GPTC Z380.1 - Addendum No. 8 - 2007 - American Gas Association

September 26, 2007 

Dear Guide Purchaser, 

Paul Cabot, C.G.E. 

GPTC Secretary 

(202) 824-7312 

Fax (202) 824-9122 

pcabot@aga.org 

Enclosed is Addendum No. 8 to ANSI GPTC Z380, Guide for Gas Transmission and Distribution 

Piping Systems, 2003 Edition. Your purchase of the 2003 edition entitles you to receive all addenda. 

Addenda are formatted to enable the replacement of pages in your Guide with the updated enclosed 

pages. Please follow the table on page 2. 

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

BLANK

GPTC GUIDE FOR GAS TRANSMISSION AND DISTRIBUTION PIPING SYSTEMS 

2003 EDITON 

ADDENDUM NO. 8, April 2007 

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, and use of a block symbol (�) where needed. The Federal 

Regulations were changed by two amendment actions that affected nine sections of the Guide. Four 

transactions affected five 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 affected 23 sections of the Guide. 

The following table shows the affected sections, the pages to be removed, and their replacement pages. 

1

FS Amendment - Amdt. Number 

New or Updated GM - TR Number 

GM Under Review - GMUR 

Editorial Update - EU 

Guide Section Reason For Change Pages to be Removed Replacement Pages 

Title Page EU i/ii i/ii 

Table of Contents EU vii/viii vii/viii 

Historical Reconstruction EU, Amdts 192-103 xxiii/xxiv thru 

xxiii/xxiv thru 

of Part 192 

[Amended], 192-104 xxx(a)/xxx(b) 

xxx(a)/xxx(b) 

Historical Record of Amdts 192-103 

xlix/l thru lix/lx xlix/l thru lix/lx 

Amendments to Part 192 

[Amended], 192-104 

Membership List EU 

Subpart A 192.1 EU, Amdt 192-103 

[Amended] 

11/12 thru 21/22 & 

25/26 

11/12 thru 21/22 & 

25/26 

192.3 EU 

192.7 EU, Amdt 192-103 

[Amended] 

192.10 EU 28(a)/28(b) 28(a)/28(b) 

192.11 EU 

Subpart C 192.121 EU 43/44 43/44 

Subpart D 192.141 EU 49/50 thru 53/54 49/50 thru 53/54 

192.143 EU, Amdt 192-104 

192.147 EU 

Subpart E 192.227 Amdt 192-103 

[Amended] 

89/90 89/90 

Subpart I 192.471 EU 157/158 thru 157/158 thru 

192.475 EU, TR03-17 166(a)/166(b) 166(c)/166(d) 

192.476 Amdt 192-104 

192.485 EU 

Subpart J 192.505 EU, TR04-20 169/170 169/170 

Subpart M 192.727 EU, Amdt 192-103 237/238 thru 241/242 237/238 thru 241/242 

[Amended], TR06-18 

192.736 EU 

Subpart O 192.903 EU, Amdt 192-103 262(i)/262(j) & 

[Amended] 

262(k)/262(l) 

192.939 EU 262(am)/262(an) thru 

262(au)/262(av) 

192.945 TR04-54 

192.949 Amdt 192-103 

[Amended] 

192.951 Amdt 192-103 

[Amended] 

GMA G-191-3 EU PHMSA form dated 

03/05 for Distribution 

System Annual Report 

GMA G-192-1 EU, TR03-17, TR04-54 313/314 thru 

326(d-1)/326(d-2) 

2 

262(i)/262(j) & 

262(k)/262(l) 

262(am)/262(an) thru 

262(au)/262(av) 

PHMSA form dated 

12/05 for Distribution 

System Annual Report 

313/314 thru 

326(d-1)/326(d-2)

Guide for 

Gas Transmission 

and 

Distribution Piping 

Systems 

GPTC Z380.1 - 2003 

Addendum No. 8 – 2007 

Author: 

Gas Piping Technology Committee (GPTC) Z380 

Accredited by ANSI 

Approved by 

American National Standards Institute (ANSI) 

April 23, 2007 

April 2007 

an American National Standard 

i 

Secretariat: 

American Gas Association 

ANSI/GPTC Z380.1-2003 

Catalog Number: X603068

GPTC GUIDE FOR GAS TRANSMISSION AND 

DISTRIBUTION PIPING SYSTEMS: 2003 Edition 

PLEASE NOTE 

Addenda to this Guide will also be issued in loose-leaf format so that users will be able 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 subscription service, GPTC (using AGA as Secretariat) will try to keep subscribers 

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. However, the GPTC assumes no responsibility in the event the material that is 

automatically mailed to subscribers never reaches its destination, or is delivered late. Otherwise, the 

subscriber is reminded that the changes to the Regulations can be timely noted 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. 

Copyright 2003 

THE AMERICAN GAS ASSOCIATION 

400 N. Capitol St., NW 

Washington, DC 20001 

All Rights Reserved 

Printed in U.S.A. 

Addendum No. 1, September 2004 ii



192.473 External corrosion control: Interference currents.................................................... 157 

192.475 Internal corrosion control: General.......................................................................... 158 

192.476 Internal corrosion control: Design and construction of transmission line............... 161 

192.477 Internal corrosion control: Monitoring...................................................................... 162 

192.479 Atmospheric corrosion control: General ................................................................. 162 

192.481 Atmospheric corrosion control: Monitoring ............................................................. 163 

192.483 Remedial measures: General ................................................................................. 164 

192.485 Remedial measures: Transmission lines................................................................ 165 

192.487 Remedial measures: Distribution lines other than cast 

iron or ductile iron lines ..............................................................................166(a) 

192.489 Remedial measures: Cast iron and ductile iron pipelines ..................................166(a) 

192.490 Direct Assessment...............................................................................................166(b) 

192.491 Corrosion control records....................................................................................166(b) 

SUBPART J -- TEST REQUIREMENTS .......................................................................................... 167 

192.501 Scope....................................................................................................................... 167 

192.503 General requirements.............................................................................................. 167 

192.505 Strength test requirements for steel pipeline to 

operate at a hoop stress of 30 percent or more of SMYS ............................ 168 

192.507 Test requirements for pipelines to operate at a hoop 

stress less than 30 percent of SMYS and at or above 100 p.s.i.g................ 171 

192.509 Test requirements for pipelines to operate below 100 p.s.i.g. ............................... 171 

192.511 Test requirements for service lines ......................................................................... 172 

192.513 Test requirements for plastic pipelines ................................................................... 172 

192.515 Environmental protection and safety requirements................................................ 173 

192.517 Records.................................................................................................................... 176 

SUBPART K -- UPRATING .............................................................................................................. 177 

192.551 Scope....................................................................................................................... 177 

192.553 General requirements.............................................................................................. 177 

192.555 Uprating to a pressure that will produce a hoop stress 

of 30 percent or more of SMYS in steel pipelines ......................................... 179 

192.557 Uprating: Steel pipelines to a pressure that will produce a hoop stress less 

than 30 percent of SMYS: plastic, cast iron, and ductile iron pipelines........ 181 

SUBPART L -- OPERATIONS.......................................................................................................... 185 

192.601 Scope....................................................................................................................... 185 

192.603 General provisions................................................................................................... 185 

192.605 Procedural manual for operations, maintenance, and emergencies ..................... 186 

192.607 (Removed and reserved) ........................................................................................ 193 

192.609 Change in class location: Required study............................................................... 194 

192.611 Change in class location: Confirmation or revision of 

maximum allowable operating pressure........................................................ 194 

192.612 Underwater inspection and re-burial of pipelines 

in the Gulf of Mexico and its inlets ................................................................. 195 

192.613 Continuing surveillance ........................................................................................... 196 

192.614 Damage prevention program ..............................................................................197(b) 

192.615 Emergency plans..................................................................................................... 203 

192.616 Public awareness .................................................................................................... 211 

192.617 Investigation of failures............................................................................................ 212 

192.619 What is the maximum allowable operating pressure for steel 

or plastic pipelines?........................................................................................ 214 

192.621 Maximum allowable operating pressure: High-pressure 

distribution systems........................................................................................ 215 

192.623 Maximum and minimum allowable operating pressure: Low-pressure 

distribution systems........................................................................................ 216 

Addendum No. 8, April 2008 vii



192.625 Odorization of gas.................................................................................................... 217 

192.627 Tapping pipelines under pressure........................................................................... 219 

192.629 Purging of pipelines ................................................................................................. 221 

SUBPART M -- MAINTENANCE ...................................................................................................... 223 

192.701 Scope....................................................................................................................... 223 

192.703 General .................................................................................................................... 223 

192.705 Transmission lines: Patrolling ................................................................................. 226 

192.706 Transmission lines: Leakage surveys..................................................................... 228 

192.707 Line markers for mains and transmission lines ...................................................... 229 

192.709 Transmission lines: Record keeping....................................................................... 230 

192.711 Transmission lines: General requirements for repair procedures.......................... 230 

192.713 Transmission lines: Permanent field repair of imperfections 

and damages.................................................................................................. 231 

192.715 Transmission lines: Permanent field repair of welds.............................................. 233 

192.717 Transmission lines: Permanent field repair of leaks............................................... 233 

192.719 Transmission lines: Testing of repairs .................................................................... 234 

192.721 Distribution systems: Patrolling ............................................................................... 234 

192.723 Distribution systems: Leakage surveys ................................................................. 236 

192.725 Test requirements for reinstating service lines ....................................................... 238 

192.727 Abandonment or deactivation of facilities ............................................................... 238 

192.729 (Removed) ............................................................................................................... 241 

192.731 Compressor stations: Inspection and testing of relief devices............................... 241 

192.733 (Removed) ............................................................................................................... 241 

192.735 Compressor stations: Storage of combustible materials........................................ 242 

192.736 Compressor stations: Gas detection....................................................................... 242 

192.737 (Removed) ............................................................................................................... 243 

192.739 Pressure limiting and regulating stations: Inspection and testing .......................... 243 

192.741 Pressure limiting and regulating stations: Telemetering or 

recording gauges............................................................................................ 245 

192.743 Pressure limiting and regulating stations: Testing of 

relief devices................................................................................................... 247 

192.745 Valve maintenance: Transmission lines ................................................................. 248 

192.747 Valve maintenance: Distribution systems............................................................... 249 

192.749 Vault maintenance................................................................................................... 250 

192.751 Prevention of accidental ignition ............................................................................. 252 

192.753 Caulked bell and spigot joints ................................................................................. 255 

192.755 Protecting cast-iron pipelines .................................................................................. 256 

192.761 (Removed) ............................................................................................................... 256 

SUBPART N -- QUALIFICATION OF PIPELINE PERSONNEL..................................................... 259 

192.801 Scope....................................................................................................................... 259 

192.803 Definitions ................................................................................................................ 260 

192.805 Qualification program ..........................................................................................262(a) 

192.807 Recordkeeping......................................................................................................262(f) 

192.809 General ................................................................................................................262(g) 

SUBPART O -- PIPELINE INTEGRITY MANAGEMENT.............................................................262(i) 

192.901 What do the regulations in this subpart cover? ...................................................262(i) 

192.903 What definitions apply to this subpart? ................................................................262(j) 

192.905 How does an operator identify a high consequence area?...............................262(m) 

192.907 What must an operator do to implement this subpart? .................................. 262(n-5) 

192.909 How can an operator change its integrity management program?....................262(p) 

Addendum No. 7, December 2006 viii



HISTORICAL RECONSTRUCTION OF PART 192 

(Complete through Amendment 192-104) 

Part 192 

Subpart 

SUBPART A – 

GENERAL 

SUBPART B – 

MATERIALS 

Part 192 

Section 

192.1 

192.3 

192.5 

192.7 

192.8 

192.9 

192.10 

192.11 

[192.12] 

192.13 

192.14 

192.15 

192.16 

[192.17] 

192.51 

192.53 

192.55 

192.57 

192.59 

192.61 

192.63 

192.65 

Effective 

Date of 

Original 

Version if 

other than 

11/12/70 

04/14/06 

03/19/98 

11/13/72 

12/30/77 

09/13/95 

01/01/71 

Addendum No. 8, April 2007 xxiii 

Amendments (if any) 

