblies should successfully meet the following requirements. (a) Leak test. An assembly should not leak when subjected to a stand-up pressure test with air or gas. (b) Short-term burst test. An assembly should meet the minimum burst requirements of ASTM D2513

or ASTM D2517, whichever is applicable (see §192.7 for both), for the specific kind and size of plastic pipe used in the assembly.

(c) Sustained-pressure test. An assembly should not fail when subjected to a sustained pressure test, such as the 1000 hr test described in ASTM D2513 or ASTM D2517 (whichever is applicable), for the specific kind and size of plastic pipe used in the assembly.

(d) Inspection. An assembly should be subjected to suitable nondestructive or destructive inspection to determine if the bonded area is substantially equivalent to the intended bond area.



3 UNLIKE PE COMPONENT QUALIFICATION PE components made of different compounds and different grades of materials may be heat-fused,

provided that properly qualified procedures for joining the specific compounds are used. Any combination of PE 2306, PE 2406/PE 2708, PE 3306, PE 3406, and PE 3408/PE 4710 may be joined by heat fusion using qualified procedures for specific materials. Operators attempting to qualify such procedures may be able to obtain qualified procedures from pipe manufacturers. (See guide material under §192.281 for PE heat fusion.) Additionally, the following references may be of assistance.

(a) PPI TN-13, "General Guidelines for Butt, Saddle and Socket Fusion of Unlike Polyethylene Pipes and Fittings."

(b) PPI TR-33, "Generic Butt Fusion Joining Procedure for Field Joining of Polyethylene Pipe." (c) PPI TR-41, "Generic Saddle Fusion Joining Procedure for Polyethylene Gas Piping."

§192.285 Plastic pipe: Qualifying persons to make joints.


(a) No person may make a plastic pipe joint unless that person has been qualified under the applicable joining procedure by — (1) Appropriate training or experience in the use of the procedure; and (2) Making a specimen joint from pipe sections joined according to the procedure that passes the inspection and test set forth in paragraph (b) of this section. (b) The specimen joint must be — (1) Visually examined during and after assembly or joining and found to have the same appearance as a joint or photographs of a joint that is acceptable under the procedure; and (2) In the case of a heat fusion, solvent cement, or adhesive joint: (i) Tested under any one of the test methods listed under §192.283(a) applicable to the type of joint and material being tested; (ii) Examined by ultrasonic inspection and found not to contain flaws that would cause failure; or (iii) Cut into at least 3 longitudinal straps, each of which is — (A) Visually examined and found not to contain voids or discontinuities on the cut surfaces of the joint area; and (B) Deformed by bending, torque, or impact, and if failure occurs, it must not initiate in the joint area. (c) A person must be re-qualified under an applicable procedure once each calendar year at intervals not exceeding 15 months, or after any production joint is found unacceptable by testing under §192.513. (d) Each operator shall establish a method to determine that each person making joints in plastic pipelines in the operator's system is qualified in accordance with this section. [Issued by Amdt. 192-34, 44 FR 42968, July 23, 1979 with Amdt. 192-34 Time Ext., 44 FR 50841, Aug. 30, 1979, Amdt. 192-34 Time Ext., 44 FR 57100, Oct. 4, 1979, Amdt. 192-34A, 45 FR 9931, Feb. 14, 1980 and Amdt. 192-34B, 46 FR 39, Jan. 2, 1981; Amdt. 192-93, 68 FR 53895, Sept. 15, 2003; Amdt. 192-94, 69 FR 32886, June 14, 2004; Amdt. 192-120, 80 FR 12762, Mar. 11, 2015]



GUIDE MATERIAL

This guide material is under review following Amendment 192-120. 1 OBSERVATION AND CERTIFICATION OF JOINER Persons qualifying to make joints in plastic piping should be observed and certified by a qualified joiner

while demonstrating their ability to make satisfactory joints using the correct procedure. See AGA XR0104, "Plastic Pipe Manual for Gas Service."

2 CERTIFICATION RECORDS Records or qualification cards or both, which show the extent of the individual's qualifications, should be

maintained for the qualification interval. 3 ULTRASONIC INSPECTION OF FUSION JOINTS Ultrasonic inspection equipment should be capable of inspecting the internal bead for proper formation

as well as detecting flaws in the fusion zone. Each manufacturer is a source of procedures for its equipment. The criteria for establishing an acceptable fusion joint must be verified by a destructive test and be repeatable. Each procedure should include the following.

(a) Cleaning the inspection area on both sides of the fusion joint. (b) Using an appropriate manufacturer-approved couplant to couple the transducer to the pipe. (c) Inspecting the entire pipe circumference on both sides of the fusion joint.

§192.287 Plastic pipe: Inspection of joints.


No person may carry out the inspection of joints in plastic pipes required by §§192.273(c) and 192.285(b) unless that person has been qualified by appropriate training or experience in evaluating the acceptability of plastic pipe joints made under the applicable joining procedure. [Issued by Amdt. 192-34, 44 FR 42968, July 23, 1979 with Amdt. 192-34 Time Ext., 44 FR 50841, Aug. 30, 1979, and Amdt. 192-34 Time Ext., 44 FR 57100, Oct. 4, 1979; Amdt. 192-94, 69 FR 32886, June 14, 2004]

GUIDE MATERIAL



140

Reserved

GPTC GUIDE FOR GAS TRANSMISSION, DISTRIBUTION, §192.301 AND GATHERING PIPING SYSTEMS: 2015 Edition SUBPART G


SUBPART G GENERAL CONSTRUCTION REQUIREMENTS

FOR TRANSMISSION LINES AND MAINS

§192.301 Scope.


This subpart prescribes minimum requirements for constructing transmission lines and mains.

GUIDE MATERIAL


§192.303 Compliance with specifications or standards.


Each transmission line or main must be constructed in accordance with comprehensive written specifications or standards that are consistent with this part.

GUIDE MATERIAL


§192.305 Inspection: General.


Each transmission line and main must be inspected to ensure that it is constructed in accordance with this subpart. An operator must not use operator personnel to perform a required inspection if the operator personnel performed the construction task requiring inspection. Nothing in this section prohibits the operator from inspecting construction tasks with operator personnel who are involved in other construction tasks. [Amdt. 192-120, 80 FR 12762, Mar. 11, 2015]

GUIDE MATERIAL

This guide material is under review following Amendment 192-120. (a) Each operator should provide inspection by personnel who are knowledgeable by training or experience.

Inspection should ensure that all work conforms to the operator’s specifications and to applicable federal, state, and local requirements. The inspector should have the authority to order the repair or the removal and replacement of any component that fails to meet the above requirements.



(b) The operator should assemble and retain all necessary records.

§192.307 Inspection of materials.


Each length of pipe and each other component must be visually inspected at the site of installation to ensure that it has not sustained any visually determinable damage that could impair its serviceability.

GUIDE MATERIAL (a) Pipe and other components used in the construction of transmission lines and mains may be exposed to

possible damage during the handling and transportation required to reach the installation location. Those performing the visual inspection at the installation site should be alert for such damage. Also, care should be exercised to prevent handling damage during installation.

(b) Field inspections for gouged or grooved pipe should be performed just ahead of the coating operation

and during the lowering-in and backfill operations. (c) Inspection should be made to determine that the coating machine does not cause harmful gouges or

grooves. (d) Lacerations of the protective coating should be carefully examined prior to the repair of the coating to

see if the pipe surface has been damaged. (e) All repairs, replacements, or changes should be inspected before they are covered. (f) Since plastic piping and other components are susceptible to mishandling damage, special attention

should be given during the installation site inspection to detect cuts, gouges, scratches, kinks, and similar imperfections.

§192.309 Repair of steel pipe.


(a) Each imperfection or damage that impairs the serviceability of a length of steel pipe must be repaired or removed. If a repair is made by grinding, the remaining wall thickness must at least be equal to either: (1) The minimum thickness required by the tolerances in the specification to which the pipe was manufactured; or (2) The nominal wall thickness required for the design pressure of the pipeline. (b) Each of the following dents must be removed from steel pipe to be operated at a pressure that produces a hoop stress of 20 percent, or more, of SMYS, unless the dent is repaired by a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe: (1) A dent that contains a stress concentrator such as a scratch, gouge, groove, or arc burn. (2) A dent that affects the longitudinal weld or a circumferential weld. (3) In pipe to be operated at a pressure that produces a hoop stress of 40 percent or more of SMYS, a dent that has a depth of —


149

(b) Effects on cathodic protection (CP) system. Consideration should be given to the possible shielding effects on CP currents that may occur from the installation of non-conductive materials, such as rock shielding and padding.

3.3 Rock shielding. Where rock shielding is used to prevent coating damage, it must be installed properly. One method of

installing a wrap-type rock shielding material is to secure the rock shielding entirely around the pipe using fiberglass tape or other suitable banding material. Rock shielding should not be draped over the pipe unless suitable backfill and padding is placed in the ditch to provide continuous and adequate support of the pipe in the trench.

3.4 Consolidation. If trench flooding is used to consolidate the backfill, care should be taken to see that the pipe is not

floated from its firm bearing on the trench bottom. Where mains are installed in existing or proposed roadways or in unstable soil, flooding should be augmented by wheel rolling or mechanical compaction. Multi-lift mechanical compaction can be used in lieu of flooding.

4 ALTERNATIVE INSTALLATION METHODS 4.1 Horizontal directional drilling. (a) See Guide Material Appendix G-192-6 for damage prevention considerations while performing

directional drilling or using other trenchless technologies. (b) See Guide Material Appendices G-192-15A and G-192-15B for additional considerations for

horizontal directional drilling to install steel pipelines and plastic pipelines, respectively.

§192.321 Installation of plastic pipe.


(a) Plastic pipe must be installed below ground level except as provided by paragraphs (g) and (h) of this section. (b) Plastic pipe that is installed in a vault or any other below grade enclosure must be completely encased in gas-tight metal pipe and fittings that are adequately protected from corrosion. (c) Plastic pipe must be installed so as to minimize shear or tensile stresses. (d) Thermoplastic pipe that is not encased must have a minimum wall thickness of 0.090 inch (2.29 millimeters), except that pipe with an outside diameter of 0.875 inch (22.3 millimeters) or less may have a minimum wall thickness of 0.062 inch (1.58 millimeters). (e) Plastic pipe that is not encased must have an electrically conducting wire or other means of locating the pipe while it is underground. Tracer wire may not be wrapped around the pipe and contact with the pipe must be minimized but is not prohibited. Tracer wire or other metallic elements installed for pipe locating purposes must be resistant to corrosion damage, either by use of coated copper wire or by other means. (f) Plastic pipe that is being encased must be inserted into the casing pipe in a manner that will protect the plastic. The leading end of the plastic must be closed before insertion. (g) Uncased plastic pipe may be temporarily installed above ground level under the following conditions: (1) The operator must be able to demonstrate that the cumulative aboveground exposure of the pipe does not exceed the manufacturer's recommended maximum period of exposure or 2 years, whichever is less. (2) The pipe either is located where damage by external forces is unlikely or is otherwise protected against such damage.