192-27, 192-67, 192-78, 192-81 

192-92, RIN 2137-AD77, 192-102, 

�192-103 

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 

192-27, 192-56, 192-78, 192-85 

192-37, 192-51, 192-68, 192-78 

192-94, RIN 2137-AD77, 192-99 

192-102, 192-103 

192-102 

192-72 + Ext., 192-95 Corr., 192-102 

192-81, RIN 2137-AD77 

192-68, 192-75, 192-78 

192-10, 192-36 (removed) 

192-27, 192-30, 192-102 

192-30 

192-74, 192-74A, 192-84 

192-1, 192-27A Ext., 192-38 

(removed) 

192-3, 192-12, 192-51, 192-68, 

192-85 

192-62 (removed and reserved) 

192-19, 192-58 


192-3, 192-31, 192-31A, 192-61, 

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

192-12, 192-17, 192-68




(Continued) 

Part 192 

Subpart 

SUBPART C - PIPE 

DESIGN 

Part 192 

Section 

192.101 

192.103 

192.105 

192.107 

192.109 

192.111 

192.113 

192.115 

192.117 

192.119 

192.121 

192.123 

192.125 

Effective 

Date of 

Original 

Version if 

other than 

11/12/70 

Addendum No. 6, September 2006 xxiv 


192-47, 192-85 

192-78, 192-84, 192-85 

192-85 

192-27 

192-37, 192-51, 192-62, 192-68, 

192-85, 192-94 

192-85 

192-37, 192-62 (removed and 

reserved) 


192-31, 192-78, 192-85, 192-94, 

�192-103 

192-31, 192-78, 192-85, 192-93 

�192-94, 192-103 

192-62, 192-85




(Continued) 

Part 192 

Subpart 

SUBPART D – DESIGN 

OF PIPELINE 

COMPONENTS 

Part 192 

Section 

192.141 

192.143 

192.144 

192.145 

192.147 

192.149 

192.150 

192.151 

192.153 

192.155 

192.157 

192.159 

192.161 

192.163 

192.165 

192.167 

192.169 

192.171 

192.173 

192.175 

192.177 

192.179 

192.181 

192.183 

192.185 

192.187 

192.189 

192.191 

192.193 

192.195 

192.197 

192.199 

192.201 

192.203 

Effective 

Date of 

Original 

Version if 

other than 

11/12/70 

08/04/83 

05/12/94 

Addendum No. 8, April 2007 xxv 


�192-48, 192-104 

192-45, 192-94 

192-3, 192-22, 192-37, 192-62, 

192-85, 192-94, 192-103 

192-62, 192-68 

192-72 + Ext., 192-85, 192-97 

192-85 

192-3, 192-68, 192-85 

192-27, 192-58 

192-27, 192-37, 192-68, 192-85 

192-27, 192-85 

192-85 

192-58, 192-62, 192-68, 192-85 

192-27, 192-78, 192-85 

192-85 

192-85 

192-76 

192-3, 192-58 

192-85, 192-93 

192-3 

192-9, 192-85 

192-78, 192-85




(Continued) 

Part 192 

Subpart 

SUBPART E – 

WELDING OF STEEL 

IN PIPELINES 

SUBPART F – 

JOINING OF 

MATERIALS OTHER 

THAN BY WELDING 

Part 192 

Section 

192.221 

[192.223] 

192.225 

192.227 

192.229 

192.231 

192.233 

192.235 

[192.237] 

[192.239] 

192.241 

192.243 

192.245 

192.271 

192.273 

192.275 

192.277 

192.279 

192.281 

192.283 

192.285 

192.287 

Effective 

Date of 

Original 

Version if 

other than 

11/12/70 

07/01/80 

07/01/80 

07/01/80 

Addendum No. 6, September 2006 xxvi 


192-52 (removed) 

192-18, 192-22, 192-37, 192-52, 

�192-94, 192-103 

192-18, 192-18A, 192-22, 192-37, 

192-43, 192-52, 192-75, 192-78, 

�192-94, 192-103 

192-18, 192-18A, 192-37, 192-78, 

�192-85, 192-94, 192-103 

192-37, 192-52 (removed) 

192-37, 192-52 (removed) 

192-18, 192-18A, 192-37, 192-78, 

�192-85, 192-94, 192-103 

192-27, 192-50, 192-78 

192-27, 192-46 

192-62 

192-62 

192-62, 192-68 

192-34, 192-58, 192-61, 192-68, 

192-78 

192-34 + Ext., 192-34A, 192-34B, 

192-68, 192-78, 192-85, 192-94 

�192-103 

192-34 + Ext., 192-34A, 192-34B 

192-93, 192-94 

192-34 + Ext., 192-94




(Continued) 

Part 192 

Subpart 

SUBPART G – 

GENERAL 

CONSTRUCTION 

REQUIREMENTS FOR 

TRANSMISSION 

LINES AND MAINS 

Part 192 

Section 

192.301 

192.303 

192.305 

192.307 

192.309 

192.311 

192.313 

192.315 

192.317 

192.319 

192.321 

192.323 

192.325 

192.327 

Effective 

Date of 

Original 

Version if 

other than 

11/12/70 

Addendum No. 1, September 2004 xxvii 


192-3, 192-85, 192-88 

192-93 

192-26, 192-29, 192-49, 192-85 

192-85 

192-27, 192-78 

192-27, 192-78, 192-85 

�192-78, 192-85, 192-93, 192-94 

192-85 

�192-27, 192-78, 192-85, 192-98




(Continued) 

Part 192 

Subpart 

SUBPART H – 

CUSTOMER METERS, 

SERVICE 

REGULATORS, AND 

SERVICE LINES 

SUBPART I – 

REQUIREMENTS FOR 

CORROSION 

CONTROL 

Part 192 

Section 

192.351 

192.353 

192.355 

192.357 

192.359 

192.361 

192.363 

192.365 

192.367 

192.369 

192.371 

192.373 

192.375 

192.377 

192.379 

192.381 

192.383 

192.451 

192.452 

192.453 

192.455 

192.457 

192.459 

192.461 

192.463 

192.465 

192.467 

192.469 

192.471 

192.473 

192.475 

�192.476 

192.477 

192.479 

192.481 

192.483 

192.485 

192.487 

192.489 

192.490 

192.491 

Effective 

Date of 

Original 

Version if 

other than 

11/12/70 

11/03/72 

07/22/96 

02/03/98 

08/01/71 

12/30/77 

08/01/71 

08/01/71 

08/01/71 

08/01/71 

08/01/71 

08/01/71 

08/01/71 

08/01/71 

08/01/71 

08/01/71 

08/01/71 

08/01/71 

05/23/07 

08/01/71 

08/01/71 

08/01/71 

08/01/71 

08/01/71 

08/01/71 

08/01/71 

10/25/05 

08/01/71 

Addendum No. 8, April 2007 xxviii 

192-85, 192-93 

192-58 


192-3, 192-85 

192-75, 192-85, 192-93 

192-75 

192-3, 192-85 

192-85 

192-78 

192-8 

192-79, 192-80, 192-85 

192-83 

192-4, 192-27, 192-33 

192-30, 192-102 

192-4, 192-71 

192-4, 192-28, 192-39, 192-78, 

192-85 

192-4, 192-33, 192-93 

192-4, 192-87 

192-4 

192-4 

192-4, 192-27, 192-33, 192-35, 

192-35A, 192-85, 192-93 

192-4, 192-33 

192-4, 192-27 

192-4 

192-4, 192-33 

192-4, 192-33, 192-78, 192-85 

192-104 

192-4, 192-33 

192-4, 192-33, 192-93 

192-4, 192-27, 192-33, 192-93 

192-4 

192-4, 192-33, 192-78, 192-88 

192-4, 192-88 

192-4 

192-101 

192-4, 192-33, 192-78




(Continued) 

Part 192 

Subpart 

SUBPART J - TEST 

REQUIREMENTS 

SUBPART K - 

UPRATING 

SUBPART L - 

OPERATIONS 

Part 192 

Section 

192.501 

192.503 

192.505 

192.507 

192.509 

192.511 

192.513 

192.515 

192.517 

192.551 

192.553 

192.555 

192.557 

192.601 

192.603 

192.605 

192.607 

192.609 

192.611 

192.612 

192.613 

192.614 

192.615 

192.616 

192.617 

192.619 

192.621 

192.623 

192.625 

192.627 

192.629 

Effective 

Date of 

Original 

Version if 

other than 

11/12/70 

01/06/92 

04/01/83 

02/11/95 

Addendum No. 6, September 2006 xxix 


192-58, 192-60, 192-60A 

192-85, 192-94 

192-58, 192-85 

192-58, 192-85 

192-75, 192-85 

192-77, 192-85 

192-93 

192-78, 192-93 

192-37, 192-62, 192-85 

192-27A Ext., 192-66, 192-71, 

192-75 

192-27A Ext., 192-59, 192-71, 

192-71A, 192-93 

192-5, 192-78 (removed and 

reserved) 

192-5, 192-53, 192-63, 192-78, 

192-94 

192-67, 192-85, 192-98 

192-40, 192-57, 192-73, 192-78, 

192-82, 192-84 + DFR Removal 

192-24, 192-71 

�192-71, 192-99, 192-103 

192-3, 192-27, 192-27A, 192-30, 

�192-78, 192-85, 192-102, 192-103 

192-85 

192-75 

192-2, 192-6, 192-7, 192-14, 

192-15, 192-16, 192-21, 192-58 

192-76, 192-78, 192-93




(Continued) 

Part 192 

Subpart 

SUBPART M - 

MAINTENANCE 

SUBPART N - 

QUALIFICATION OF 

PIPELINE 

PERSONNEL 

Part 192 

Section 

192.701 

192.703 

102.705 

192.706 

192.707 

192.709 

192.711 

192.713 

192.715 

192.717 

192.719 

192.721 

192.723 

192.725 

192.727 

[192.729] 

192.731 

[192.733] 

192.735 

192.736 

[192.737] 

192.739 

192.741 

192.743 

192.745 

192.747 

192.749 

192.751 

192.753 

192.755 

[Header] 

[192.761] 

192.801 

192.803 

192.805 

192.807 

192.809 

Effective 

Date of 

Original 

Version if 

other than 

11/12/70 

06/04/75 

10/18/93 

06/01/76 

10/26/99 

10/26/99 

10/26/99 

10/26/99 

10/26/99 

Addendum No. 8, April 2007 xxx 


192-21, 192-43, 192-78 

192-21, 192-43, 192-71 

192-20, 192-20A, 192-27, 192-40, 

192-44, 192-73, 192-85 

192-78 

192-27B, 192-88 

192-27, 192-88 

192-85 

192-11, 192-27, 192-85, 192-88 

192-54 

192-43, 192-78 

192-43, 192-70, 192-71, 192-94 

192-8, 192-27, 192-71, 192-89, 

�RIN 2137-AD77, 192-103 


192-43 


192-69, 192-85 


192-43, 192-93, 192-96 

192-43, 192-55, 192-93, 192-96 

192-43, 192-93 

192-43, 192-93 

192-43, 192-85 

192-25, 192-85, 192-93 

192-23 

192-103 (removed) 

192-91, 192-95 (removed) 

192-86 

192-86, 192-90 

192-86, 192-100 

192-86 

192-86, 192-90, 192-100




(Continued) 

Part 192 

Subpart 

SUBPART O – 

PIPELINE INTEGRITY 

MANAGEMENT 

Part 192 

Section 

Header 

192.901 

192.903 

192.905 

192.907 

192.909 

192.911 

192.913 

192.915 

192.917 

192.919 

192.921 

192.923 

192.925 

192.927 

192.929 

192.931 

192.933 

192.935 

192.937 

192.939 

192.941 

192.943 

192.945 

192.947 

192.949 

192.951 

Effective 

Date of 

Original 

Version if 

other than 

11/12/70 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

2/14/04 

Addendum No. 8, April 2007 xxx(a) 


192-95, 192-103 

192-95 

192-95, 192-103 

192-95 

192-95, 192-103 

192-95 

192-95, 192-103 

192-95, 192-103 

192-95 

192-95, 192-103 

192-95 

192-95, 192-103 

192-95, 192-103 

192-95, 192-103 

192-95, 192-103 

192-95, 192-103 

192-95, 192-103 

192-95, 192-103 

192-95, 192-103 

192-95, 192-103 

192-95, 192-103 

192-95 

192-95 

192-95, 192-103 

192-95 

�192-95, RIN 2137-AD77, 192-103 

�192-95, RIN 2137-AD77, 192-103




(Continued) 

Part 192 

Subpart 

FEDERAL 

APPENDICES 

Part 192 

Section 

[App. A] 

App. B 

App. C 

Effective 

Date of 

Original 

Version if 

other than 

11/12/70 

App. D 08/01/71 192-4 

App. E 

Addendum No. 6, September 2006 xxx(b) 

12/15/03 192-95 


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) 

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 

192-85, 192-94

GPTC 

GUIDE FOR GAS TRANSMISSION AND 

DISTRIBUTION PIPING SYSTEMS: 

2003 Edition 

Amdt 

192- 

102 Gas Gathering Line 

Definition 

103 Update of Regulatory 

References to 

Technical Standards 

103 

[Amended] 

[104] 

HISTORICAL RECORD OF AMENDMENTS TO PART 192 

(Continued) 

Subject Vol FR Pg# Published 

Date 

Update of Regulatory 

References to 

Technical Standards 

[Amending that 

published [06/09/06] 

Design and 

Construction 

Standards to Reduce 

Internal Corrosion in 

Gas Transmission 

Pipelines 

* Issued as a Direct Final Rule (DFR). 

Addendum No. 8, April 2007 

xlix 

Docket 

No. 

71 FR 13289 03/15/06 RIN 2137- 

AB15 

71 FR 33402 06/09/06 RIN 2138- 

AD68 

72 FR 4655 02/01/07 RIN 2137- 

AD68 

72 FR 20055 04/23/07 RIN 2137- 

AE09 

Effective 

Date 

Affected Sections 

192. 

04/14/06 1, 7, 8, 9, 13, 452, 

619 

07/10/06 7, 121, 123, 145, 

225, 227, 229, 241, 

283, 616, 619, 

Header before 761, 

Subpart O Header, 

903, 907, 911, 913, 

917, 921, 923, 925, 

927, 929, 931, 933, 

935, 937, 939, 945, 

App. B 

03/05/07 1, 7, 227, 727, 903, 

949, 951 

05/23/07 143, 476




2003 Edition 

Addendum No. 5, May 2006 l 

Reserved



Abbreviations: 

Chairperson: Chair 

First Vice Chairperson: 1 st V Chair 

Second Vice Chairperson: 2 nd V Chair 

Secretary: Sec 

Damage Prevention - Emergency Response: DP/ER 

Operation and Maintenance: O&M 

GAS PIPING TECHNOLOGY COMMITTEE MEMBERSHIP LIST 

Abraham, Richard A. 

National Grid USA, Providence, RI 

Affonso, Joaquin J. 

Consumers Energy, Jackson, MI 

Alexander, Thomas D. 

Willbros Engineers, Inc., Tulsa, OK 

Arita, Richard 

Pacific Gas & Electric Co., Walnut Creek, CA 

Armstrong, Glen F. 

EN Engineering, Woodridge, IL 

Ashcraft, Nicholas 

Kiefner & Associates, Worthington, OH 

Barkei, David E. 

We Engeries, Milwaukee, WI 

Batten, Charles H. 

Batten & Associates., Inc., Locust Grove, VA 

Beaver, Brett 

Advantica, Mechanicsburg, PA 

Becken, Robert C. 

Energy Experts International, Pleasant Hill, CA 

Benedict, Andrew G. 

Opvantek, Inc., Newtown, PA 

Bennett, Frank M. 

PPL Gas Utilities Corp., Lancaster, PA 

Addendum No. 8, April 2007 li 

Main Body 

X 

X 

X 

X 

X 

X 

Distribution 

DIVISIONS TASK GROUPS SECTIONS 

Manufacturers 

Transmission 

Design 

DP/ER 

X X X 

IMP/Corrosion 

X X X 

X X 

O&M/OQ 

X X X 

Chair X X X X X 

X X 

X X X 

X X X 

X X X 

Plastic Pipe 

Regulations 

Editorial 

X X X X 

X X 

X X X 

Executive 

Liaison











(Continued) 

Blaney, Steven D. 

NY State Dept. of Public Service, Albany, NY 

Booth, Lloyd E. 

Southern Cross Corp., Coppell, TX 

Boros, Stephen 

Plastics Pipe Institute, Washington, DC 

Borski, Lawrence W. 

Williams Gas Pipeline, Houston, TX 

Breaux, David 

Broen, Inc., Metairie, LA 

Brown, Charles E. 

TRC, Jackson, MI 

Bull, David E. 

ViaData LP, Tobyhanna, PA 

Cabot, Paul W. 

American Gas Association, Washington, DC 

Cadorin, Robert J. 

Great Lakes Gas Trmn. Co., Troy, MI 

Carey, Willard S. 

Public Service Elec. & Gas Co., Newark, NJ 

Chin, John S. 

TransCanada Corp., Farmington Hills, MI 

Addendum No. 8, April 2007 lii 

Main Body 

X 

X 

Distribution 


Manufacturers 

Transmission 

Design 

DP/ER 

X X X X 

IMP/Corrosion 

O&M/OQ 

X X X 

Plastic Pipe 

X X 

X X 

X X X 

X X X 

X SEC X 

SEC SEC 

X 

X 

X 

SEC X 

X X Chair X 

Regulations 

Editorial 

X X X Chair X X 

Executive 

Liaison











(Continued) 

Clarke, Allan M. 

Spectra Energy Corp., Houston, TX 

Cody, Leo T. 

KeySpan Energy Delivery, Waltham, MA 

Craig, Jim M. 

McElroy Manufacturing, Inc., Tulsa, OK 

Del Buono, Amerigo J. 

Steel Forgings, Inc., League City, TX 

DeVore, James C. 

Consultant, Green Valley, AZ 

Dockweiler, Kenneth D. 

Kinder Morgan Inc., Casper, WY 

Dolezal, Denise L. 

Metropolitan Utilities District, Omaha, NE 

Erickson, John P. 

American Public Gas Association, Washington, DC 

Fleet, F. Roy 

F. Roy Fleet, Inc., Westmont, IL 

Frantz, John H. 

Consultant, Philadelphia, PA 

Frederick, Victor M., III 

Utility Line Services, Conshohocken, PA 

Main Body 

Distribution 


Manufacturers 

Transmission 

Design 

DP/ER 

IMP/Corrosion 

X X X X 

O&M/OQ 

X X X 

X X 

Addendum No. 8, April 2007 liii 

X 

X 

X 

Plastic Pipe 

X X X 

X X X X 

X X X 

X X X 

X X 

Regulations 

Editorial 

X X X 

X X Chair 

X X X 

Executive 

Liaison











(Continued) 

Friend, Mary S. 

Columbia Gas Trmn. Corp., Charleston, WV 

Fuller, William R. 

Xcel Energy Inc., Denver, CO 

Galante, Julie 

Washington Gas Light Co., Springfield, VA 

Gilchrist, Hart 

Intermountain Gas Co., Pocatello , ID 

Goble, Greg H. 

R. W. Lyall & Co., Corona, CA 

Groeber, Steve A. 

Philadelphia Gas Works, Philadelphia, PA 

Gunther, Karl M. 

NTSB, Washington, DC 

Hansen, James P. 

Perfection Corp., Madison, OH 

Hart, Thomas L. 

NSTAR Electric & Gas Corp., Westwood, MA 

Hazelden, Glyn 

Gas Technology Institute, Des Plaines, IL 

Heintz, James R. 

UGI Utilities, Inc., Reading, PA 

Addendum No. 8, April 2007 liv 

Main Body 

X 

X 

X 

Distribution 


Manufacturers 

Transmission 

Design 

DP/ER 

IMP/Corrosion 

O&M/OQ 

X X X 

Plastic Pipe 

X X X X 

X X 

X X 

X X X 

X X X X X 

X X 

X X 

X X X 

X X X 

X X X X X Chair 

Regulations 

Editorial 

Executive 

Liaison











(Continued) 

Main Body 

Henningsgaard, David R. 

CenterPoint Energy, Minneapolis, MN 

Henry, Jill A. 

X 

Ohio PUC, Columbus, OH 

Hotinger, James M. 

VA State Corp. Comm., Richmond, VA 

Humes, Dennis W. 

X 

Mueller Co.- Gas Products Div., Decatur, IL 

Hurbanek, Stephen F. 

Pennsylvania PUC, Harrisburg, PA 

Huriaux, Richard D. 

X 

PHMSA - OPS, Washington, DC 

Kottwitz, John D. 

X 

MO Public Service Comm., Jefferson City, MO 

Krummert, Lawrence M. 

Columbia Gas of PA, Inc., New Castle, PA 

Lathrap, Philip A. X 

Consultant, Lafayette, CA 

Lewis, Raymond D. 

X 

Rosen USA, Houston, TX 

Addendum No. 8, April 2007 lv 

Distribution 


Manufacturers 

Transmission 

Design 

DP/ER 

IMP/Corrosion 

O&M/OQ 

X X X X 

Plastic Pipe 

X X X 

X X X 

Regulations 

X X 

X X 

X X 

X Chair X X X 

X X 

X X X X 

X X 

Editorial 

Executive 

Liaison











(Continued) 

Loker, Jon O. 

Pipeline Safety Consultant, Saint Albans, WV 

Lomax, George S. 

Heath Consultants Inc., Montoursville, PA 

Lopez, Paul 

Colorado Interstate Gas Co., Colorado Springs, CO 

Lueders, John D. 

DTE Energy - MichCon, Grand Rapids, MI 

Mackay-Smith, Seth 

UMAC Inc., Malvern, PA 

Marek, Marti 

Southwest Gas Corp., Las Vegas, NV 

Mason, James F. 

Arkema Inc., Philadelphia, PA 

McKenzie, James E. 

Atmos Energy Corp., Jackson, MS 

McMaine Jeffrey B. 

Texas Gas Trmn., LLC, Owensboro, KY 

Miller, D. Lane 

Transportation Safety Inst., Oklahoma City, OK 

Addendum No. 8, April 2007 lvi 

Main Body 

X 

X 

X 

Distribution 


Manufacturers 

Transmission 

Design 

DP/ER 

IMP/Corrosion 

O&M/OQ 

Plastic Pipe 

Regulations 

Editorial 

X Chair X 

X X X 

X X 

X X X 

X X X 

Chair X 

X 

X X 

X X 

X X X 

X X X Sec 

Executive 

Liaison











(Continued) 

Naper, Robert C. 

KeySpan Energy Delivery, Waltham, MA 

Oleksa, Paul E. 

Oleksa & Assoc., Akron, OH 

Palermo, Eugene F. 

Palermo Plastics Pipe Consulting, Friendsville, TN 

Peters, Kenneth C. 

El Paso Corp. Pipeline Group, Birmingham, AL 

Pioli, Christopher A. 

Jacobs Consultancy, Pasadena, CA 

Quezada, Leticia 

Nicor Gas, Naperville, IL 

Reynolds, Donald Lee 

NiSource Inc., Columbus, OH 

Roberson, Edwin H. 

Natural Gas Odorizing, Inc., Katy, TX 

Robertson, Joseph P. 

Williams Gas Pipeline-NW, Salt Lake City, UT 

Schmidt, Robert A. 