(3) The pipe adequately resists exposure to ultraviolet light and high and low temperatures. (h) Plastic pipe may be installed on bridges provided that it is: (1) Installed with protection from mechanical damage, such as installation in a metallic casing; (2) Protected from ultraviolet radiation; and (3) Not allowed to exceed the pipe temperature limits specified in §192.123. [Amdt. 192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-93, 68 FR 53895, Sept. 15, 2003; Amdt. 192-94, 69 FR 32886, June 14, 2004]

GUIDE MATERIAL 1 GENERAL PRECAUTIONS 1.1 Handling. Care should be taken to avoid rough handling of plastic pipe. It should not be dropped or have other

objects dropped upon it, nor should it be pushed or pulled over sharp projections. Caution should be taken to prevent kinking or buckling. Any kinks or buckles that occur should be cut out as a cylinder.

1.2 Considerations to minimize damage by outside forces. See Guide Material Appendix G-192-13. 1.3 Other. (a) Plastic materials vary in their ability to resist damage from fire, heat, and chemicals. Care should be

exercised at all times to protect the pipe from these hazards. (b) Plastic pipe should be adequately supported during storage. Thermoplastic pipe and fittings should

be protected from long-term exposure to direct sunlight. See 2 of the guide material under §192.59. 2 DIRECT BURIAL OF PLASTIC PIPE 2.1 Contraction. The piping should be installed with sufficient slack to provide for possible contraction. Under high

temperature conditions, cooling may be necessary before the last connection is made. See 3.5(f)(3) of the guide material under §192.281.

2.2 Installation stress. When long sections of piping that have been assembled alongside the ditch are lowered-in, care should

be taken to avoid any strains that may overstress or buckle the piping, or impose excessive stress on the joints.

2.3 Backfilling. (a) General. Blocking should not be used to support plastic pipe. Plastic pipe should be laid on

undisturbed soil, well-compacted soil, well-tamped soil, or other continuous support. If plastic pipe is to be laid in soils that may damage it, the pipe should be protected by suitable rock-free materials.

(b) Backfill material. Backfilling should be performed in a manner to provide firm support around the piping and to protect the piping from damage. Plastic piping materials could be affected by rock impingement. The backfill expected to come in direct contact with the pipe should be free of rocks, pieces of pavement, or other materials that might damage the pipe. Rocks or similar material can cause stress concentrations that could limit the long-term performance of the piping system should contact with the pipe occur.

(1) Consult the pipe manufacturer for guidance to determine the appropriate backfill for its plastic piping material.

(2) Maximum particle size for materials within 6 inches of the pipe, including bedding materials and other initial materials that might damage the pipe, are shown in Table 192.321i.



Pipe Size Maximum Particle Size (inch) NPS 4 and smaller 1/2 NPS 6 and NPS 8 3/4 Larger than NPS 8 1

TABLE 192.321i

(3) Beyond the 6-inch zone, the final backfill should be free of materials that might damage the

pipe, such as rocks (3 inches or larger), pieces of pavement, or construction debris. Additional guidance on backfill is provided in ASTM D2774, “Standard Practice for Underground Installation of Thermoplastic Pressure Piping.”

(c) Consolidation. If trench flooding is used to consolidate the backfill, care should be taken to see that the piping is not floated from its firm bearing on the trench bottom. Where mains and service lines are installed in existing or proposed roadways or in unstable soil, flooding should be augmented by wheel rolling or mechanical compaction. Multi-lift mechanical compaction can be used in lieu of flooding. Care should be taken when using mechanical compaction not to cause excessive ovality of the plastic pipe.

2.4 Means of locating. (a) Tracer wire. (1) A bare or coated corrosion-resistant metal wire may be buried along the plastic pipe. Wire size

#12 or #14 AWG is commonly installed. (2) Tracer wire may be installed physically separated from, or immediately adjacent to, the plastic

pipe. Separation may lead to difficulty in accurately locating the plastic pipe. In determining placement of tracer wire relative to plastic pipe, the operator should consider the relative importance of locating the pipe versus potential pipe damage from a current surge through the tracer wire. Lightning strikes are a source of current surges.

(3) Tracer wire should not be wrapped around plastic pipe. It may be taped to the outside of the plastic pipe, especially for installation by boring or plowing-in, or placed loosely in the trench directly adjacent to the pipe.

(4) A separation of 2" to 6" between plastic pipe and tracer wire is commonly used where current surges, such as from lightning, have been experienced or can be expected.

(5) Leads from tracer wire into curb boxes and valve boxes and on outside service risers can be used for direct connection of locating instruments. Consideration should be given to ensuring that no bare tracer wire is exposed such that a lightning strike could cause a current surge through the wire.

(6) Splicing of tracer wire, if necessary, should be done in a manner to produce an electrically and mechanically sound joint that will not loosen or separate under conditions to which it may be subjected, such as backfilling operations and freeze-thaw cycles.

(7) Where the tracer wire is electrically connected to metallic structures (e.g., steel or cast iron pipe) for reasons such as expanded locating capabilities or cathodic protection, consideration should be given to the effects of electrical current surges on the ability to locate the plastic pipe or the increased potential for damage.

(8) Additional information may be obtained from AGA XR0104, "Plastic Pipe Manual for Gas Service."

(b) Metallic tape. A metallic coated or corrosion-resistant metallic tape may be installed along with the plastic pipe. Care should be taken so that the tape is not torn or separated during backfilling operations. Metallic locating tape normally has no accessible leads for connecting locating equipment, making it necessary to use a passive or induced current locating device.

(c) Mapping. Accurate mapping of plastic pipe with dimensions referenced to permanent landmarks (e.g., lot lines, street centerlines) is an acceptable method of locating plastic pipe.

(d) Passive devices. Tuned coils or other passive devices may be buried at strategic points along a plastic pipeline. These devices can be located from above ground by means of an associated locating instrument.



2.5 Warning tape. A highly-visible warning tape may be used in addition to one of the means for locating the pipe. Such

tapes are usually yellow with a legend, such as "Warning: Buried Gas Pipeline." Warning tapes are generally installed approximately 12" directly above the plastic pipe so that it will be struck first by someone digging in the vicinity.

3 PLASTIC PIPE INSERTED INTO A CASING OR INTO AN ABANDONED PIPELINE 3.1 General. (a) The casing or abandoned pipeline should be prepared to the extent necessary to remove any sharp

edges, projections, dust, welding slag, or abrasive material which could damage the plastic during or after insertion.

(b) A support sleeve or plug should be used to prevent the plastic pipe from bearing on the end of the casing or abandoned pipeline.

(c) Maps or other records should indicate plastic pipe that is inserted in a casing or an abandoned pipeline.

3.2 Special considerations. (a) That portion of the plastic pipe which spans disturbed earth should be protected by bridging, by

compaction of the soil under the plastic pipe, or by other means to prevent the settling of the backfill from shearing the plastic pipe.

(b) The portion of the plastic pipe exposed due to the removal of a section of casing pipe or abandoned pipeline should have sufficient strength or be protected with bridging or other means, so as to withstand the anticipated external soil loadings.

(c) Protective sleeve installations that are designed to mitigate the stresses imposed onto the plastic pipe in the transition area should be considered if undue stresses are anticipated, or if recommended by the manufacturer. The installation of protective sleeves, in addition to providing adequate backfill and compaction around the transition area, reduces excessive bending and shear stresses. For protective sleeves, see guide material under 192.367.

(d) Cased plastic pipe can contract due to cold gas or low ambient temperature. See 3.5(f)(3) of the guide material under §192.281.

(e) Where a gas leak migrating through the annular space between the plastic pipe and the casing or abandoned pipeline could result in a hazardous condition, consideration should be given to plugging the annular space at one or both ends. Plugs may also be provided at intermediate points, such as where the casing or abandoned pipeline is cut, to permit the installation of a service tee or a lateral main. Care should be used in the selection of the plugging material to avoid damage to the plastic pipe. Both urethane foam and grout have been found to be effective for this purpose.

(f) If water that has accumulated between the casing or abandoned pipeline and the carrier pipe freezes, the carrier pipe can be constricted (affecting the capacity) or damaged causing a leak. One or more of the following steps can be taken to minimize this possibility.

(1) Sizing the pipe so that the formation of ice between the carrier and the casing or abandoned pipeline will not constrict the carrier pipe to the extent that service is affected.

(2) Providing for drainage at the lower points in the casing or abandoned pipeline. (3) Inserting a filler, such as a closed cell foam material, in the annular space. 3.3 Reference. See 8 below for plastic pipe encased on bridges. 4 PROVISIONS FOR BENDS 4.1 General considerations. The bends should be free of buckles, cracks, or other evidence of damage. 4.2 Bending radius. Plastic pipe may not be deflected to a radius smaller than the minimum recommended by the

manufacturer for the kind, type, grade, wall thickness, and diameter of the particular plastic pipe used.

GPTC GUIDE FOR GAS TRANSMISSION, DISTRIBUTION, §192.501 AND GATHERING PIPING SYSTEMS: 2015 Edition SUBPART J

217 Addendum 1, May 2015

SUBPART J TEST REQUIREMENTS

§192.501 Scope.


This subpart prescribes minimum leak-test and strength-test requirements for pipelines.

GUIDE MATERIAL


§192.503 General requirements.


(a) No person may operate a new segment of pipeline, or return to service a segment of pipeline that has been relocated or replaced, until — (1) It has been tested in accordance with this subpart and §192.619 to substantiate the proposed maximum allowable operating pressure; and (2) Each potentially hazardous leak has been located and eliminated. (b) The test medium must be liquid, air, natural gas, or inert gas that is — (1) Compatible with the material of which the pipeline is constructed; (2) Relatively free of sedimentary materials; and (3) Except for natural gas, nonflammable. (c) Except as provided in §192.505(a), if air, natural gas, or inert gas is used as the test medium, the following maximum hoop stress limitations apply:

Class Location

Maximum hoop stress allowed as percentage of SMYS

Natural gas Air or inert gas

1 2 3 4

80 30 30 30

80 75 50 40

(d) Each joint used to tie in a test segment of pipeline is excepted from the specific test requirements of this subpart, but each non-welded joint must be leak tested at not less than its operating pressure. (e) If a component other than pipe is the only item being replaced or added to a pipeline, a strength test after installation is not required, if the manufacturer of the component certifies that: (1) The component was tested to at least the pressure required for the pipeline to which it is being added;



(2) The component was manufactured under a quality control system that ensures that each item manufactured is at least equal in strength to a prototype and that the prototype was tested to at least the pressure required for the pipeline to which it is being added; or (3) The component carries a pressure rating established through applicable ASME/ANSI, Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS) specifications, or by unit strength calculations as described in §192.143. [Amdt. 192-58, 53 FR 1633, Jan. 21, 1988; Amdt. 192-60, 53 FR 36028, Sept. 16, 1988 with Amdt. 192-60A, 54 FR 5484, Feb. 3, 1989; Amdt. 192-120, 80 FR 12762, Mar. 11, 2015]

GUIDE MATERIAL

This guide material is under review following Amendment 192-120. (a) The test procedure should give consideration to such items as the following. (1) The method and equipment used. (2) The test medium and maximum test pressure. (3) The duration of the test. (4) The volumetric content of the piping and its location. (5) The reason for the pressure test. (i) New construction. (ii) Pipe replacement. (iii) Class location changes. (iv) Uprating. (v) Integrity assessment. (vi) Other as deemed appropriate by the operator. (b) See §192.619 for test pressure requirements to substantiate the maximum allowable operating pressure

for steel and plastic pipelines. (c) See Guide Material Appendices G-192-9, G-192-9A, and G-192-10.