Hackney Ladish Inc., Russellville, AR 

Addendum No. 8, April 2007 lvii 

Main Body 

X 

X 

X 

X 

X 

Distribution 


Manufacturers 

Transmission 

Design 

DP/ER 

X X 

X X X X 

IMP/Corrosion 

O&M/OQ 

Plastic Pipe 

X X X 

Regulations 

Editorial 

Chair X SEC X 

X X X X 

X X X Chair X 

X 

Chair X X 

X X 

X X X 

Chair X X 

Executive 

Liaison




2003 Edition 



st 

First Vice Chairperson: 1 V Chair 







(Continued) 

Scott, Edward W. 

AmerenIP, Pawnee, IL 

Seamands, Patrick A. 

Laclede Gas Co., Saint Louis, MO 

Sher, Philip 

CT Dept. Public Utility Control, New Britain, CT 

Siedlecki, Walter 

AEGIS Insurance Services, Inc., East Rutherford, NJ 

Slagle, Richard 

Vectren Energy Delivery, Evansville, IN 

Sprenger, Roger W. 

San Diego Gas & Elec. Co., San Diego, CA 

Strohm, Billy J. 

George Fischer Sloane, Little Rock, AR 

Themig, Jerome S. 

Ameren Services Co., Pawnee, IL 

Torbin, Robert N. 

Cutting Edge Solutions LLC, Framingham, MA 

Main Body 

2 nd V 

Chair 

X 

Distribution 


Manufacturers 

lviii 

Transmission 

Design 

DP/ER 

IMP/Corrosion 

O&M/OQ 

Plastic Pipe 

X X X 

X X X X 

X X 

SEC X Chair 

X X X 

X X 

X X X 

X X 

Regulations 

Editorial 

Executive 

X 

Liaison




2003 Edition 

iations: 

st 

V Chair 

Second Vice Chairperson: 2 nd Abbrev 


First Vice Chairperson: 1 

V Chair 





(Continued) 

Troch, Steven J. 

Baltimore Gas & Electric Co., Baltimore, MD 

Ulanday, Alfredo S. 

Peoples Energy Corp., Chicago, IL 

Veerapaneni, Ram 

DTE Energy – MichCon, Detroit, MI 

Volgstadt, Frank R. 

Volgstadt & Associates, Madison, OH 

Weber, David E. 

Consultant Engineer, Barnstable, MA 

White, Gary R. 

PI Confluence, Inc., Houston, TX 

Wilkes, Al L. 

Performance Pipe, Plano, TX 

Wolf, Brian D. 

Iroquois Pipeline Operating Co., Shelton, CT 

Zapalac, Daniel P. 

R.W. Lyall & Co., Inc., Corona, CA 


Main Body 

X 

X 

Distribution 


lix 

Manufacturers 

Transmission 

Design 

DP/ER 

IMP/Corrosion 

X X 

O&M/OQ 

X X X 

X X X X 

Plastic Pipe 

SEC SEC 

X X X 

X X 

X X X 

X X X X 

X X 

Regulations 

Editorial 

Executive 

Liaison



Reserved 

lx

GPTC GUIDE FOR GAS TRANSMISSION AND §192.1 

DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART A 

PART 192 

MINIMUM FEDERAL SAFETY STANDARDS 

Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 60113, and 60118; and 49 CFR 1.53. 

Source: 35 FR 13257, Aug. 19, 1970, unless otherwise noted. 

SUBPART A 

GENERAL 

§192.1 

What is the scope of this part? 

▌[Effective Date: 3-05-07] 

(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] 

Addendum No. 8, April 2007 11



GUIDE MATERIAL 

This guide material is under review following Amendment 192-102. 

(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 this Guide is intended principally to serve natural gas pipelines, it is a valuable reference for other 

pipelines covered by Part 192. The user is cautioned that the unique properties and characteristics 

associated with other gases (e.g., density, corrosivity, and temperature extremes) may require special 

engineering considerations. 

(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. 

§192.3 

Definitions. 

[Effective Date: 5-6-05] 

As used in this part: 

Abandoned means permanently removed from service. 

Administrator means the Administrator, Pipeline and Hazardous Materials Safety Administration 

or his or her delegate. 

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. 

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 o F (38 o C). 

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 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 of 

Puerto Rico. 

Addendum No. 5, May 2006 13



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. 

[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] 


Glossary of Commonly Used Terms 

(For Glossary of Commonly Used Abbreviations, see Table 192.3i below.) 


Abandoned pipeline is a pipeline that is physically separated from its source of gas and is no longer 

maintained under Part 192. 

Abandonment is the process of abandoning a pipeline. 

Adhesive joint is a joint made in thermosetting plastic piping by the use of an adhesive substance that forms 

a bond between the mating surfaces without dissolving either one of them. 

Ambient temperature is the temperature of the surrounding medium, usually used to refer to the temperature 

of the air in which a structure is situated or a device operates. See also Ground Temperature and 

Temperature. 

Bell-welded pipe is furnace-welded pipe that has a longitudinal butt joint that is forge-welded by the 

mechanical pressure developed in drawing the furnace-heated skelp through a cone-shaped die. The 

die, commonly known as a "welding bell," serves as a combined forming and welding die. This type of 

pipe is produced in individual lengths from cut-length skelp. Typical specifications: ASTM A53, API 

Spec 5L. See also Furnace-butt-welded pipe and Pipe manufacturing processes. 

Bottle is a gastight structure which is (1) completely fabricated by the manufacturer from pipe with integral 

drawn, forged, or spun end closures; and (2) tested in the manufacturer's plant. See also Bottle-type 

holder. 

Bottle-type holder is any bottle or group of interconnected bottles installed in one location, and used for the 

sole purpose of storing gas. See also Bottle. 

Carbon steel. By common custom, steel is considered to be carbon steel where (i) no minimum content is 

specified or required for aluminum, boron, chromium, cobalt, columbium, molybdenum, nickel, titanium, 

tungsten, vanadium, zirconium, or any other element added to obtain a desired alloying effect; (ii) the 

specified minimum content for copper does not exceed 0.40 percent; or (iii) the specified maximum 

content does not exceed 1.65 percent for manganese, 0.60 percent for silicon or 0.60 percent for 

copper. 

All carbon steels may contain small quantities of unspecified residual elements unavoidably retained 

from raw materials. These elements (copper, nickel, molybdenum, chromium, etc.) are considered 

incidental and are not normally determined or reported. 




Cast iron. The unqualified term cast iron applies to gray-cast iron that is a cast ferrous material in which a 

major part of the carbon content occurs as free carbon in the form of flakes interspersed through the 

metal. 

Cold-expanded pipe is seamless or welded pipe which is formed and then, expanded in the pipe mill while 

cold, so that the circumference is permanently increased by at least 0.50 percent. 

Continuous-welded pipe is furnace-welded pipe which has a longitudinal butt joint that is forge-welded by the 

mechanical pressure developed in rolling the hot-formed skelp through a set of round pass welding 

rolls. It is produced in continuous lengths from coiled skelp and subsequently cut into individual lengths. 

Typical specifications: ASTM A53, API Spec 5L. See also Furnace-butt-welded pipe and Pipe 

manufacturing processes. 

Control piping is pipe, valves, and fittings used to interconnect air, gas, or hydraulically operated control 

apparatus. 

Curb valve is a valve installed for the purpose of shutting off the gas supply to a building. It is installed below 

grade in a service line, at or near the property line. It is operated by use of a removable key or wrench, 

through a curb box or standpipe. 

Customer meter is a device that measures gas delivered to a customer for consumption on its premises. 

Deactivation (Inactivation) is the process of making the pipeline inactive. 

District regulator station or district pressure regulating station is a pressure regulating station that controls 

pressure to a high- or low-pressure distribution main. It does not include pressure regulation whose 

sole function is to control pressure to a manifold serving multiple customers. 

Double submerged-arc-welded pipe is a pipe having longitudinal or spiral butt joints. The joints are produced 

by at least two passes, including at least one each on the inside and on the outside of the pipe. 

Coalescence is produced by heating with an electric arc or arcs between the bare metal electrode or 

electrodes and the work. The welding is shielded by a blanket or granular, fusible material on the work. 

Pressure is not used and filler metal for the inside and outside welds is obtained from the electrode or 

electrodes. Typical specifications: ASTM A381, API Spec 5L. See also Pipe manufacturing processes. 

Ductile iron (sometimes called nodular iron) is a cast ferrous material in which the free graphite present is in 

a spheroidal form rather than a flake form. The desirable properties of ductile iron are achieved by 

means of chemistry and a ferritizing heat treatment of the castings. 

Electric-flash-welded pipe is pipe having a longitudinal butt joint wherein coalescence is produced, 

simultaneously over the entire area of abutting surfaces, by the heat obtained from resistance to the 

flow of electric current between the two surfaces, and by the application of pressure after heating is 

substantially completed. Flashing and upsetting are accompanied by the expulsion of metal from the 

joint. Typical specification: API Spec 5L. See also Pipe manufacturing processes. 

Electric-fusion-welded pipe is pipe having a longitudinal butt joint wherein coalescence is produced in the 

preformed tube by manual or automatic electric-arc welding. The weld may be single or double and 

may be made with or without the use of filler metal. Typical specifications: ASTM A134, ASTM A139: 

Single or double weld is permitted with or without the use of filler metal. ASTM A671, ASTM A672, 

ASTM A691, and API Spec 5L: Requires both inside and outside welds and use of filler metal. 

Spiral-welded pipe is also made by the electric-fusion-welded process with either a butt joint, a lap joint 

or a lock-seam joint. Typical specifications: ASTM A134, ASTM A139, and API Spec 5L: Butt joint. 

ASTM A211: Butt joint, lap joint, or lock-seam joint. See also Pipe manufacturing processes. 

Electric-resistance-welded pipe is pipe, which has a longitudinal butt joint wherein coalescence, is produced 

by the application of pressure and by the heat obtained from the resistance of the pipe to the flow of an 

electric current in a circuit of which the pipe is a part. It is produced in individual lengths or in 

continuous lengths from coiled skelp and subsequently cut into individual lengths. Typical 

specifications: ASTM A53, ASTM A135, and API Spec 5L. See also Pipe manufacturing processes. 

Excess Flow Valve (EFV) is a device installed in a gas pipeline to automatically restrict or shut off the gas 

flow through the line when the flow exceeds a predetermined limit. 

Excess Flow Valve-Bypass (EFVB) is an EFV that is designed to limit the flow of gas upon closure to a 

small, predetermined level. EFVBs reset automatically once the line downstream is made gastight and 

pressure is equalized across the valve. 




Excess Flow Valve-Non-Bypass (EFVNB) is an EFV that is designed to stop the flow of gas upon closure. 

EFVNBs must be manually reset. 

Furnace-butt-welded pipe. There are two such types of pipe defined in this glossary: Bell-welded pipe and 

Continuous-welded pipe. See also Pipe manufacturing processes. 

Furnace-lap-welded pipe is pipe that has a longitudinal lap joint that is produced by the forge welding 

process. In this process, coalescence is produced by heating a preformed tube to welding temperature 

and then passing it over a mandrel. The mandrel is located between the two welding rolls that 

compress and weld the overlapping edges. Typical specification: API Spec 5L. The manufacture of this 

type of pipe was discontinued, and the process was deleted from API Spec 5L in 1962. See also Pipe 

manufacturing processes. 

Gas control is a person or persons who acquire and maintain data to remotely monitor and direct the flow of 

gas to meet design and contractual obligations, and to assist in detecting pipeline emergencies and 

initiating response. 

Ground temperature is the temperature of the earth at pipe depth. See also Ambient temperature and 

Temperature. 

Heat fusion joint is a joint made in thermoplastic piping by heating the parts sufficiently to permit fusion of the 

materials when the parts are pressed together. 

Hoop stress is the stress in a pipe wall, acting circumferentially in a plane perpendicular to the longitudinal 

axis of the pipe, produced by the pressure of the fluid in the pipe. In this Guide, hoop stress in steel 

pipe is calculated by the formula: 

Where: 

S h = PD 

2t 

Sh = hoop stress, psi 

P = internal pressure, psig 

D = nominal outside diameter of pipe, inches 

t = nominal wall thickness, inches 

See also Maximum allowable hoop stress. 

Hot taps are connections made to transmission lines, mains, or other facilities while they are in operation. 