§192.505 Strength test requirements for steel pipeline

to operate at a hoop stress of 30 percent or more of SMYS. ▌[Effective Date: 10/01/15]

(a) Except for service lines, each segment of a steel pipeline that is to operate at a hoop stress of 30 percent or more of SMYS must be strength tested in accordance with this section to substantiate the proposed maximum allowable operating pressure. In addition, in a Class 1 or Class 2 location, if there is a building intended for human occupancy within 300 feet (91 meters) of a pipeline, a hydrostatic test must be conducted to a test pressure of at least 125 percent of maximum operating pressure on that segment of the pipeline within 300 feet (91 meters) of such a building, but in no event may the test section be less than 600 feet (183 meters) unless the length of the newly installed or relocated pipe is less than 600 feet (183 meters). However, if the buildings are evacuated while the hoop stress exceeds 50 percent of SMYS, air or inert gas may be used as the test medium. (b) In a Class 1 or Class 2 location, each compressor station, regulator station, and measuring station must be tested to at least Class 3 location test requirements. (c) Except as provided in paragraph (e) of this section, the strength test must be conducted by maintaining the pressure at or above the test pressure for at least 8 hours.



(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

This guide material is under review following Amendment 192-120. 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.

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.


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, §192.605 AND GATHERING PIPING SYSTEMS: 2015 Edition SUBPART L


(i) Unintended closure of valves or shutdowns; (ii) Increase or decrease in pressure or flow rate outside normal operating limits; (iii) Loss of communications; (iv) Operation of any safety device; and (v) Any other foreseeable malfunction of a component, deviation from normal operation, or personnel error, which may result in a hazard to persons or property. (2) Checking variations from normal operation after abnormal operation has ended at sufficient critical locations in the system to determine continued integrity and safe operation. (3) Notifying responsible operator personnel when notice of an abnormal operation is received. (4) Periodically reviewing the response of operator personnel to determine the effectiveness of the procedures controlling abnormal operation and taking corrective action where deficiencies are found. (5) The requirements of this paragraph (c) do not apply to natural gas distribution operators that are operating transmission lines in connection with their distribution system. (d) Safety-related condition reports. The manual required by paragraph (a) of this section must include instructions enabling personnel who perform operation and maintenance activities to recognize conditions that potentially may be safety-related conditions that are subject to the reporting requirements of §191.23 of this subchapter. (e) Surveillance, emergency response, and accident investigation. The procedures required by §§192.613(a), 192.615, and 192.617 must be included in the manual required by paragraph (a) of this section. [Amdt. 192-27A, 41 FR 47252, Oct. 28, 1976; Amdt. 192-59, 53 FR 24942, July 1, 1988 with Amdt. 192-59 Correction, 53 FR 26560, July 13, 1988; Amdt. 192-71, 59 FR 6579, Feb. 11, 1994 with Amdt. 19271A, 60 FR 14379, Mar. 17, 1995; Amdt. 192-93, 68 FR 53895, Sept. 15, 2003; Amdt. 192-112, 74 FR 63310, Dec. 3, 2009]

GUIDE MATERIAL 1 GENERAL (a) Each procedural manual for operations, maintenance, and emergencies should include a written

statement, procedure, or other document addressing each specific requirement of §192.605. The requirements include the maintenance and normal operation of any pipeline; and the abnormal operations of transmission lines, other than those transmission lines operated in connection with a distribution system.

(b) The comprehensive manual can consist of multiple binders with relevant sections kept at appropriate locations. Appropriate sections of other documents may be referenced instead of being incorporated, but the referenced documents are to be present at the location to which they apply.

(c) The manual will necessarily vary in length and complexity depending upon the individual operator, its size, locale, policies, and types of equipment in use and the amount of material included in its entirety or cross-referenced, including manufacturers’ instructions, where appropriate.

(d) Procedures for only those facilities within the operator’s system need be included in the manual. Therefore, it is not necessary to have a manual for each pipeline.

(e) The required review of the manual should ensure that the operator’s current facilities and any deficiencies in the manual are addressed. An operator should consider reviewing its operator qualification (OQ) processes and procedures since changes to the manual may affect the OQ program. More serious deficiencies, possibly identified following an accident, may require immediate correction.

(f) Many sections of the pipeline safety regulations are written using performance language to achieve a desired result, but the method to reach that result is not specified. In such situations, an operator should use a method that is suitable for its individual operations and include it in the manual.


242

2 TRAINING 2.1 Operations and maintenance (O&M) procedures.

Each operator should establish a training program that will provide operating and maintenance personnel with a basic understanding of each element of the procedural manual for operations, maintenance, and emergencies appropriate to the job assignment. See 3.7 below regarding periodic reviews, procedure modifications, and retraining of personnel.

2.2 Operations and maintenance tasks. See Subpart N. 2.3 Emergency response procedures.

Each operator is required by §192.615(b)(2) to train the appropriate operating personnel to ensure that they are knowledgeable of the emergency procedures. See 2 of the guide material under §192.615.

3 MAINTENANCE AND NORMAL OPERATIONS

In addition to those items required to be in the manual under Subparts L and M as they apply to the operator’s facilities, other Subparts (e.g., E, F, I, J, and K) may also require written procedures. Additional guide material can be found under individual sections.

3.1 Control of corrosion. Refer to guide material for respective sections of Subpart I. 3.2 Availability of construction records, maps, and operating history. (a) Construction records, maps, and operating history should be comprehensive and current. The

construction records, maps, and operating history will depend upon the individual operator, its size and locale, and the types of equipment in use.

(b) The construction records, maps, and operating history should be made available to operating personnel, especially supervisors or those called on to safely operate pipeline facilities or respond to emergencies, or both. Dispatch or gas control personnel should have maps and operating history available.

(c) For transmission facilities, the types of records and data that could be made available are as follows.

(1) Pipeline system maps, including abandoned and out-of-service facilities. (2) Compressor station and other piping drawings (mechanical and major gas piping). (3) Maximum allowable operating pressures. (4) Inventories of pipe and equipment. (5) Pressure and temperature histories. (6) Maintenance history. (7) Emergency shutdown systems drawings. (8) Isolation drawings. (9) Purging information. (10) Applicable bolt torquing information. (11) Operating parameters for engines and equipment. (12) Leak history. (d) For distribution systems, the types of records and data that could be made available are as follows. (1) Maps showing location of pipe, valves, and other system components. (2) Maps and records showing pipe specifications, valve type, and operating pressure. (3) Auxiliary maps and records showing other useful information, including abandoned and out-of-

service facilities. (e) Communications with knowledgeable personnel should be maintained to respond to questions

concerning the records, maps, or history if the need arises.



Additional guidance on mitigation methods may be found in ASME STP-PT-011, "Integrity Management of Stress Corrosion Cracking in Gas Pipeline High Consequence Areas," which documents a joint industry project.

4.2 References. (a) ASME B31.8S, Appendix A3 and Table 4 (see §192.7). (b) ASME STP-PT-011, "Integrity Management of Stress Corrosion Cracking in Gas Pipeline High

Consequence Areas." (c) NACE Publication 35103, "External Stress Corrosion Cracking of Underground Pipelines." (d) NACE SP0204, "Stress Corrosion Cracking (SCC) Direct Assessment Methodology." (e) National Energy Board (Canada), Report of the Inquiry MH-2-95, "Stress Corrosion Cracking on

Canadian Oil and Gas Pipelines," December 1996. (f) OPS Advisory Bulletin ADB-03-05 (68 FR 58166, Oct. 8, 2003; see Guide Material Appendix G-192-

1, Section 2). (g) OPS Technical Task Order Number 8, "Stress Corrosion Cracking Study," Michael Baker, Jr., Inc.,

January 2005. (h) PRCI L52047, "Pipeline Repair Manual." (i) "SCC Detection and Mitigation Based on In-Line Inspection Tools," W. Kresic and S. Ironside, Paper

# IPC2004-0375 presented at ASME International Pipeline Conference, Calgary, October 2004. 5 THREADED JOINTS

Operators that have threaded joints in underground gas systems may want to determine if increased surveillance is warranted. Factors that could be considered include wall thickness, leak history, susceptibility to corrosion, settlement, frost-induced movement, and third-party damage.

6 SEVERE FLOODING Severe flooding can adversely affect the safe operation of a pipeline. Operators should consider the

following actions in areas prone to, or previously affected by, flooding. (a) Identify pipeline facilities that are in the flood plain, such as overlaying 100-year flood elevations on

GIS pipeline maps. (b) Extend regulator vents and relief stacks above the level of anticipated flooding, as appropriate. (c) Determine if facilities that are normally above ground (e.g., valves, regulators, relief devices) could

become submerged and then have a potential for being struck by vessels or debris, and consider protecting or relocating such facilities.

(d) For additional information, see OPS Advisory Bulletin ADB-11-04 (76 FR 44985, July 27, 2011; see Guide Material Appendix G-192-1, Section 2).

7 SERVICE LINES UNDER BUILDINGS Buried and uncased service lines discovered under buildings should be moved to locations no longer

beneath the building or reinstalled under the building in accordance with the requirements of §192.361. In instances involving mobile homes, it may be possible to have the home relocated away from the service line. See guide material under §192.361 (pending).

8 INTEGRITY MANAGEMENT CONSIDERATIONS Conditions or information discovered that could affect the integrity of a pipeline should be reported to the

appropriate integrity management and operating personnel.


260

§192.614 Damage prevention program.


(a) Except as provided in paragraphs (d) and (e) of this section, each operator of a buried pipeline shall carry out, in accordance with this section, a written program to prevent damage to that pipeline from excavation activities. For the purpose of this section, the term "excavation activities" includes excavation, blasting, boring, tunneling, backfilling, the removal of aboveground structures by either explosive or mechanical means, and other earthmoving operations. (b) An operator may comply with any of the requirements of paragraph (c) of this section through participation in a public service program, such as a one-call system, but such participation does not relieve the operator of responsibility for compliance with this section. However, an operator must perform the duties of paragraph (c)(3) of this section through participation in a one-call system, if that one-call system is a qualified one-call system. In areas that are covered by more than one qualified one-call system, an operator need only join one of the qualified one-call systems if there is a central telephone number for excavators to call for excavation activities, or if the one-call systems in those areas communicate with one another. An operator’s pipeline system must be covered by a qualified one-call system where there is one in place. For the purpose of this section, a one-call system is considered a "qualified one-call system" if it meets the requirements of section (b)(1) or (b)(2) of this section. (1) The state has adopted a one-call damage prevention program under §198.37 of this chapter; or (2) The one-call system: (i) Is operated in accordance with §198.39 of this chapter; (ii) Provides a pipeline operator an opportunity similar to a voluntary participant to have a part in management responsibilities; and (iii) Assesses a participating pipeline operator a fee that is proportionate to the costs of the one-call system’s coverage of the operator’s pipeline. (c) The damage prevention program required by paragraph (a) of this section must, at a minimum: (1) Include the identity, on a current basis, of persons who normally engage in excavation activities in the area in which the pipeline is located. (2) Provides for notification of the public in the vicinity of the pipeline and actual notification of the persons identified in paragraph (c)(1) of this section of the following as often as needed to make them aware of the damage prevention program: (i) The program's existence and purpose; and (ii) How to learn the location of underground pipelines before excavation activities are begun. (3) Provide a means of receiving and recording notification of planned excavation activities. (4) If the operator has buried pipelines in the area of excavation activity, provide for actual notification of persons who give notice of their intent to excavate of the type of temporary marking to be provided and how to identify the markings. (5) Provide for temporary marking of buried pipelines in the area of excavation activity before, as far as practical, the activity begins. (6) Provide as follows for inspection of pipelines that an operator has reason to believe could be damaged by excavation activities: (i) The inspection must be done as frequently as necessary during and after the activities to verify the integrity of the pipeline; and (ii) In the case of blasting, any inspection must include leakage surveys. (d) A damage prevention program under this section is not required for the following pipelines: (1) Pipelines located offshore.


285

Pipeline segment Pressure date Test date

— Onshore gathering line that first became subject to this part (other than §192.612) after April 13, 2006. — Onshore transmission line that was a gathering line not subject to this part before March 15, 2006.

March 15, 2006, or date line becomes subject to this part, whichever is later.

5 years preceding applicable date in second column.

Offshore gathering lines. July 1, 1976. July 1, 1971. All other pipelines. July 1, 1970. July 1, 1965.

(4) The pressure determined by the operator to be the maximum safe pressure after considering the history of the segment, particularly known corrosion and the actual operating pressure. (b) No person may operate a segment to which paragraph (a)(4) of this section is applicable, unless over-pressure protective devices are installed on the segment in a manner that will prevent the maximum allowable operating pressure from being exceeded, in accordance with §192.195. (c) The requirements on pressure restrictions in this section do not apply in the following instance. An operator may operate a segment of pipeline found to be in satisfactory condition, considering its operating and maintenance history, at the highest actual operating pressure to which the segment was subjected during the 5 years preceding the applicable date in the second column of the table in paragraph (a)(3) of this section. An operator must still comply with §192.611. (d) The operator of a pipeline segment of steel pipeline meeting the conditions prescribed in §192.620(b) may elect to operate the segment at a maximum allowable operating pressure determined under §192.620(a). [Amdt. 192-3, 35 FR 17659, Nov. 17, 1970; Amdt. 192-27, 41 FR 34598, Aug. 16, 1976 with Amdt. 192-27A, 41 FR 47252, Oct. 28, 1976; Amdt. 192-30, 42 FR 60146, Nov. 25, 1977; Amdt. 192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-102, 71 FR 13289, Mar. 15, 2006; Amdt. 192-103, 71 FR 33402, June 9, 2006; RIN 2137-AE25, 73 FR 62148, Oct. 17, 2008; Eff. date stayed by 73 FR 72737, Dec. 1, 2008]

GUIDE MATERIAL (a) Before adjusting the operation of a pipeline by increasing pressure within the limits of the pipeline

segment's MAOP, but substantially above a historical long-term operating pressure, the operator should consider a review of the operating, maintenance, and testing history for the segment. See guide material under §192.555. Pressure should be increased gradually at an incremental rate. The operator should consider conducting a leak survey when the pressure increase is concluded.

(b) See Guide Material Appendices G-192-9, G-192-9A, and G-192-10.



§192.620 Alternative maximum allowable operating pressure for certain steel pipelines.


(a) How does an operator calculate the alternative maximum allowable operating pressure? An operator calculates the alternative maximum allowable operating pressure by using different factors in the same formulas used for calculating maximum allowable operating pressure under §192.619(a) as follows: (1) In determining the alternative design pressure under §192.105, use a design factor determined in accordance with §192.111(b), (c), or (d) or, if none of these paragraphs apply, in accordance with the following table:

Class Location Alternative Design Factor (F)

1 2 3

0.80 0.67 0.56

(i) For facilities installed prior to December 22, 2008, for which §192.111(b), (c), or (d) applies, use the following design factors as alternatives for the factors specified in those paragraphs: §192.111(b) — 0.67 or less; 192.111(c) and (d) — 0.56 or less. (ii) [Reserved] (2) The alternative maximum allowable operating pressure is the lower of the following: (i) The design pressure of the weakest element in the pipeline segment, determined under subparts C and D of this part. (ii) The pressure obtained by dividing the pressure to which the pipeline segment was tested after construction by a factor determined in the following table:

Class Location Alternative Test Factor

1 2 3

1.25 11.50 1.50

1For Class 2 alternative maximum allowable operating pressure segments installed prior to December 22, 2008 the alternative test factor is 1.25.

(b) When may an operator use the alternative maximum allowable operating pressure calculated

under paragraph (a) of this section? An operator may use an alternative maximum allowable operating pressure calculated under paragraph (a) of this section if the following conditions are met: (1) The pipeline segment is in a Class 1, 2, or 3 location; (2) The pipeline segment is constructed of steel pipe meeting the additional design requirements in §192.112; (3) A supervisory control and data acquisition system provides remote monitoring and control of the pipeline segment. The control provided must include monitoring of pressures and flows, monitoring compressor start-ups and shut-downs, and remote closure of valves per paragraph (d)(3) of this section;



(4) The pipeline segment meets the additional construction requirements described in §192.328; (5) The pipeline segment does not contain any mechanical couplings used in place of girth welds; (6) If a pipeline segment has been previously operated, the segment has not experienced any failure during normal operations indicative of a systemic fault in material as determined by a root cause analysis, including metallurgical examination of the failed pipe. The results of this root cause analysis must be reported to each PHMSA pipeline safety regional office where the pipeline is in service at least 60 days prior to operation at the alternative MAOP. An operator must also notify a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State; and (7) At least 95 percent of girth welds on a segment that was constructed prior to December 22, 2008, must have been non-destructively examined in accordance with §192.243(b) and (c). (c) What is an operator electing to use the alternative maximum allowable operating pressure

required to do? If an operator elects to use the alternative maximum allowable operating pressure calculated under paragraph (a) of this section for a pipeline segment, the operator must do each of the following: (1) For pipelines already in service, notify the PHMSA pipeline safety regional office where the pipeline is in service of the intention to use the alternative pressure at least 180 days before operating at the alternative MAOP. For new pipelines, notify the PHMSA pipeline safety regional office of planned alternative MAOP design and operation at least 60 days prior to the earliest start date of either pipe manufacturing or construction activities. An operator must also notify the state pipeline safety authority when the pipeline is located in a state where PHMSA has an interstate agent agreement or where an intrastate pipeline is regulated by that state. (2) Certify, by signature of a senior executive officer of the company, as follows: (i) The pipeline segment meets the conditions described in paragraph (b) of this section; and (ii) The operating and maintenance procedures include the additional operating and maintenance requirements of paragraph (d) of this section; and (iii) The review and any needed program upgrade of the damage prevention program required by paragraph (d)(4)(v) of this section has been completed. (3) Send a copy of the certification required by paragraph (c)(2) of this section to each PHMSA pipeline safety regional office where the pipeline is in service 30 days prior to operating at the alternative MAOP. An operator must also send a copy to a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State. (4) For each pipeline segment, do one of the following: (i) Perform a strength test as described in §192.505 at a test pressure calculated under paragraph (a) of this section or (ii) For a pipeline segment in existence prior to December 22, 2008, certify, under paragraph (c)(2) of this section, that the strength test performed under §192.505 was conducted at test pressure calculated under paragraph (a) of this section, or conduct a new strength test in accordance with paragraph (c)(4)(i) of this section. (5) Comply with the additional operation and maintenance requirements described in paragraph (d) of this section. (6) If the performance of a construction task associated with implementing alternative MAOP that occurs after December 22, 2008, can affect the integrity of the pipeline segment, treat that task as a ‘‘covered task’’, notwithstanding the definition in §192.801(b) and implement the requirements of subpart N as appropriate. (7) Maintain, for the useful life of the pipeline, records demonstrating compliance with paragraphs (b), (c)(6), and (d) of this section. (8) A Class 1 and Class 2 location can be upgraded one class due to class changes per §192.611(a). All class location changes from Class 1 to Class 2 and from Class 2 to Class 3 must have all anomalies evaluated and remediated per: The ‘‘original pipeline class grade’’ §192.620(d)(11)



anomaly repair requirements; and all anomalies with a wall loss equal to or greater than 40 percent must be excavated and remediated. Pipelines in Class 4 may not operate at an alternative MAOP. (d) What additional operation and maintenance requirements apply to operation at the

alternative maximum allowable operating pressure? In addition to compliance with other applicable safety standards in this part, if an operator establishes a maximum allowable operating pressure for a pipeline segment under paragraph (a) of this section, an operator must comply with the additional operation and maintenance requirements as follows:

To address increased risk of a maximum allowable operating pressure based on higher stress levels in the following areas:

Take the following additional step:

(1) Identifying and evaluating threats

Develop a threat matrix consistent with §192.917 to do the following:

(i) Identify and compare the increased risk of operating the pipeline at the increased stress level under this section with conventional operation; and

(ii) Describe and implement procedures used to mitigate the risk.

(2) Notifying the public (i) Recalculate the potential impact circle as defined in §192.903 to reflect use of the alternative maximum operating pressure calculated under paragraph (a) of this section and pipeline operating conditions; and

(ii) In implementing the public education program required under §192.616, perform the following:

(A) Include persons occupying property within 220 yards of the centerline and within the potential impact circle within the targeted audience; and

(B) Include information about the integrity management activities performed under this section within the message provided to the audience.

(3) Responding to an emergency in an area defined as a high consequence

(i) Ensure that the identification of high consequence areas reflects the larger potential impact circle recalculated under paragraph (d)(2)(i) of this section.

area in §192.903 (ii) If personnel response time to mainline valves on either side of the high consequence area exceeds one hour (under normal driving conditions and speed limits) from the time the event is identified in the control room, provide remote valve control through a supervisory control and data acquisition (SCADA) system, other leak detection system, or an alternative method of control.

(iii) Remote valve control must include the ability to close and monitor the valve position (open or closed), and monitor pressure upstream and downstream.

(iv) A line break valve control system using differential pressure, rate of pressure drop or other widely-accepted method is an acceptable alternative to remote valve control.



To address increased risk of a maximum allowable operating pressure based on higher stress levels in the following areas:

Take the following additional step:

(11) Making repairs (continued)

(C) The alternative maximum allowable operating pressure was based on a design factor of 0.67 under paragraph (a) of this section and the failure pressure is less than 1.25 times the alternative maximum allowable operating pressure.

(D) The alternative maximum allowable operating pressure was based on a design factor of 0.56 under paragraph (a) of this section and the failure pressure is less than or equal to 1.4 times the alternative maximum allowable operating pressure.

(iii) If paragraph (d)(11)(ii) of this section does not require immediate repair, repair a defect within one year if any of the following apply:

(A) The defect meets the criteria for repair within one year in §192.933(d).

(B) The alternative maximum allowable operating pressure was based on a design factor of 0.80 under paragraph (a) of this section and the failure pressure is less than 1.25 times the alternative maximum allowable operating pressure.