The connecting and tapping is done while the facility is under gas pressure. 

Hydrostatic Design Basis (HDB) is one of a series of established stress values specified in ASTM D2837, 

"Standard Test Method for Obtaining Hydrostatic Design Basis for Thermoplastic Pipe Materials or 

Pressure Design Basis for Thermoplastic Pipe Products," for a plastic compound, obtained by 

categorizing the long-term hydrostatic strength as determined in accordance with ASTM D2837. 

Inactive pipeline is a pipeline that is being maintained under Part 192 but is not presently being used to 

transport gas. 

Instrument piping is pipe, valves, and fittings used to connect instruments to main piping, to other 

instruments and apparatus, or to measuring equipment. 

Iron. See Cast iron, Ductile iron, and Malleable iron. 

Joint. See Length. 

Leakage surveys are systematic inspections made for the purpose of finding leaks in a gas piping system. 

The types of inspections commonly made are described in Guide Material Appendix G-192-11 "Gas 

Leakage Control Guidelines for Natural Gas Systems" and Guide Material Appendix G-192-11A "Gas 

Leakage Control Guidelines for Petroleum Gas Systems." 

Length is a piece of pipe as delivered from the mill. Each piece is called a length regardless of its actual 

longitudinal dimension. While this is sometimes called a "joint," the term "length" is preferred. 

Light surface oxide is a non-damaging form of corrosion. 

Long-term hydrostatic strength of plastic pipe is the estimated hoop stress, in psi, that would result in a 

failure of the pipe if the pipe were subjected to 100,000 hours of hydrostatic pressure. 

Lower Explosive Limit (LEL) is the lower limit of flammability for a gas expressed as a percent, by volume, of 

gas in air. 

Malleable iron is a mixture of iron and carbon, including small amounts of silicon, manganese, phosphorous 

and sulfur which, after being cast, is converted structurally by heat treatment into primarily a matrix of 

ferrite containing nodules of tempered carbon. 




Maximum allowable hoop stress is the maximum hoop stress permitted for the design of a piping system. It 

depends upon the material used, the class location of the pipe, and the operating conditions. See also 

Hoop stress. 

Maximum allowable test pressure is the maximum internal fluid pressure permitted for testing, for the 

materials and class location involved. 

Meters. See Customer meter and Meter set assembly. 

Meter set assembly is the piping installed to connect the inlet side of the meter to the gas service line, and to 

connect the outlet side of the meter to the customer's fuel line. 

Monitoring regulator is a pressure regulator, set in series with another pressure regulator, for the purpose of 

providing automatic overpressure protection in the event of a malfunction of the primary regulator. 

Nodular iron. See Ductile iron. 

Nominal outside diameter (D) is the outside diameter, in inches, as listed in Table 192.105i for nominal pipe 

size 12 inches and less, and is the same as the nominal pipe size greater than 12 inches. It is used in 

the design formula for steel pipe in §192.105 and the calculation for hoop stress. 

Nominal wall thickness (t) is the wall thickness, in inches, computed by, or used in, the design formula for 

steel pipe in §192.105. Pipe may be ordered to this computed wall thickness without adding an 

allowance to compensate for the under-thickness tolerances permitted in approved specifications. 

Operating stress is the stress in a pipe or structural member under normal operating conditions. 

Overpressure protection is the use of a device or equipment installed for the purpose of preventing pressure 

in a pipe system or other facility from exceeding a predetermined limit. See also Pressure limiting 

station, Pressure regulating station, Pressure relief station, and Service regulator. 

Parallel encroachment pertains to that portion of the route of a transmission line or main that lies within, runs 

in a generally parallel direction to, and does not necessarily cross, the rights-of-way of a road, street, 

highway, or railroad. 

Pipe. See Bell-welded pipe, Cold expanded pipe, Continuous-welded pipe, Control piping, 

Double-submerged-arc-welded pipe, Electric-flash-welded pipe, Electric-fusion-welded pipe, Electric- 

resistance-welded pipe, Furnace-butt-welded pipe, Furnace-lap-welded pipe, Instrument piping, 

Length, Pipe-container, Pipe manufacturing processes, Pipe-type holder, Sample piping, and 

Seamless pipe. 

Pipe-container is a gastight structure assembled from pipe and end closures. See also Pipe-type holder. 

Pipe manufacturing processes. A reference is ASME I00396 “History of Line Pipe Manufacturing in North 

America.” Types and names of welded joints are used herein as defined in the American Welding 

Society (AWS) Publication A3.0 "Standard Welding Terms and Definitions" except for the following 

terms which are defined in this glossary. 

Bell-welded pipe 

Continuous-welded pipe 

Double-submerged-arc-welded pipe 

Electric-flash-welded pipe 

Electric-fusion-welded pipe 

Electric-resistance-welded pipe 

Furnace-butt-welded pipe 

Furnace-lap-welded pipe 

Seamless pipe 

Pipe-type holder is any pipe-container or group of interconnected pipe-containers installed at one location 

for the sole purpose of storing gas. See also Pipe-container. 

Plastic (noun) is a material that contains one or more organic polymeric substances of high molecular weight 

as an essential ingredient, is solid in its finished state, and can be shaped by flow at some stage of its 

manufacture or processing into finished articles. The two general types of plastic referred to in this 

Guide are thermoplastic and thermosetting. See also Thermoplastic and Thermosetting plastic. 

Plastic pipe joints. See Adhesive joint, Heat fusion joint, and Solvent cement joint. 

Pressure (expressed in pounds per square inch above atmospheric pressure, i.e., gauge pressure 

(abbreviation: psig), unless otherwise stated). See also Maximum allowable test pressure, 

Overpressure protection, Pressure limiting station, Pressure regulating station, Pressure relief station, 

and Standup pressure test. 




Pressure limiting station consists of apparatus which, under abnormal conditions, will act to reduce, restrict 

or shut off the supply of gas flowing into a transmission line, main, holder, pressure vessel or 

compressor station piping in order to prevent the gas pressure from exceeding a predetermined limit. 

While normal pressure conditions prevail, the pressure limiting station may exercise some degree of 

control of the flow of gas or may remain in the wide-open position. Included in the station are any 

enclosures and ventilating equipment, and any piping and auxiliary equipment, such as valves, control 

instruments, or control lines. 

Pressure regulating station consists of apparatus installed for the purpose of automatically reducing and 

regulating the gas pressure in the downstream transmission line, main, holder, pressure vessel or 

compressor station piping to which it is connected. Included in the station are any enclosures and 

ventilating equipment, and any piping and auxiliary equipment, such as valves, control instruments, or 

control lines. 

Pressure relief station consists of apparatus installed to vent gas from a transmission line, main, holder, 

pressure vessel, or compressor station piping in order to prevent the gas pressure from exceeding a 

predetermined limit. The gas may be vented into the atmosphere or into a lower pressure gas system 

capable of safely receiving the gas being discharged. Included in the station are any enclosures and 

ventilating equipment, and any piping and auxiliary equipment, such as valves, control instruments, or 

control lines. 

Private rights-of-way are those that are not located on roads, streets or highways used by the public, or on 

railroad rights-of-way. 

Proprietary items are items made by a company having the exclusive right of manufacture. 

Public place is a place that is generally open to all persons in a community as opposed to being restricted 

to specific persons. A public place includes churches, schools, and commercial property, as well as 

any publicly owned right-of-way or property that is frequented by people. 

Regulators. See Pressure limiting station, Pressure regulating station, Pressure relief station, and Service 

regulator. 

Sample piping is pipe, valves, and fittings used for the collection of samples of gas or other fluids. 

SCADA is supervisory control and data acquisition. SCADA is a remote control system that allows the 

transmission of data from a remote site (e.g., a delivery point) to a central control location. SCADA 

systems are used to monitor and control flow, pressure, and other parameters of the pipeline system. 

SCADA systems may generate an alarm when an event has occurred or an unusual situation is 

developing. 

Seamless pipe is a wrought tubular product made without a welded seam. It is manufactured by hot working 

steel or, if necessary, by subsequently cold finishing the hot-worked tubular product to produce the 

desired shape, dimensions, and properties. See also Pipe manufacturing processes. 

Secondary stress is stress created in the pipe wall by loads other than internal fluid pressure. Examples are 

backfill loads, traffic loads, beam action in a span and loads at supports and at connections to the pipe. 

Service line valve is a valve located in the service line ahead of the service regulator, or ahead of the meter 

where there is no regulator. 

Solvent cement joint is a joint made in PVC piping by using solvent cement to join the piping components. 

Standup pressure test is a test to demonstrate that a pipe or piping system does not leak as evidenced by 

the lack of a drop in pressure over a specified period of time after the source of pressure has been 

isolated. 

Steel is an iron-base alloy, malleable in some temperature range as initially cast, containing manganese, 

carbon, and often other alloying elements. See also Carbon steel. 

Stress is the resultant internal force that resists change in the size or shape of a body acted on by external 

forces. See also Hoop stress, Maximum allowable hoop stress, Operating stress, Secondary stress, 

Tensile strength, and Yield strength. 

Temperature (expressed in degrees Fahrenheit ( o F) unless otherwise stated). See also Ambient 

temperature and Ground temperature. 




Tensile strength is the highest unit tensile stress (referred to the original cross section) that a material can 

sustain before failure (psi) 

Thermoplastic is a plastic, which is capable of being repeatedly softened by increase of temperature and 

hardened by decrease of temperature. 

Thermosetting plastic is a plastic that is capable of being changed into a substantially infusible or insoluble 

product when cured under the application of heat or by chemical means. 

Thickness. See Nominal wall thickness. 

Valve. See Curb valve and Service line valve. 

Vault is an underground structure which may be entered, and which is designed to contain piping and piping 

components, such as valves or pressure regulators. 

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 

ASV automatic shutoff valve 

BAP baseline assessment plan 

CAB cellulose acetate butyrate 

CDA confirmatory direct assessment 

CGI combustible gas indicator 

DA direct assessment 

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 

HCA high consequence area 

HDB hydrostatic design basis 

HFI hydrogen flame ionization 

IC internal corrosion 

ICDA internal corrosion direct assessment 

ILI In-line inspection 

IMP integrity management program 

IR drop voltage drop 

LEL lower explosive limit 

LNG liquefied natural gas 

LPG liquid petroleum gas 

LTHS long-term hydrostatic strength 

MAOP maximum allowable operating pressure 

MRS minimum required strength 

NPS nominal pipe size 

O&M operations and maintenance 

OCS outer continental shelf 

OQ operator qualification 




GLOSSARY OF COMMOMLY USED ABBREVIATIONS (Continued) 

Abbreviation Meaning 

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 

SMYS specified minimum yield strength 

TABLE 192.3i 

§192.5 

Class locations. 


(a) This section classifies pipeline locations for purposes of this part. The following criteria 

apply to classifications under this section. 

(1) A "class location unit" is an onshore area that extends 220 yards (200 meters) on either 

side of the centerline of any continuous 1- mile (1.6 kilometers) length of pipeline. 

(2) Each separate dwelling unit in a multiple dwelling unit building is counted as a separate 

building intended for human occupancy. 

(b) Except as provided in paragraph (c) of this section, pipeline locations are classified as 

follows: 

(1) A Class 1 location is: 

(i) An offshore area; or 

(ii) Any class location unit that has 10 or fewer buildings intended for human 

occupancy. 

(2) A Class 2 location is any class location unit that has more than 10 but fewer than 46 

buildings intended for human occupancy. 

(3) A Class 3 location is: 

(i) Any class location unit that has 46 or more buildings intended for human 

occupancy; or 

(ii) An area where the pipeline lies within 100 yards (91 meters) of either a building or 

a small, well-defined outside area (such as a playground, recreation area, outdoor theater, or other 

place of public assembly) that is occupied by 20 or more persons on at least 5 days a week for 10 

weeks in any 12-month period. (The days and weeks need not be consecutive.) 

(4) A Class 4 location is any class location unit where buildings with four or more stories 

above ground are prevalent. 