(C) The alternative maximum allowable operating pressure was based on a design factor of 0.67 under paragraph (a) of this section and the failure pressure is less than 1.50 times the alternative maximum allowable operating pressure.

(D) The alternative maximum allowable operating pressure was based on a design factor of 0.56 under paragraph (a) of this section and the failure pressure is less than or equal to 1.80 times the alternative maximum allowable operating pressure.

(iv) Evaluate any defect not required to be repaired under paragraph (d)(11)(ii) or (iii) of this section to determine its growth rate, set the maximum interval for repair or re-inspection, and repair or re-inspect within that interval.

(e) Is there any change in overpressure protection associated with operating at the alternative

maximum allowable operating pressure? Notwithstanding the required capacity of pressure relieving and limiting stations otherwise required by §192.201, if an operator establishes a maximum allowable operating pressure for a pipeline segment in accordance with paragraph (a) of this section, an operator must: (1) Provide overpressure protection that limits mainline pressure to a maximum of 104 percent of the maximum allowable operating pressure; and (2) Develop and follow a procedure for establishing and maintaining accurate set points for the supervisory control and data acquisition system. [Issued by RIN 2137-AE25, 73 FR 62148, Oct. 17, 2008; Eff. date stayed by 73 FR 72737, Dec. 1, 2008; Amdt. 192-111, 74 FR 62503, Nov. 30, 2009; Amdt. 192-120, 80 FR 12762, Mar. 11, 2015]


294

GUIDE MATERIAL


§192.621 Maximum allowable operating pressure: High-pressure distribution systems.


(a) No person may operate a segment of a high pressure distribution system at a pressure that exceeds the lowest of the following pressures, as applicable: (1) The design pressure of the weakest element in the segment, determined in accordance with Subparts C and D of this part. (2) 60 p.s.i. (414 kPa) gage, for a segment of a distribution system otherwise designed to operate at over 60 p.s.i.g., unless the service lines in the segment are equipped with service regulators or other pressure limiting devices in series that meet the requirements of §192.197(c). (3) 25 p.s.i. (172 kPa) gage in segments of cast iron pipe in which there are unreinforced bell and spigot joints. (4) The pressure limits to which a joint could be subjected without the possibility of its parting. (5) The pressure determined by the operator to be the maximum safe pressure after considering the history of the segment, particularly known corrosion and the actual operating pressures. (b) No person may operate a segment of pipeline to which paragraph (a) (5) of this section applies, unless overpressure protective devices are installed on the segment in a manner that will prevent the maximum allowable operating pressure from being exceeded, in accordance with §192.195. [Amdt. 192-85, 63 FR 37500, July 13, 1998]

GUIDE MATERIAL For high-pressure distribution systems containing steel or plastic pipelines, see §192.619.

§192.623 Maximum and minimum allowable operating pressure:

Low-pressure distribution systems. [Effective Date: 04/26/96]

(a) No person may operate a low-pressure distribution system at a pressure high enough to make unsafe the operation of any connected and properly adjusted low-pressure gas burning equipment. (b) No person may operate a low pressure distribution system at a pressure lower than the minimum pressure at which the safe and continuing operation of any connected and properly adjusted low-pressure gas burning equipment can be assured. [Amdt. 192-75, 61 FR 18512, Apr. 26, 1996 with Amdt. 192-75 Correction, 61 FR 38403, July 24, 1996]

GPTC GUIDE FOR GAS TRANSMISSION, DISTRIBUTION, §192.803 AND GATHERING PIPING SYSTEMS: 2015 Edition SUBPART N


(d) Performance monitoring. The operator may also consider planned or impromptu observation of performance of covered and related tasks by individuals and developing documentation that could be useful in a work performance history review.

3.3 Evaluation categories. The three types of qualifications are as follows. (a) Transitional qualification means qualification in a covered task completed by October 28, 2002, of

an individual who had been performing that task on a regular basis prior to October 26, 1999. (b) Initial qualification means the first qualification of an individual in a covered task that is not

transitional qualification. (c) Subsequent qualification means evaluation of an individual’s qualification to perform a covered task,

after "transitional" or "initial" qualification, at the interval established by the operator. The subsequent qualification process may use different evaluation criteria than used for transitional or initial qualification. The interval for the first subsequent qualification does not need to start until October 28, 2002. Therefore, if an operator chooses October 28, 2002, as the start date for the subsequent qualification interval applicable to previously qualified individuals, the first subsequent qualification interval for those individuals may exceed the intervals established under the operator's written program. However, for qualifications on or after October 28, 2002, the established subsequent evaluation intervals would apply.

Subsequent evaluations may be used as follows. (1) Verify that all necessary changes since the last qualification have been communicated to

affected personnel. (2) Identify qualification concerns. (3) Evaluate the employee’s performance over the preceding interval. 4 CONTRACTORS The operator should review the qualification criteria used by contractors to ensure consistency with its

own criteria.

§192.805 Qualification program.


Each operator shall have and follow a written qualification program. The program shall include provisions to: (a) Identify covered tasks; (b) Ensure through evaluation that individuals performing covered tasks are qualified; (c) Allow individuals that are not qualified pursuant to this subpart to perform a covered task if directed and observed by an individual that is qualified; (d) Evaluate an individual if the operator has reason to believe that the individual's performance of a covered task contributed to an incident as defined in Part 191; (e) Evaluate an individual if the operator has reason to believe that the individual is no longer qualified to perform a covered task; (f) Communicate changes that affect covered tasks to individuals performing those covered tasks; (g) Identify those covered tasks and the intervals at which evaluation of the individual's qualifications is needed; and

GPTC GUIDE FOR GAS TRANSMISSION, DISTRIBUTION, §192.805 AND GATHERING PIPING SYSTEMS: 2015 Edition SUBPART N


(h) After December 16, 2004, provide training, as appropriate, to ensure that individuals performing covered tasks have the necessary knowledge and skills to perform the tasks in a manner that ensures the safe operation of pipeline facilities; and (i) After December 16, 2004, notify the Administrator or a state agency participating under 49 U.S.C. Chapter 601 if the operator significantly modifies the program after the Administrator or state agency has verified that it complies with this section. Notifications to PHMSA may be submitted by electronic mail to [email protected], or by mail to ATTN: Information Resources Manager DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, New Jersey Avenue SE., Washington, DC 20590. [Issued by Amdt. 192-86, 64 FR 46853, Aug. 27, 1999; Amdt. 192-100, 70 FR 10332, Mar. 3, 2005 with Amdt. 192-100 DFR Confirmation, 70 FR 34693, June 15, 2005; Amdt. 192-120, 80 FR 12762, Mar. 11, 2015]

GUIDE MATERIAL

See Cautionary Note at the beginning of Subpart N.

1 GENERAL

An operator may use vendor written programs to meet this regulation. However, the operator should be aware that by adopting a vendor program (including those produced by industry associations and consortiums), it is still responsible for ensuring that the elements of the program meet the requirements of the subpart as applied to its systems, and supplementing the vendor program where it does not. Since the Regulations are applicable to pipeline operators, it is not necessary for contractors to have written programs. In complying with §192.805 requirements, some operators may choose to request that each contractor develop its own written program. If an operator chooses to request written programs from contractors or accept third-party evaluations, the operator should ensure that the contractor’s program requirements are consistent with its own. This may require that copies of the evaluation tools of the contractor or the third-party evaluator be reviewed.

2 ELEMENTS OF THE WRITTEN PROGRAM 2.1 Identification of covered tasks (§192.805(a)).

The operator is responsible for identifying which O&M tasks performed on its facilities are covered tasks based on the four–part test in §192.801(b). Covered tasks may vary among operators.

(a) Four-part test. When applying the four-part test for a covered task and evaluating whether a task is covered, the operator may consider the following definitions.

(1) Performed on a pipeline facility means that the task is performed on part of a facility that is connected to the pipeline system. A task that is performed on a component that is removed from the system is not considered to be a task performed on a pipeline facility. To meet this criterion, the performance of the task should directly affect the pipeline facility.

(2) An operations or maintenance task means a task that is performed on an existing portion of a pipeline facility. Most covered O&M tasks performed in order to comply with these rules are found in Subparts L and M of Part 192. However, some tasks may be found in other subparts (e.g., Subparts E, I, J, and K). Additionally, not all tasks required to comply with Subparts L and M are considered O&M tasks (e.g., tasks involving emergency response, and some tasks related to installation of replacement pipe or components).

(i) An operating task is one that causes a system or a part of a system to function. Opening and closing a valve is an example of an operating task.

GPTC GUIDE FOR GAS TRANSMISSION, DISTRIBUTION, §192.925 AND GATHERING PIPING SYSTEMS: 2015 Edition SUBPART O


§192.925 What are the requirements for using

External Corrosion Direct Assessment (ECDA)? ▌[Effective Date: 10/01/15]

(a) Definition. ECDA is a four-step process that combines preassessment, indirect inspection, direct examination, and post assessment to evaluate the threat of external corrosion to the integrity of a pipeline. (b) General requirements. An operator that uses direct assessment to assess the threat of external corrosion must follow the requirements in this section, in ASME/ANSI B31.8S (incorporated by reference, see §192.7), section 6.4, and in NACE SP0502 (incorporated by reference, see §192.7). An operator must develop and implement a direct assessment plan that has procedures addressing pre-assessment, indirect inspection, direct examination, and post assessment. If the ECDA detects pipeline coating damage, the operator must also integrate the data from the ECDA with other information from the data integration (§192.917(b)) to evaluate the covered segment for the threat of third party damage and to address the threat as required by §192.917(e)(1). (1) Preassessment. In addition to the requirements in ASME/ANSI B31.8S section 6.4 and NACE SP0502, section 3, the plan’s procedures for preassessment must include — (i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a covered segment; and (ii) The basis on which an operator selects at least two different, but complementary indirect assessment tools to assess each ECDA Region. If an operator utilizes an indirect inspection method that is not discussed in Appendix A of NACE SP0502, the operator must demonstrate the applicability, validation basis, equipment used, application procedure, and utilization of data for the inspection method. (2) Indirect examination. In addition to the requirements in ASME/ANSI B31.8S, section 6.4 and in NACE SP0502, section 4, the plan’s procedures for indirect inspection of the ECDA regions must include — (i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a covered segment; (ii) Criteria for identifying and documenting those indications that must be considered for excavation and direct examination. Minimum identification criteria include the known sensitivities of assessment tools, the procedures for using each tool, and the approach to be used for decreasing the physical spacing of indirect assessment tool readings when the presence of a defect is suspected; (iii) Criteria for defining the urgency of excavation and direct examination of each indication identified during the indirect examination. These criteria must specify how an operator will define the urgency of excavating the indication as immediate, scheduled or monitored; and (iv) Criteria for scheduling excavation of indications for each urgency level. (3) Direct examination. In addition to the requirements in ASME/ANSI B31.8S section 6.4 and NACE SP0502, section 5, the plan’s procedures for direct examination of indications from the indirect examination must include — (i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a covered segment; (ii) Criteria for deciding what action should be taken if either: (A) Corrosion defects are discovered that exceed allowable limits (Section 5.5.2.2 of NACE SP0502), or (B) Root cause analysis reveals conditions for which ECDA is not suitable (Section 5.6.2 of NACE SP0502); (iii) Criteria and notification procedures for any changes in the ECDA Plan, including changes that affect the severity classification, the priority of direct examination, and the time frame for direct examination of indications; and



(iv) Criteria that describe how and on what basis an operator will reclassify and reprioritize any of the provisions that are specified in section 5.9 of NACE SP0502. (4) Post assessment and continuing evaluation. In addition to the requirements in ASME/ANSI B31.8S section 6.4 and NACE SP0502, section 6, the plan’s procedures for post assessment of the effectiveness of the ECDA process must include — (i) Measures for evaluating the long-term effectiveness of ECDA in addressing external corrosion in covered segments; and (ii) Criteria for evaluating whether conditions discovered by direct examination of indications in each ECDA region indicate a need for reassessment of the covered segment at an interval less than that specified in §192.939. (See Appendix D of NACE SP0502.) [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan. 15, 2004, Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004 and Amdt. 192-95 Correction, 69 FR 29903, May 26, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006; Amdt. 192-114, 75 FR 48593, Aug. 11, 2010; Amdt. 192-119, 80 FR 168, Jan. 5, 2015; Amdt. 192-120, 80 FR 12762, Mar. 11, 2015]

GUIDE MATERIAL Note: References to NACE throughout this section of guide material are specific to the edition of NACE SP0502 as incorporated by reference (IBR) in §192.7. Abbreviated references are used in guide material below. Example: "NACE 5.2.1" means NACE SP0502, Paragraph 5.2.1 of the IBR edition. See 3 of the guide material under §192.907. 1 PURPOSE External Corrosion Direct Assessment (ECDA) is a methodology to assess the integrity of pipe and pipe

coating that is subject to the threat of external corrosion. ECDA can discover existing external corrosion on steel and other ferrous pipe. A key advantage of ECDA, when compared to in-line inspection (ILI) and pressure testing, is its ability to detect coating damage before corrosion occurs.

2 GENERAL REQUIREMENTS (a) A written ECDA plan is required to be based on the following. (1) Section 192.925. (2) ASME B31.8S-2004, Paragraph 6.4 (see §192.7 for IBR). (3) NACE SP0502. (b) The ECDA plan should include its purpose, objectives, and instructions to personnel. (c) Written procedures are required to address the following four process steps (see §192.925(b)). (1) Pre-assessment. (2) Indirect examination (inspection). (3) Direct examination. (4) Post-assessment and continuing evaluation. (d) Section 192.947(d) requires documents to support decisions, analyses, and processes developed

and used to implement and evaluate the operator’s integrity management program including ECDA. (e) The ECDA plan may reference appropriate sections of other documents (e.g., survey procedures)

instead of including them in the ECDA plan. These documents should be available to personnel performing associated tasks.

(f) For first-time application of ECDA on a covered segment, the written procedure is required to address more restrictive criteria for each step of the ECDA assessment except for post-assessment.


505

1.2 Revisions to the Integrity Management Program (IMP). Copies of revisions to the integrity management program should be kept for documentation. If changes are made to the program as a result of revisions to standards or regulations, copies of the historical and current versions of the standards should be kept. Note that significant changes to the operator’s program require notification to PHMSA-OPS or state pipeline safety authorities. See guide material under §192.949.

1.3 Threat identification and risk assessment. Documentation for threat identification and risk assessment might include the following. (a) Description of the process used for risk analysis. (b) History of risk analysis results. (c) Minutes from subject matter expert meetings. (d) List of threats. 1.4 Baseline assessment plans.

Operators should retain and record the technical basis for changes to their baseline assessment plans. Operators should retain adequate documentation to illustrate how their plans have changed and the technical justification for those changes. Documentation might include historical and current records as follows.

(a) Schedules. (b) Threat lists and assessment methods. (c) Direct assessment plans. (d) Environmental and safety procedures. 2 TRAINING AND QUALIFICATION OF PERSONNEL Documentation for employee training and qualification might include the following. (a) Training curriculum. (b) Training outlines. (c) Training schedules. (d) Sample tests. (e) Employee training records. 3 ONGOING ACTIVITY 3.1 Evaluation and remediation. Documentation for the evaluation and remediation schedule might include the following. (a) List of conditions found. (b) Repairs, monitoring, replacements, or pressure reductions performed. (c) Priority of conditions. (d) Scheduled evaluation or remediation date. (e) Written justification for assigning priority. 3.2 Direct and confirmatory assessment. Documentation for direct and confirmatory assessments might include the following. (a) Procedures for assessment methods. (b) Criteria for evaluating assessment results. (c) Tool selection criteria. (d) Forms or other documentation of field data. 4 REGULATORY CORRESPONDENCE

Documentation of correspondence with PHMSA-OPS and state pipeline safety agencies relating to integrity management issues should be retained.



§192.949 How does an operator notify PHMSA?


An operator must provide any notification required by this subpart by — (a) Sending the notification by electronic mail to [email protected]; or (b) Sending the notification by mail to ATTN: Information Resources Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, 1200 New Jersey Ave. SE., Washington, DC 20590. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan. 15, 2004; RIN 2137-AD77, 70 FR 11135, Mar. 8, 2005; Amdt. 192-103, 72 FR 4655, Feb. 1, 2007; RIN 2137-AE29, 73 FR 16562, Mar. 28, 2008; RIN 2137-AE29 (#2), 74 FR 2889, Jan. 16, 2009; Amdt. 192-120, 80 FR 12762, Mar. 11, 2015]

GUIDE MATERIAL 1 NOTIFICATION INFORMATION See the following sections for information regarding specific notification requirements. (a) Section 192.909, when the operator makes substantial changes to the integrity management

program. Notifications include the following information. (1) Operator name and ID. (2) Description and reason for the program or schedule change. (b) Sections 192.921 and 192.937, when the operator makes use of technologies for assessment

other than internal inspection tools, pressure tests, or direct assessment. Notifications include the following information.

(1) Operator name and ID. (2) Description and rationale for new technology. (3) Where the technology will be used. (4) Procedures for applying the technology. (5) Procedures for qualifying persons performing the assessment and analyzing the results. (c) Section 192.927, when ICDA is used to assess a covered segment with an electrolyte present in

the gas stream. Notifications include the following information. (1) Operator name and ID. (2) Description of system. (3) Justification for using ICDA. (4) How public safety will be maintained.

(d) Section 192.933(a)(1), when the operator cannot meet the schedule and cannot provide safety through temporary pressure reduction. Notifications include the following information.

(1) Operator name and ID. (2) Reason why the schedule cannot be met or temporary pressure reduction cannot be

implemented. (3) How public safety will be maintained. (e) Section 192.933(a)(2), when a pressure reduction exceeds 365 days. Notifications include the

following information. (1) Operator name and ID. (2) Reason for remediation delays. (3) Technical justification that pressure reduction is sufficient for maintaining public safety.

GPTC GUIDE FOR GAS TRANSMISSION, DISTRIBUTION, §192.1013 AND GATHERING PIPING SYSTEMS: 2015 Edition SUBPART P


§192.1013 When may an operator deviate from required

periodic inspections under this part? [Effective Date: 02/12/10]

(a) An operator may propose to reduce the frequency of periodic inspections and tests required in this part on the basis of the engineering analysis and risk assessment required by this subpart. (b) An operator must submit its proposal to the PHMSA Associate Administrator for Pipeline Safety or, in the case of an intrastate pipeline facility regulated by the State, the appropriate State agency. The applicable oversight agency may accept the proposal on its own authority, with or without conditions and limitations, on a showing that the operator’s proposal, which includes the adjusted interval, will provide an equal or greater overall level of safety. (c) An operator may implement an approved reduction in the frequency of a periodic inspection or test only where the operator has developed and implemented an integrity management program that provides an equal or improved overall level of safety despite the reduced frequency of periodic inspections. [Issued by Amdt. 192-113, 74 FR 63906, Dec. 4, 2009 with Amdt. 192-113 Correction, 75 FR 5244, Feb. 2, 2010]

GUIDE MATERIAL 1 IDENTIFY FACILITIES THAT MAY QUALIFY FOR ALTERNATIVE INSPECTION INTERVALS (a) After completing the engineering analysis and risk assessment required by Subpart P, identify

facilities with low risk. (b) Evaluate low-risk facilities for which the alternative inspection interval might apply using past

inspection performance and other supporting documents or information. (c) Identify the specific areas of the Regulations for which the alternative inspection interval is sought. (d) Specify the proposed duration or schedule of events for which the alternative inspection interval is

sought. 2 ACQUIRING REGULATORY APPROVAL (a) Determine which regulatory agency (PHMSA-OPS or state) has approval authority to grant

alternative inspection intervals. (b) Regulatory agency requirements for granting alternative inspection intervals may vary, but at a

minimum, the operator should provide the following. (1) Name, street, mailing address, and telephone number of the operator, or an individual

designated as an agent of the operator. (2) Detailed description of the pipeline facilities for which the alternative inspection interval is

sought. (3) A cite to the regulation from which the alternative inspection interval is sought. (4) Detailed description of the proposed alternative inspection interval, including past inspection

performance and other supporting documents or information. This should include analyses, data, or test results supporting the position that the alternative inspection interval will maintain or improve the safety level of the overall system. Indicate any added practices that would be implemented.

(5) Proposed duration or schedule of events for which the alternative inspection interval is sought. (6) Description of plans and performance metrics that will be used to evaluate the effectiveness of

the alternative inspection interval in maintaining the current level of pipeline safety.



(7) A statement describing the basis for seeking alternative compliance with the specified regulations and how the overall Distribution Integrity Management Program (DIMP) will provide an equal or improved level of safety.

(8) Sections in the DIMP written plan for implementing and evaluating the pipeline safety effectiveness of the alternative inspection interval.

3 IMPLEMENTING APPROVED ALTERNATIVE INSPECTION INTERVALS (a) Once the alternative inspection interval has been approved, it is important to review the

waiver/special permit to ensure that the conditions and limitations are understood. (b) The operator should ensure that employees are trained and qualified so that they understand and

can apply the terms and conditions of the waiver/special permit, including the reporting requirements.

(c) Operators who are granted special permits are reminded that special permits may include terms and conditions specified by the regulatory agency (PHMSA-OPS or state) that are not optional.

(d) The regulatory agency requirements for granting alternative inspection intervals might require modification to the operator’s procedural manual for operations, maintenance, and emergencies as it applies to the waiver/special permit. The agency might also require periodic reporting.