(c) The length of Class locations 2, 3, and 4 may be adjusted as follows: 

(1) A Class 4 location ends 220 yards (200 meters) from the nearest building with four or 




more stories above ground. 

(2) When a cluster of buildings intended for human occupancy requires a Class 2 or 3 

location, the class location ends 220 yards (200 meters) from the nearest building in the cluster. 

[Amdt. 192-27, 41 FR 34598, Aug. 16, 1976; Amdt. 192-56, 52 FR 32924, Sept. 1, 1987; Amdt. 192-78, 

61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996 and Amdt. 192- 

78 Correction, 61 FR 35139, July 5, 1996; Amdt. 192-85, 63 FR 37500, July 13, 1998] 


No guide material available at present. 

§192.7 

What documents are incorporated by reference partly or wholly in this part? 


(a) Any documents or portions thereof incorporated by reference in this part are included in 

this part as though set out in full. When only a portion of a document is referenced, the remainder is 

not incorporated in this part. 

(b) All incorporated materials are available for inspection in the Pipeline and Hazardous 

Materials Safety Administration, 400 Seventh Street, SW., Washington, DC, or at the National 

Archives and Records Administration (NARA). For information on the availability of this material at 

NARA, call 202–741–6030 or go to: 

http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html. These 

materials have been approved for incorporation by reference by the Director of the Federal Register 

in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. In addition, the incorporated materials are 

available from the respective organizations listed in paragraph (c) (1) of this section. 

(c) The full titles of documents incorporated by reference, in whole or in part, are provided 

herein. The numbers in parentheses indicate applicable editions. For each incorporated document, 

citations of all affected sections are provided. Earlier editions of currently listed documents or 

editions of documents listed in previous editions of 49 CFR part 192 may be used for materials and 

components designed, manufactured, or installed in accordance with these earlier documents at the 

time they were listed. The user must refer to the appropriate previous edition of 49 CFR part 192 for 

a listing of the earlier listed editions or documents. 

(1) Incorporated by reference (IBR). List of Organizations and Addresses: 

A. Pipeline Research Council International, Inc. (PRCI), c/o Technical Toolboxes, 3801 

Kirby Drive, Suite 520, Houston, TX 77098. 

B. American Petroleum Institute (API), 1220 L Street, NW, Washington, DC 20005. 

C. American Society for Testing and Materials (ASTM), 100 Barr Harbor Drive, West 

Conshohocken, PA 19428. 

D. ASME International (ASME), Three Park Avenue, New York, NY 10016–5990. 

E. Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. 

(MSS), 127 Park Street, NE, Vienna, VA 22180. 

F. National Fire Protection Association (NFPA), 1 Batterymarch Park, P.O. Box 9101, 

Quincy, MA 02269–9101. 

G. Plastics Pipe Institute, Inc. (PPI), 1825 Connecticut Avenue, NW, Suite 680, 

Washington, DC 20009. 

H. NACE International (NACE), 1440 South Creek Drive, Houston, TX 77084. 

I. Gas Technology Institute (GTI), 1700 South Mount Prospect Road, Des Plaines, IL 

60018. 




(2) Documents incorporated by reference (Numbers in Parentheses Indicate Applicable Editions). 

Source and name of referenced material 49 CFR reference 

A. Pipeline Research Council International, Inc. (PRCI): 

(1) AGA Pipeline Research Committee, Project PR–3–805, ‘‘A 

Modified Criterion for Evaluating the Remaining Strength of 

Corroded Pipe,’’ (December 22, 1989). The RSTRENG program 

may be used for calculating remaining strength. 

B. American Petroleum Institute (API): 

(1) API Specification 5L ‘‘Specification for Line Pipe,’’ (43rd 

edition and errata, 2004). 

(2) API Recommended Practice 5L1 ‘‘Recommended Practice 

for Railroad Transportation of Line Pipe,’’ (6th edition, 2002). 

(3) API Specification 6D ‘‘Pipeline Valves,’’ (22nd edition, 

January 2002). 

(4) API Recommended Practice 80, ‘‘Guidelines for the 

Definition of Onshore Gas Gathering Lines,’’ (1st edition, April 

2000). 

(5) API 1104 ‘‘Welding of Pipelines and Related Facilities,’’ 

(19th edition, 1999, including Errata October 31, 2001). 

(6) API Recommended Practice 1162 ‘‘Public Awareness 

Programs for Pipeline Operators,’’ (1 st edition December 2003). 

C. American Society for Testing and Materials (ASTM): 

(1) ASTM A 53/A53M–04a (2004) ‘‘Standard Specification for 

Pipe, Steel, Black and Hot-Dipped, Zinc-Coated, Welded and 

Seamless.’’ 

(2) ASTM A106/A106M-04b (2004) ‘‘Standard Specification for 

Seamless Carbon Steel Pipe for High-Temperature Service.’’ 

(3) ASTM A333/A333M-05 (2005) ‘‘Standard Specification for 

Seamless and Welded Steel Pipe for Low-Temperature 

Service.’’ 

(4) ASTM A372/A372M-03 (2003) ‘‘Standard Specification for 

Carbon and Alloy Steel Forgings for Thin-Walled Pressure 

Vessels.’’ 

(5) ASTM A381–96 (Reapproved 2001) ‘‘Standard 

Specification for Metal-Arc-Welded Steel Pipe for Use With 

High-Pressure Transmission Systems.’’ 

(6) ASTM A671-04 (2004) ‘‘Standard Specification for Electric- 

Fusion-Welded Steel Pipe for Atmospheric and Lower 

Temperatures.’’ 

(7) ASTM A672-96 (Reapproved 2001) ‘‘Standard 

Specification for Electric-Fusion-Welded Steel Pipe for High- 

Pressure Service at Moderate Temperatures.’’ 

Addendum No. 8, April 2007 22 

§§192.933(a); 192.485(c). 

§§192.55(e); 192.113; Item I of 

Appendix B. 

§192.65(a). 

§192.145(a). 

§§192.8(a); 192.8(a)(1); 192.8(a)(2); 

192.8(a)(3); 192.8(a)(4). 

§§192.227(a); 192.229(c)(1); 

192.241(c); Item II, Appendix B. 

§§192.616(a); 192.616(b); 

192.616(c). 

§§192.113; Item I, Appendix B. 



§192.177(b)(1). 



§§192.113; Item I, Appendix B.



[Amdt. 192-37, 46 FR 10157, Feb. 2, 1981; Amdt. 192-51, 51 FR 15333, Apr. 23, 1986; Amdt. 192-68, 58 

FR 14519, Mar. 18, 1993; 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 with Amdt. 192-94 Correction, 69 

FR 54591, Sept. 9, 2004; RIN 2137-AD77, 70 FR 11135, Mar. 8, 2005; Amdt. 192-99, 70 FR 28833, May 

19, 2005 with Amdt. 192-99 Correction, 70 FR 35041, June 16, 2005; Amdt. 192-102, 71 FR 13289, Mar. 

15, 2006; Amdt. 192-103, 71 FR 33402, June 9, 2006; Amdt. 192-103, 72 FR 4655, Feb. 1, 2007] 



Additional standards and specifications recommended for use under this Guide, and the names and 

addresses of the sponsoring organizations, are shown in Guide Material Appendix G-192-1. See Guide 

Material Appendix G-192-1A for documents previously incorporated by reference in the Regulations. 

§192.8 

How are onshore gathering lines and regulated onshore gathering 

lines determined? 


(a) An operator must use API RP 80 (incorporated by reference, see §192.7), to determine if 

an onshore pipeline (or part of a connected series of pipelines) is an onshore gathering line. The 

determination is subject to the limitations listed below. After making this determination, an 

operator must determine if the onshore gathering line is a regulated onshore gathering line under 

paragraph (b) of this section. 

(1) The beginning of gathering, under section 2.2(a)(1) of API RP 80, may not extend 

beyond the furthermost downstream point in a production operation as defined in section 2.3 of 

API RP 80. This furthermost downstream point does not include equipment that can be used in 

either production or transportation, such as separators or dehydrators, unless that equipment is 

involved in the processes of ‘‘production and preparation for transportation or delivery of 

hydrocarbon gas’’ within the meaning of ‘‘production operation.’’ 

(2) The endpoint of gathering, under section 2.2(a)(1)(A) of API RP 80, may not extend 

beyond the first downstream natural gas processing plant, unless the operator can demonstrate, 

using sound engineering principles, that gathering extends to a further downstream plant. 

(3) If the endpoint of gathering, under section 2.2(a)(1)(C) of API RP 80, is determined by 

the commingling of gas from separate production fields, the fields may not be more than 50 miles 

from each other, unless the Administrator finds a longer separation distance is justified in a 

particular case (see 49 CFR §190.9). 

(4) The endpoint of gathering, under section 2.2(a)(1)(D) of API RP 80, may not extend 

beyond the furthermost downstream compressor used to increase gathering line pressure for 

delivery to another pipeline. 

(b) For purposes of §192.9, ‘‘regulated onshore gathering line’’ means: 

(1) Each onshore gathering line (or segment of onshore gathering line) with a feature 

described in the second column that lies in an area described in the third column; and 

(2) As applicable, additional lengths of line described in the fourth column to provide a 

safety buffer: 




Type Feature Area Safety Buffer 

A — Metallic and the MAOP Class 2, 3, or 4 location 

None. 

produces a hoop stress of 

20 percent or more of 

SMYS. If the stress level is 

unknown, an operator 

must determine the stress 

level according to the 

applicable provisions in 

subpart C of this part. 

(see §192.5). 

— Non-metallic and the 

MAOP is more than 125 

psig (862 kPa). 

B — Metallic and the MAOP 

produces a hoop stress of 

less than 20 percent of 

SMYS. If the stress level is 

unknown, an operator 

must determine the stress 

level according to the 

applicable provisions in 

subpart C of this part. 

— Non-metallic and the 

MAOP is 125 psig (862 

kPa) or less. 

[Issued by Amdt. 192-102, 71 FR 13289, Mar. 15, 2006] 

Addendum No. 5, May 2005 26 

Area 1. Class 3 or 4 

location. 

Area 2. An area within a 

Class 2 location the 

operator determines by 

using any of the following 

three methods: 

(a) A Class 2 location. 

(b) An area extending 150 

feet (45.7 m) on each side 

of the centerline of any 

continuous 1 mile (1.6 km) 

of pipeline and including 

more than 10 but fewer 

than 46 dwellings. 

(c) An area extending 150 

feet (45.7 m) on each side 

of the centerline of any 

continuous 1000 feet (305 

m) of pipeline and 

including 5 or more 

buildings. 



If the gathering line is in 

Area 2(b) or 2(c), the 

additional lengths of line 

extend upstream and 

downstream from the area 

to a point where the line is 

at least 150 feet (45.7 m) 

from the nearest dwelling 

in the area. However, if a 

cluster of dwellings in area 

2(b) or 2(c) qualifies a line 

as Type B, the Type B 

classification ends 150 feet 

(45.7 m) from the nearest 

dwelling in the cluster.



[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] 


No guide material necessary. 

§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 ANSI/NFPA 58 and 59. 

(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 ANSI/NFPA 58 and 59, ANSI/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] 

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. 

Addendum No. 8, April 2007 28(a)



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 

Outlet of 

regulation 

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

NATURAL GAS DISTRIBUTION 

PIPING SYSTEM 

Distribution 

Main 

Point of Petroleum 

Gas/Air Injection 

District Regulator 

Station 

(RE: TITLE 49 CFR PART 192) 

FIGURE 192.11A 

Distribution 

Service Line 

Customer 

Meter 

CUSTOMER FUEL PIPING 

Outlet of meter or connection to customer’s 

piping, whichever is farther downstream 

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

Figure 192.11B depicts the standards applicable to pipeline systems for petroleum gas or petroleum 

gas/air mixtures, as described in §192.11(b). 