§192.1015 What must a master meter or small liquefied petroleum gas (LPG)

operator do to implement this subpart? [Effective Date: 02/12/10]

(a) General. No later than August 2, 2011 the operator of a master meter system or a small LPG operator must develop and implement an IM program that includes a written IM plan as specified in paragraph (b) of this section. The IM program for these pipelines should reflect the relative simplicity of these types of pipelines. (b) Elements. A written integrity management plan must address, at a minimum, the following elements: (1) Knowledge. The operator must demonstrate knowledge of its pipeline, which, to the extent known, should include the approximate location and material of its pipeline. The operator must identify additional information needed and provide a plan for gaining knowledge over time through normal activities conducted on the pipeline (for example, design, construction, operations or maintenance activities). (2) Identify threats. The operator must consider, at minimum, the following categories of threats (existing and potential): Corrosion, natural forces, excavation damage, other outside force damage, material or weld failure, equipment failure, and incorrect operation. (3) Rank risks. The operator must evaluate the risks to its pipeline and estimate the relative importance of each identified threat. (4) Identify and implement measures to mitigate risks. The operator must determine and implement measures designed to reduce the risks from failure of its pipeline. (5) Measure performance, monitor results, and evaluate effectiveness. The operator must monitor, as a performance measure, the number of leaks eliminated or repaired on its pipeline and their causes. (6) Periodic evaluation and improvement. The operator must determine the appropriate period for conducting IM program evaluations based on the complexity of its pipeline and changes in factors affecting the risk of failure. An operator must re-evaluate its entire program at least every five years. The operator must consider the results of the performance monitoring in these evaluations. (c) Records. The operator must maintain, for a period of at least 10 years, the following records: (1) A written IM plan in accordance with this section, including superseded IM plans;



(2) Documents supporting threat identification; and (3) Documents showing the location and material of all piping and appurtenances that are installed after the effective date of the operator’s IM program and, to the extent known, the location and material of all pipe and appurtenances that were existing on the effective date of the operator’s program. [Issued by Amdt. 192-113, 74 FR 63906, Dec. 4, 2009 with Amdt. 192-113 Correction, 75 FR 5244, Feb. 2, 2010]

GUIDE MATERIAL See Guide Material Appendix G-192-8.


516

Reserved

Form PHMSA F 7100.1-1 (rev 1-2011) Reproduction of this form is permitted. Page 1 of 3

NOTICE: This report is required by 49 CFR Part 191. Failure to report may result in a civil penalty not to exceed $100,000 for OMB No. 2137-0522 each violation for each day the violation continues up to a maximum of $1,000,000 as provided in 49 USC 60122. Expiration Date 10/31/2016

U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration

ANNUAL REPORT FOR CALENDAR YEAR 20___

GAS DISTRIBUTION SYSTEM

INITIAL REPORT SUPPLEMENTAL REPORT

A federal agency may not conduct or sponsor, and a person is not required to respond to, nor shall a person be subject to a penalty for failure to comply with a collection of information subject to the requirements of the Paperwork Reduction Act unless that collection of information displays a current valid OMB Control Number. The OMB Control Number for this information collection is 2137-0522. Public reporting for this collection of information is estimated to be approximately 16 hours per submission, including the time for reviewing instructions, gathering the data needed, and completing and reviewing the collection of information. All responses to this collection of information are mandatory. Send comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing this burden to: Information Collection Clearance Officer, PHMSA, Office of Pipeline Safety (PHP-30) 1200 New Jersey Avenue, SE, Washington, D.C. 20590.

PART A - OPERATOR INFORMATION DOT USE ONLY 1. NAME OF OPERATOR

3. OPERATOR'S 5 DIGIT IDENTIFICATION NUMBER

/ / / / / / 2. LOCATION OF OFFICE WHERE ADDITIONAL INFORMATION MAY BE OBTAINED

4. HEADQUARTERS NAME & ADDRESS, IF DIFFERENT

Number and Street Number and Street City and County City and County State and Zip Code State and Zip Code 5. STATE IN WHICH SYSTEM OPERATES:/ / / (provide a separate report for each state in which system operates)

PART B - SYSTEM DESCRIPTION Report miles of main and number of services in system at end of year. 1. GENERAL STEEL

PLASTIC

CAST/ WROUGHT

IRON DUCTILE

IRON

COPPER OTHER SYSTEM TOTAL UNPROTECTED CATHODICALLY

PROTECTED BARE COATED BARE COATED

MILES OF MAIN

NO. OF SERVICES

2. MILES OF MAINS IN SYSTEM AT END OF YEAR

MATERIAL UNKNOWN 2" OR LESS OVER 2" THRU 4"

OVER 4" THRU 8"

OVER 8" THRU 12” OVER 12" SYSTEM

TOTALS

STEEL

DUCTILE IRON

COPPER

CAST/WROUGHT IRON

PLASTIC 1. PVC

2. PE

3. ABS

4. OTHER PLASTIC

OTHER

SYSTEM TOTALS

3. NUMBER OF SERVICES IN SYSTEM AT END OF YEAR AVERAGE SERVICE LENGTH FEET


MATERIAL UNKNOWN 1" OR LESS OVER 1" THRU 2"

OVER 2" THRU 4"

OVER 4" THRU 8” OVER 8" TOTAL

STEEL

DUCTILE IRON

COPPER

CAST/WROUGHT IRON

PLASTIC 1. PVC

2. PE

3. ABS

4. OTHER PLASTIC

OTHER

SYSTEM TOTALS

4. MILES OF MAIN AND NUMBER OF SERVICES BY DECADE OF INSTALLATION UN-

KNOWN PRE-1940

1940-1949

1950- 1959

1960- 1969

1970- 1979

1980- 1989

1990- 1999

2000- 2009

2010- 2019 TOTAL

MILES OF MAIN

NUMBER OF SERVICES

PART C - TOTAL LEAKS AND HAZARDOUS LEAKS ELIMINATED/REPAIRED DURING YEAR

CAUSE OF LEAK

Mains Services Total Hazardous Total Hazardous

CORROSION

NATURAL FORCES

EXCAVATION DAMAGE

OTHER OUTSIDE FORCE DAMAGE

MATERIAL OR WELDS

EQUIPMENT

INCORRECT OPERATIONS

OTHER

NUMBER OF KNOWN SYSTEM LEAKS AT END OF YEAR SCHEDULED FOR REPAIR

PART D – EXCAVATION DAMAGE PART E – EXCESS FLOW VALVE (EFV) DATA Number of Excavation Damages __________________ Number of Excavation Tickets __________________

Total Number Of EFVs on Single-family Residential Services Installed During Year _________ Estimated Number of EFVs In System At End Of Year _________


PART F - TOTAL NUMBER OF LEAKS ON FEDERAL LAND REPAIRED OR SCHEDULED FOR REPAIR

PART G - PERCENT OF UNACCOUNTED FOR GAS

Unaccounted for gas as a percent of total input for the12 months ending June 30 of the reporting year.

[(Purchased gas + produced gas) minus (customer use + company use + appropriate adjustments)] divided by (purchased gas + produced gas) equals percent unaccounted for.

Input for year ending 6/30________________________ %.

(Type or print) Preparer’s Name and Title Area Code and Telephone Number Preparer’s email address Area Code and Facsimile Number Name and Title of Person Signing Area Code and Telephone Number Authorized Signature

PART I - PREPARER AND AUTHORIZED SIGNATURE

PART H - ADDITIONAL INFORMATION

Blank Sheet

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

567

1.14 OTHER DOCUMENTS

AGA X69804 Historical Collection of Natural Gas Pipeline Safety Regulations [Available from GPTC Secretary at AGA.]

Forward Editorial Notes

AGA XK0101 Purging Principles and Practice §192.629 §192.727

AGA XL0702 Distribution Pipe: Repair and Replacement Decision Manual §192.465 §192.703

GMA G-192-18

AGA XL1001 Classification of Locations for Electrical Installations in Gas Utility Areas

§192.163

AGA XQ0005 Odorization Manual §192.625

API RP 500 Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class 1, Division 1 and Division 2

§192.163

API RP 1102 Steel Pipelines Crossing Railroads and Highways §192.103 GMA G-192-15

API RP 1117 Movement of In-Service Pipelines §192.103 §192.703

API RP 1166 Excavation Monitoring and Observation §192.614

API RP 1168 Pipeline Control Room Management §192.631

API Std 1163 In-Line Inspection Systems Qualification Standard GMA G-192-14

AREMA Manual for Railway Engineering, Chapter 1 – Roadway and Ballast (for Part 5 – Pipelines)

GMA G-192-15

ASCE 428-5 Guidelines for the Seismic Design of Oil and Gas Pipeline Systems (Discontinued)

§192.103

ASME B31.1 Power Piping §192.141

ASME B31.2 Fuel Gas Piping (Withdrawn 1988; Replaced by NFPA 54/ANSI Z223.1)

ASME B31.3 Process Piping §192.141

ASME B31.4 Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids

ASME B31.5 Refrigeration Piping and Heat Transfer Components §192.141

ASME B31.8S-2010 Managing System Integrity of Gas Pipelines §192.929

ASME B31.9 Building Services Piping

Table Continued



1.14 OTHER DOCUMENTS (Continued)

ASME B31Q Pipeline Personnel Qualification §192.805

ASME CRTD Vol. 57 Determining the Yield Strength of In-Service Pipe §192.107

ASME CRTD-91 Applications Guide for Determining the Yield Strength of In-Service Pipe by Hardness Evaluation

§192.107

ASME Guide SI-1 ASME Orientation and Guide for Use of SI (Metric) Units GMA G-192-M

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

§192.613

ASNT ILI-PQ In-line Inspection Personnel Qualification and Certification GMA G-192-14

ASTM D1586 Standard Test Method for Standard Penetration Test (SPT) and Split-Barrel Sampling of Soils

GMA G-192-15A

ASTM D2487 Standard Practice for Classification of Soils for Engineering Purposes (Unified Soil Classification System)

GMA G-192-15A

ASTM D2774 Standard Practice for Underground Installation of Thermoplastic Pressure Piping

§192.321

ASTM D6273 Standard Test Methods for Natural Gas Odor Intensity §192.625

ASTM E84 Test Method for Surface Burning Characteristics of Building Materials

§192.163

AWS A3.0 Standard Welding Terms and Definitions §192.3 §192.221

CGA "Best Practices" Guide §192.325 §192.361 §192.614

One Call Systems International (OCSI) Resource Guide §192.614

CoGDEM Gas Detection and Calibration Guide GMA G-192-11 GMA G-192-11A

GRI-91/0283 Guidelines for Pipelines Crossing Railroads §192.103 GMA G-192-15

GRI-91/0284 Guidelines for Pipelines Crossing Highways §192.103 GMA G-192-15

GRI-91/0285 Technical Summary and Database for Guidelines for Pipelines Crossing Railroads and Highways

GMA G-192-15

GRI-91/0285.1 Executive Summary: Technical Summary and Database for Guidelines for Pipelines Crossing Railroads and Highways

GMA G-192-15

GRI-95/0171 State-of-the-Art Review and Analysis of Guided Drilling Systems

GMA G-192-15B

Table Continued



GUIDE MATERIAL APPENDIX G-192-8 (See §§192.1001, 192.1003, 192.1005, 192.1007, 192.1009, 192.1011, 192.1015, and

Guide Material Appendix G-192-8A)

DISTRIBUTION INTEGRITY MANAGEMENT PROGRAM (DIMP)

CONTENTS 1 INTRODUCTION 1.1 Scope. 1.2 Glossary of abbreviations. 1.3 How to use this guide material. 1.4 Overview. 2 ELEMENTS OF A DISTRIBUTION INTEGRITY MANAGEMENT PROGRAM 2.1 General. 2.2 Develop and implement a written plan. 3 KNOWLEDGE 3.1 General. 3.2 DOT Annual Report information. 3.3 Additional information. 3.4 Knowledge of what is physically happening in the system. 3.5 Documentation. 4 IDENTIFY THREATS 4.1 Primary threats. 4.2 Identify threats. 4.3 Sample threat identification method. 5 EVALUATE AND RANK RISK 5.1 General. 5.2 Information evaluation. 5.3 Methods. 5.4 Example of risk evaluation. 5.5 Validation. 6 IDENTIFY AND IMPLEMENT MEASURES TO ADDRESS RISKS 6.1 General. 6.2 Leak Management Program. 6.3 A/A actions. 7 MEASURE PERFORMANCE, MONITOR RESULTS, AND EVALUATE EFFECTIVENESS 7.1 Guidelines for developing performance measures. 7.2 Examples of performance measures. 8 PERIODIC EVALUATION AND IMPROVEMENT 8.1 Review of the written plan. 8.2 Review of effectiveness. 9 REPORT RESULTS


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10 REPORT FITTING FAILURES 11 SAMPLE DIMP APPROACHES 11.1 SME approach. 11.2 Mathematical approach.



1 INTRODUCTION 1.1 Scope. (a) This guide material is intended to assist operators with development of a Distribution Integrity

Management Program (DIMP), including the written plan, and compliance with Federal Regulations §§192.1001, 192.1003, 192.1005, 192.1007, 192.1009, 192.1011, and 192.1015 on DIMP. It provides operators with practices that may be considered as they develop and maintain a DIMP specific to their gas distribution systems.

(b) Distribution pipeline systems and associated operating practices can vary widely. Examples of system differences include: materials used, age, manner of construction, operation and maintenance practices, and operating environments (natural and man-made). This guidance recognizes that there is wide diversity among distribution systems and is therefore flexible, allowing operators to identify considerations dealing with their unique threats and to select actions suited to their specific needs.

(c) The options in this guidance are intended to provide the operator with a selection of possible choices to use in improving the integrity of its distribution system. Operators may not need to consider or perform every step presented. It is not intended that an operator evaluate every option or provide justification or reasons why options were not implemented.

(d) Section 192.1015 imposes different requirements for small liquefied petroleum gas (LPG) operators (i.e., those serving fewer than 100 customers from a single source) and master meter operators. Since these pipeline systems are less complex, the integrity management requirements are simplified. The appropriate portions of this guide material are valid for those operators. PHMSA-OPS has published "Guidance for Master Meter and Small Liquefied Petroleum Gas Pipeline Operators" to assist operators of these systems to implement requirements of the DIMP rule, which can be found at:

primis.phmsa.dot.gov/dimp/docs/GuidanceForMasterMeterAndSmallLiquefiedPetroleumGas PipelineOperators_11_09.pdf. 1.2 Glossary of Abbreviations.

Abbreviation Meaning A/A additional or accelerated (actions) CP cathodic protection DIMP Distribution Integrity Management Program LPG liquefied petroleum gas PE polyethylene SCADA supervisory control and data acquisition SDR standard dimension ratio SME subject matter expert

1.3 How to use this guide material.

The guide material is organized to coincide with the seven required elements of a DIMP. The order in which the guidance is presented does not imply the order in which it should be applied. However, the operator needs to address each element in some way. Once an operator determines how it can best accomplish distribution system integrity, the guide material may be used to support or direct the operator’s approach. The operator is cautioned that the guide material may not anticipate all conditions that may be encountered, and the operator is not restricted from using other methods to comply with the Regulations.

Two sample DIMP approaches are given in Section 11.



1.4 Overview. (a) The objective of a DIMP is to manage the integrity of a gas distribution system. As discussed in

detail in Section 5, an essential part of a DIMP is a risk evaluation of the distribution system. One approach to risk evaluation is to group facilities by common traits or problems, and then perform a risk ranking. This process allows the grouping of facilities that experience similar threats to be risk-ranked together. Then, if necessary, attention can be focused on developing measures that address the greatest risks.

(b) After identifying the problems, the operator should consider the concept of grouping facilities when first developing its DIMP. Such groupings could significantly affect how the operator assembles data about its system (see Section 3) and how it approaches its threat analysis (see Section 4).

(c) The operator should also recognize that the development of the DIMP may be an iterative (or repeating) process. That means each time a cycle (e.g., gather knowledge, identify threats, rank risks, take action to reduce risk, measure performance) is completed, areas needing additional data, analyses, or actions may become apparent. For example, the initial general knowledge of the system may be used to group facilities, identify the applicable threats, and begin the risk analysis. In attempting to complete the risk analysis, the operator may determine the need for additional information. The operator may also determine that the facility groupings need to be redefined, such as by subdividing groups or combining groups.

2 ELEMENTS OF A DISTRIBUTION INTEGRITY MANAGEMENT PLAN 2.1 General. Seven elements have been identified as the essential components of a DIMP, except as modified for

those operators identified in §192.1015(a). Collectively, these elements establish a program that should reasonably manage the integrity of distribution pipeline systems on a going-forward basis. These elements are as follows.

(a) Knowledge (see Section 3). (b) Identify threats (see Section 4). (c) Evaluate and rank risk (see Section 5). (d) Identify and implement measures to address risks (see Section 6). (e) Measure performance, monitor results, and evaluate effectiveness (see Section 7). (f) Periodic evaluation and improvement (see Section 8). (g) Report results, except for master meter and small LPG operators (see Section 9). 2.2 Develop and implement a written plan. Federal Regulations require that each distribution operator prepare and implement a written plan as a

primary component of its DIMP. The function of the plan is to document how each of the applicable seven elements will be addressed and implemented. The plan should be complete and address required elements by the implementation dates in §§192.1005 and 192.1015. The plan should be concise, but still be sufficient for operator personnel to understand and implement the program on a consistent basis, and is not intended to include extensive technical justifications or detailed process descriptions.

3 KNOWLEDGE 3.1 General. (a) Information, such as the materials and type of construction, the operating conditions of the pipe or

facility, and other relevant factors within the surroundings in which the system operates, is referred to as the "knowledge of the distribution system."


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(3) Ratio of no-show tickets to total tickets received by the operator. A no-show ticket is one that was not responded to by the locators within the allowed time.

(4) Failure by notification center to accurately transmit tickets to the operator. (5) Damages by cause, facility type (mains, services), and responsible party. Cause categories

may include the following. (i) Excavator’s failure to call. (ii) Excavator’s failure to provide accurate ticket information (e.g., wrong address). (iii) Operator’s failure to mark. (iv) Operator’s failure to mark accurately. (v) Excavator’s failure to wait required time for marking. (vi) Excavator’s failure to protect marks. (vii) Excavator’s failure to utilize precaution when excavating within the tolerance zone. (viii) Excavator’s failure to properly support and protect facility. (6) Leaks or failures on previously damaged pipe. (7) Repairs implemented as a result of first / second / third-party damage prior to leak or failure. (8) Excavation notices versus number of locates (not all notices will require an actual locate). (9) Locates timely or untimely made. (10) Negative callbacks timely or untimely made if state law, the one-call center, or another entity

requires such calls. (11) Mis-locates later identified. (d) Other outside force damage. (1) Leaks or failures caused, or repairs necessitated, by vandalism. (2) Leaks or failures caused, or repairs necessitated, by vehicular damage. (3) Instances of damage that is secondary to non-pipeline fire or explosion. (4) Leaks or failures on previously damaged pipe. (5) Leaks, failures, damage, or movement caused by blasting. (6) Leaks, failures, damage, or movement caused by heavy vehicle traffic over or near pipelines. (e) Material or welds. (1) Pipe failures during pressure tests. (2) Joint failures during pressure tests. (3) In-service pipe or joint failures (not caused by outside force or excavation damage). (4) Production joints rejected by an inspector other than the joiner. (5) Joiners failing re-qualification. (f) Equipment failure. (1) Regulator failures. (2) Relief valve failures. (3) Seal, gasket or O-ring failures. (4) Regulators or relief valves found with set points outside of acceptable range. (5) Emergency valves found inoperable. (6) SCADA failures, system upsets, or false readings. (g) Incorrect operations. (1) Service outages due to operator error. (2) Odor tests finding insufficient odorant. (3) Response times to leak or odor calls. (4) Hazardous leaks make safe or repair times. (h) Other. Case-by-case determination. 8 PERIODIC EVALUATION AND IMPROVEMENT Periodic review and evaluation of DIMP is an integral part of the process. This should include at least

two activities. First, a review of the written plan content to ensure it remains accurate and appropriate. Second, the success and effectiveness of risk management techniques or practices or A/A actions adopted to respond to specific threats should be analyzed.



8.1 Review of the written plan. (a) The plan should be periodically reviewed at an interval determined to be appropriate by the

operator and updated on an as-needed basis. Consideration should be given to reviewing this plan on a frequency similar to that used for other operational plans and procedures. For example, operating and maintenance manuals and public awareness programs are required by regulation to be reviewed annually, so it may be convenient to schedule review of the written plan at the same time.

(b) The review should include verifying, and updating as needed, content such as any contact information contained in the plan, names or numbers of designated forms, information storage locations, action schedules, etc. This is also a good time to review experience with the plan and consider revising any parts that users have found confusing or difficult to implement.

(c) Another reasonable time for plan review and updating may be after a plan milestone has been achieved. For example, if a major pipe replacement program was being conducted under the DIMP, and that project has been completed, the plan may need modification to reflect that this work is no longer ongoing. This may also be a good time to determine whether there are other risks that should now be given higher priority.

(d) Other plan revisions may be appropriate if review of performance measures concludes that a change of approach is warranted, such as selection of a different performance measure, or of a different risk management technique or practice.

(e) The operator should maintain a record demonstrating that the plan review was performed even if no changes were made.

8.2 Review of effectiveness. (a) The data collected for a performance measure should be periodically reviewed to determine if the

risk management technique or practice (A/A action) implemented is effective. A DIMP should show that the risks it addresses are being managed effectively.

(b) During review, the data that supports the performance measure for a risk management technique or practice (A/A action) should be collected and analyzed. Analysis methods may range from simple side-by-side comparisons of before-and-after data to sophisticated statistical data processing. The analysis should examine whether the evidence indicates the practice or action is or is not managing the targeted risk. Decisions are then made on whether to continue, or discontinue, with the action, accelerate or decelerate its pace, modify how it is being implemented, or choose another action. It is not required that a review always find that a particular risk management technique or practice is either effective or ineffective. It is acceptable to conclude that it is too soon to tell, or that currently there is insufficient data to tell how well an action is working.

(c) The analysis should also examine if the performance measure selected is providing information useful in analyzing the impact of the practice or action. If the impact is unclear, consider including other data in the review, or selecting a different performance measure.

(d) The frequency of review may depend on the time frame within which the operator anticipates that the A/A action will produce meaningful results. For example, one construction season may be enough to assess if additional damage prevention activities are noticeably reducing the frequency of dig-ins. On the other hand, it may take years to determine if changes in corrosion control practices are having an impact. It is recommended that the operator establish a review period appropriate for the performance measure. The interval should not exceed five years for any particular performance measure for consistency with the maximum allowed interval for complete program reevaluation.

9 REPORT RESULTS Except for master meter and small LPG operators, four performance measures are required by

§192.1007(g) to be reported to PHMSA on the operator’s annual report and to the state, as applicable. State regulations may contain additional reporting requirements. The operator should ensure that the information needed to complete those reports is being collected and is available when needed.