PETROLEUM GAS 

STORAGE/VAPORIZATION 

FACILITIES 

STORAGE VESSEL 

(RE: TITLE 49 CFR PART 192, 

NFPA 58 AND 59) 

VAPORIZER 

Outlet of 1st 

cut regulation 

PETROLEUM GAS DISTRIBUTION 

PIPING SYSTEM 

(In some cases, this may not exist, 

except for the customer meter) 

Overpressure 

Protection 

Customer 

Meter 

(RE: TITLE 49 CFR PART 192, 

NFPA 58 AND 59) 

FIGURE 192.11B 

Addendum No. 8, April 2007 28(b) 

CUSTOMER FUEL PIPING 

Outlet of meter or connection to customer’s 

piping, whichever is farther downstream 

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

GPTC GUIDE FOR GAS TRANSMISSION AND 192.121 

DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART C 

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 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) Magnetically-filled PE (reference ASTM D2513, Annex A.6) is considered as either PE 2406 or PE 

3408 material. 

(d) Long-term hydrostatic strength (LTHS) for reinforced thermosetting plastic covered by ASTM 

D2517 is 11,000 psi. 

(e) 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." 

(f) 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. 

Pipe Material HDB @ 73 °F, psi 

PA 32312 (PA 11) 2500 

PE 2406 1250 

PE 3408 1600 

PVC Type I, Grade 1, Class 12454B (PVC 1120)* 4000 

PVC Type II, Grade 1, Class 1433D (PVC 2116)* 3200 

* Editions of ASTM D2513 issued after 2001 no longer permit use of PVC piping for new 

gas piping installations, but do specify that it may be used for repair and maintenance of 

existing PVC gas piping. The Regulations may continue to reference an edition of ASTM 

D2513 earlier than 2001. The operator is advised to check §192.7. 

2 PETROLEUM GASES 

TABLE 192.121i 

PE and PA materials listed in ASTM D2513 may be used for liquid petroleum gas (LPG) piping 

applications. NFPA 58 (referenced by §192.7) prescribes the following: 

(a) PA may be used in liquid or vapor LPG systems up to the design pressure of the piping material. 

PPI recommends a chemical derating factor of 1.0 (no derating) for PA 11 piping. 

(b) PE, when recommended by the manufacturer, may be used in vapor-only LPG systems up to 30 

psig pressure. PPI recommends a 0.5 chemical derating factor for the use of PE piping. 

(c) PVC is not permitted. 

Some information on the strengths of polyethylenes with propane is given in PPI TR-22, “Polyethylene 

Piping Distribution Systems for Components of Liquid Petroleum Gases.” See guide material under 

§192.123. 


GPTC GUIDE FOR GAS TRANSMISSION AND 192.121 

DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART C 

3 MINIMUM REQUIRED WALL THICKNESS 

The minimum wall thickness (tm) for a given design pressure is determined from the formula below. 

Also, see §§192.123 (c) and (d) plus 3 of the guide material under §192.123. 

Where: 

tm = PD 

(P + 0.64 S) 

P = Design pressure, gauge, kPa (psi) 

D = Specified outside diameter, mm (in.) 

S = The long-term hydrostatic strength, for thermoplastic pipe, kPa (psi) determined at 23 o C 

(73 o F), 38 o C (100 o F), 49 o C (120 o F), or 60 o C (140 o F); for reinforced thermosetting 

pipe, 75,800 kPa (11,000 psi) 

4 INTERPOLATION OF HYDROSTATIC DESIGN BASIS (HDB) VALUES 

(a) For thermoplastic pipe that is to be installed at a service temperature greater than 73 ºF and less 

than that at which the next HDB has been established, the HDB at the anticipated service 

temperature can be determined by interpolation. The pipe manufacturer should be consulted for 

assistance in determining an interpolated HDB. 

(b) The interpolation formula as prescribed in §192.121 is published in PPI TR-3 as follows. 

Where: 

S 

T 

= S 

L 

( S 

− 

L 

1 

− SH)( 

TL 

− 

1 

) 

TT 

1 

( 

TL 

− 

1 

) 

TH 

ST = Interpolated LTHS for the anticipated service temperature (psi) 

SL = LTHS established at a temperature below the anticipated service temperature (psi) 

SH = LTHS established at a temperature above the anticipated service temperature (psi) 

TL = Temperature at which the lower LTHS (SL) was established (K) 

TT = Anticipated service temperature (K) 

TH = Temperature at which the higher LTHS (SH) was established (K) 

(c) Section 192.121 requires that the interpolation be made between the LTHS values at the lower and 

higher temperatures. The resulting interpolated LTHS is categorized into an HDB. This interpolated 

HDB is then used to determine the design pressure under §192.121. 

(d) Example: 

An operator is installing SDR 11 PE pipe where the anticipated service temperature is 78 ºF. HDB 

values are established and published in PPI TR-4 at 73 ºF (296 K) and 140 ºF (333 K). Thus, the 

operator has the option of establishing an interpolated HDB at the anticipated service temperature, 

78 °F (299 K), or using the 140 °F HDB of 800 psi. 

(1) In order to calculate the HDB for the anticipated service temperature, the operator must obtain 

the actual LTHS values established for the material at the nearest temperature above and 

below the temperature for which the interpolated value is to be determined. These values are 

typically available from the pipe supplier. If these LTHS values are not available, the lowest 

LTHS for the HDB category in Table 192.121ii may be used as a conservative estimate. 

(2) Once the LTHS values are obtained, the interpolation calculation input is as follows. 

SL(73 °F) = 1567 psi 

SH(140 °F) = 845 psi 

TL = 73 ºF (295.93 K) 

TT = 78 ºF (298.71 K) 

TH = 140 ºF (333.15 K) 

Addendum No. 6, September 2006 44


DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART D 

SUBPART D 

DESIGN OF PIPELINE COMPONENTS 

§192.141 

Scope. 


This subpart prescribes minimum requirements for the design and installation of pipeline 

components and facilities. In addition, it prescribes requirements relating to protection against 

accidental overpressuring. 


Useful industry references for design and construction of auxiliary piping for compressor stations or other 

similar installations (other than gas piping) are listed in Table 192.141i. Federal, state and local requirements 

may also apply. 

Piping System Fluid Design Code 

Power piping (boiler external 

piping) 

Power piping (non-boiler external 

piping) 

Utility, auxiliary, process, air 

injection 

Air, steam, water, oil, gas, steam 

condensate 

Air, steam, water, oil, gas, steam 

condensate 

Air, steam, water, oil, steam 

condensate, glycol, natural gas 

liquids 

ASME B31.1 

ASME B31.3 

ASME B31.3 

Process Hydrocarbons, chemicals ASME B31.3 

Refrigeration Refrigerant (e.g., propane) ASME B31.3 or B31.5 

Fire protection Water NFPA 14 and 24 

Drinking and domestic supply Water AWWA Standards; Uniform 

Plumbing Code 

Plumbing and drains Sanitary and waste water Uniform Plumbing Code 


§192.143 

General requirements. 

� [Effective Date: 5-23-07] 

(a) Each component of a pipeline must be able to withstand operating pressures and other 

anticipated loadings without impairment of its serviceability with unit stresses equivalent to those 

allowed for comparable material in pipe in the same location and kind of service. However, if design 

based upon unit stresses is impractical for a particular component, design may be based upon a 

pressure rating established by the manufacturer by pressure testing that component or a prototype 

of the component. 




(b) The design and installation of pipeline components and facilities must meet applicable 

requirements for corrosion control found in subpart I of this part. 

[Amdt. 192-48, 49 FR 19823, May 10, 1984; Amdt. 192-104, 72 FR 20055, April 23, 2007] 



The designer should select components that will withstand the field test pressure to which they will be 

subjected without failure or leakage and without impairment to their serviceability. Consideration should also 

be given to pulsation-induced vibrations that could produce excessive cyclic stresses. 

See Guide Material Appendix G-192-9 and Guide Material Appendix G-192-10. 

§192.144 

Qualifying Metallic Components. 


Notwithstanding any requirement of this subpart which incorporates by reference an edition of 

a document listed in §192.7 or Appendix B of this part, a metallic component manufactured in 

accordance with any other edition of that document is qualified for use under this part if -- 

(a) It can be shown through visual inspection of the cleaned component that no defect exists 

which might impair the strength or tightness of the component; and 

(b) The edition of the document under which the component was manufactured has equal or 

more stringent requirements for the following as an edition of that document currently or previously 

listed in §192.7 or appendix B of this part: 

(1) Pressure testing; 

(2) Materials; and 

(3) Pressure and temperature ratings. 

[Issued by Amdt. 192-45, 48 FR 30637, July 5, 1983; Amdt. 192-94, 69 FR 32886, June 14, 2004] 


See Guide Material Appendix G-192-1A for documents previously incorporated by reference in the 

Regulations. Current documents incorporated by reference that were listed in Appendix A prior to 

Amendment 192-94, published June 14, 2004, are now found in §192.7. 

If the edition of the document under which the component was manufactured was neither previously listed 

nor currently listed in §192.7, and was not previously listed in Appendix A, then requirements under 

§192.144(b) should be reviewed to determine if the metallic component is qualified for use under Part 192. 




§192.145 

Valves. 


(a) Except for cast iron and plastic valves, each valve must meet the minimum requirements of 

API 6D (incorporated by reference, see §192.7), or to a national or international standard that 

provides an equivalent performance level. A valve may not be used under operating conditions that 

exceed the applicable pressure-temperature ratings contained in those requirements. 

(b) Each cast iron and plastic valve must comply with the following: 

(1) The valve must have a maximum service pressure rating for temperatures that equal or 

exceed the maximum service temperature. 

(2) The valve must be tested as part of the manufacturing, as follows: 

(i) With the valve in the fully open position, the shell must be tested with no leakage 

to a pressure at least 1.5 times the maximum service rating. 

(ii) After the shell test, the seat must be tested to a pressure not less than 1.5 times 

the maximum service pressure rating. Except for swing check valves, test pressure during the seat 

test must be applied successively on each side of the closed valve with the opposite side open. No 

visible leakage is permitted. 

(iii) After the last pressure test is completed, the valve must be operated through its 

full travel to demonstrate freedom from interference. 

(c) Each valve must be able to meet the anticipated operating conditions. 

(d) No valve having shell components made of ductile iron may be used at pressures exceeding 

80 percent of the pressure ratings for comparable steel valves at their listed temperature. However, a 

valve having shell components made of ductile iron may be used at pressures up to 80 percent of 

the pressure ratings for comparable steel valves at their listed temperature, if -- 

(1) The temperature-adjusted service pressure does not exceed 1,000 p.s.i (7MPa) gage; 

and 

(2) Welding is not used on any ductile iron component in the fabrication of the valve shells 

or their assembly. 

(e) No valve having pressure-containing parts made of ductile iron may be used in the gas pipe 

components of compressor stations. 

[Amdt. 192-3, 35 FR 17659, Nov. 17, 1970; Amdt. 192-22, 41 FR 13589, Mar. 31, 1976; Amdt. 192-37, 46 

FR 10157, Feb. 2, 1981; Amdt. 192-62, 54 FR 5625, Feb. 6, 1989; 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] 


1 FLANGED CAST IRON VALVES IN STEEL PIPELINES 

Consideration should be given to the effect of secondary stresses (e.g., resulting from earth movement, 

expansion and contraction or other external forces) which could affect the structural integrity of flanged 

cast iron valves in steel pipelines. Adequate support, compression couplings, or other means may be 

used. 

2 EQUIVALENCY 

2.1 Equivalent standards. 

Valve standards API Spec 6A, API Std 600, ASME B16.33, ASME B16.34, and ASME B16.38 provide 

an equivalent performance level to API Spec 6D for gas application purposes. 




2.2 Valves not listed in API Spec 6D. 

Although all valve sizes (such as those smaller than 2 inches) are not listed in API Spec 6D, 

manufacturers may design, build and test non-listed sizes in accordance with all applicable 

requirements of API Spec 6D and, thereby, meet the equivalency criteria. However, application of the 

API monogram to valve sizes not listed in the API Specification is not permitted. 

3 PRESSURE-TEMPERATURE RATING 

Any valve which cannot comply to the API Spec 6D standard pressure-temperature rating because of 

material(s) which require a reduced maximum temperature limit should be provided with markings on 

the nameplate showing the maximum pressure rating at that temperature and with the pressure rating 

at 100 o F. 

§192.147 

Flanges and flange accessories. 


(a) Each flange or flange accessory (other than cast iron) must meet the minimum requirements 

of ASME/ANSI B16.5, MSS SP-44, or the equivalent. 

(b) Each flange assembly must be able to withstand the maximum pressure at which the 

pipeline is to be operated and to maintain its physical and chemical properties at any temperature to 

which it is anticipated that it might be subjected in service. 

(c) Each flange on a flanged joint in cast iron pipe must conform in dimensions, drilling, face 

and gasket design to ASME/ANSI B16.1 and be cast integrally with the pipe, valve, or fitting. 

[Amdt. 192-62, 54 FR 5625, Feb. 6, 1989; Amdt. 192-68, 58 FR 14519, Mar. 18, 1993] 

1 FLANGES 


1.1 Flange types. 

(a) The dimensions and drilling for all line or end flanges should conform to one of the following 

standards. 

ASME B16 Series listed in Appendix A (for iron and steel) 

MSS SP-44 Steel Pipe Line Flanges 

Flanges cast or forged integral with pipe, fittings or valves in sizes and for the maximum service 

rating covered by the standards listed above may be used subject to the facing, bolting and 

gasketing requirements of this paragraph and 1.2, 2.1 and 2.2 below. 

(b) Threaded companion flanges that comply with the B16 group of American National Standards, in 

sizes and for maximum service ratings covered by these standards, may be used. 

(c) Lapped flanges in sizes and pressure standards established by ASME B16.5 may be used. 

(d) Slip-on welding flanges in sizes and pressure standards established in ASME B16.5 may be used. 

Slip-on flanges or rectangular section may be substituted for hubbed slip-on flanges provided the 

thickness is increased as required to produce equivalent strength as determined by calculations 

made in accordance with Section VIII, Pressure Vessels, of the ASME Boiler and Pressure Vessel 

Code. 




(e) Welding neck flanges in sizes and pressure standards established in ASME B16.5, ASME B16.47, 

and MSS SP-44 may be used. The bore of the flanges should correspond to the inside diameter of 

the pipe used. For acceptable welding end treatment see Figure 192.235B in Guide Material 

Appendix G-192-5. 

(f) Flanges made of ductile iron should conform to material and dimensional standards listed in 

§192.145(a) and should be subject to all service restrictions as outlined for valves in that 

paragraph. The bolting requirements for ductile-iron flanges should be the same as for carbon and 

low-alloy steel flanges as listed in 2.1 below. 

1.2 Flange facings. 

(a) Cast iron, ductile iron, and steel flanges should have contact faces finished in accordance with 

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

Fittings. 

(b) Class 25 and Class 125 cast iron integral or threaded companion flanges may be used with a 

full-face gasket or with a flat ring gasket extending to the inner edge of the bolt holes. When using a 

full-face gasket, the bolting may be of alloy steel (ASTM A193). When using a ring gasket, the 

bolting should be of carbon steel, without heat treatment other than stress relief, equivalent to 

ASTM A307 Grade B. 

(c) When bolting together two Class 250 integral or threaded companion cast iron flanges, having 1/16 

inch raised faces, the bolting should be of carbon steel, without heat treatment other than stress 

relief, equivalent to ASTM A307 Grade B. 

(d) Class 150 steel flanges may be bolted to Class 125 cast iron flanges. When such construction is 

used, the 1/16 inch raised face on the steel flange should be removed. When bolting such flanges 

together, using a flat ring gasket extending to the inner edge of the bolt holes, the bolting should be 

of carbon steel, without heat treatment other than stress relief, equivalent to ASTM A307 Grade B. 

When bolting such flanges together using a full-face gasket, the bolting may be alloy steel (ASTM 

A193). 

(e) Class 300 steel flanges may be bolted to Class 250 cast iron flanges. Where such construction is 

used, the bolting should be of carbon steel, without heat treatment other than stress relief, 

equivalent to ASTM A307 Grade B. It is recommended that the raised face on the steel flange be 

removed. When this is done, bolting should be of carbon steel, without heat treatment other than 

stress relief, equivalent to ASTM A307 Grade B. 

(f) Forged steel welding neck flanges have an outside diameter and drilling the same as ASME B16.1, 

but with modified flange thicknesses, hub dimensions, and special facing details, may be used to 

bolt against flat-faced cast iron flanges, and may operate at the pressure-temperature ratings given 

in ASME B16.1 Class 125 Cast Iron Pipe Flanges provided: 

(1) The minimum flange thickness, T, of the steel flange is not less than that specified for size 6 

inch and larger. 

(2) Flanges are used with nonmetallic full-face gaskets extending to the periphery of the flange. 

(3) The design joint has been proven by test to be suitable for the ratings. 

2 FLANGE ACCESSORIES 

2.1 Bolting. 

(a) For all flange joints other than described under 1.2(c), (d), (e) and (f), the bolting should be made of 

alloy steel conforming to ASTM A193, A320 or A354, or of heat-treated carbon steel conforming to 

ASTM A449. However, bolting for American National Standard Class 250 and 300 flanges to be 

used at temperatures between minus 20 o F and plus 450 o F may be made to ASTM A307, Grade 

B. 

(b) Alloy steel bolting material conforming to ASTM A193 or ASTM A354 should be used for insulating 

flanges if such bolting is made 1/8 inch undersized. 

(c) The materials used for nuts should conform to ASTM A194 and A307. A307 nuts may be used only 

with A307 bolting. 

(d) All carbon and alloy steel bolts, stud bolts, and their nuts should be threaded in accordance with the 

following thread series and dimension class as required by ASME B1.1. 




(1) Carbon Steel--All carbon steel bolts and stud bolts should have coarse threads, Class 2A 

dimensions and their nuts, Class 2B dimensions. 

(2) Alloy Steel--All alloy steel bolts and stud bolts of 1 inch and smaller nominal diameters should 

be of the coarse thread series; nominal diameters 1 1/8 inch and larger should be of the 8 

thread series. Bolts and stud bolts should have a Class 2A dimension, and their nuts should 

have a Class 2B dimension. 

(e) Bolts should have American National Standard regular square heads or heavy hexagonal heads 

and should have American National Standard heavy hexagonal nuts conforming to the dimensions 

of ASME B18.2.1 and B18.2.2. 

(f) Nuts cut from bar stock in such a manner that the axis will be parallel to the direction of rolling of 

the bar may be used in all sizes for joints in which one or both flanges are cast iron, and for joints 

with steel flanges where the pressure does not exceed 250 p.s.i.g. Such nuts should not be used 

for joints in which both flanges are steel and the pressure exceeds 250 p.s.i.g. except that, for nut 

sizes 1/2 inch and smaller, these limitations do not apply. 

(g) For all flange joints, the bolts or stud bolts used should extend completely through the nuts. 

2.2 Gaskets. 

(a) Material for gaskets should be capable of withstanding the maximum pressure and maintaining its 

physical and chemical properties at any temperature to which it might reasonably be subjected in 

service. 

(b) Gaskets used under pressure and at temperatures above 250 o F should be of noncombustible 

material. Metallic gaskets should not be used with Class 150 standard or lower-rated flanges. 

(c) Full-face gaskets should be used with all bronze flanges, and may be used with Class 25 or Class 

125 cast iron flanges. Flat ring gaskets with outside diameter extending to the inside of the bolt 

holes may be used with cast iron flanges, with raised face steel flanges, or with lapped steel 

flanges. 

(d) In order to secure higher unit compression on the gasket, metallic gaskets of a width less than the 

full male face of the flange may be used with raised face, lapped, or large male and female facings. 

The width of the gasket for small male and female or for tongue and groove joints should be equal 

to the width of the male face or tongue. 

(e) Rings for ring joints should be of dimensions established in ASME B16.20. The material for these 

rings should be suitable for the service conditions encountered and should be softer than the 

flanges. 



DISTRIBUTION PIPING SYSTEMS: 2003 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. 


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 in accordance with welding procedures 

qualified under section 5 of API 1104 (incorporated by reference, see §192.7) or section IX of the 

ASME Boiler and Pressure Vessel Code ‘‘Welding and Brazing Qualifications’’ (incorporated by 

reference, see §192.7) to produce welds meeting the requirements of this subpart. The quality of the 

test welds used to qualify welding procedures shall be determined by destructive testing in 

accordance with the applicable 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] 


Additional references for welding procedures include the following. 

(a) ASME B31.8, "Gas Transmission and Distribution Piping Systems." 



DISTRIBUTION PIPING SYSTEMS: 2003 Edition Subpart E 

(b) API Std 1104, "Welding of Pipelines and Related Facilities," Appendix B, "In-Service Welding.” 

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 must be qualified in 

accordance with section 6 of API 1104 (incorporated by reference, see §192.7) or section IX of the 

ASME Boiler and Pressure Vessel Code (incorporated by reference, see §192.7). However, a welder 

qualified under an earlier edition than listed in §192.7 of this part may weld but may not requalify 

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] 


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 whose qualification is based on nondestructive testing may weld compressor 

station pipe and components. 



DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART I 

(c) Each bared test lead wire and bared metallic area at point of connection to the pipeline must 

be coated with an electrical insulating material compatible with the pipe coating and the insulation 

on the wire. 

[Issued by Amdt 192-4, 36 FR 12297, June 30, 1971] 

1 INSTALLATION METHODS 

Some acceptable methods include the following. 


1.1 Thermit welding. 

(a) Steel. Attachment of electrical leads directly to steel pipe by the thermit welding process using 

copper oxide and aluminum powder. The thermit welding charge should be limited to a 15-gram 

cartridge. 

(b) Cast iron. Attachment of electrical leads directly to cast or ductile-iron pipe by the thermit welding 

process using copper oxide and aluminum powder. The thermit welding charge should be limited to 

a 32-gram cartridge. 

1.2 Solder connections. 

Attachment of electrical leads directly to steel pipe with the use of soft solders or other materials that do 

not involve temperatures exceeding those for soft solders. 

1.3 Brazing. 

Attachment of electrical leads to steel pipe by brazing, provided that the pipeline operates at less than 

29 percent SMYS. 

1.4 Mechanical connections. 

Mechanical connections which remain secure and electrically conductive. 

2 OTHER CONSIDERATIONS 

For convenience, conductors may be coded or permanently identified. Wire should be installed with 

slack. Damage to insulation should be avoided. Repairs should be made if damage occurs. Test leads 

should not be exposed to excessive heat or excessive sunlight. 

§192.473 

External corrosion control: Interference currents. 


(a) Each operator whose pipeline system is subjected to stray currents shall have in effect a 

continuing program to minimize the detrimental effects of such currents. 

(b) Each impressed current type cathodic protection system or galvanic anode system must be 

designed and installed so as to minimize any adverse effects on existing adjacent underground 

metallic structures. 

[Issued by Amdt. 192-4, 36 FR 12297, June 30, 1971; Amdt. 192-33, 43 FR 39389, Sept. 5, 1978] 




1 REFERENCE 

A reference is NACE RP0169, Section 9. 

2 INSTALLATION CONSIDERATIONS 


(a) Attention should be given to a new pipeline's physical location, particularly if the location may 

subject the pipeline to stray electrical currents from other facilities, such as the following. 

(1) Other pipelines or utilities with associated cathodic protection systems. 

(2) Rail transit systems. 

(3) Mining or welding operations. 

(4) Induced currents from electrical transmission lines. 

(b) To the extent possible, the operator should identify and plan for the mitigation and control of 

anticipated stray electrical currents prior to construction. As soon as practicable after construction 

of the pipeline or facility to be protected is completed, the operator should implement monitoring, 

testing, and mitigation plans to control the effects of stray electrical currents. The rate of corrosion 

caused by stray electrical current can be higher than the rate of corrosion resulting from galvanic 

action. 

3 EXTERNAL CORROSION CONTROL EFFECTIVENESS 

Once the interference control methods have been established, periodic tests and inspections should be 

conducted to ensure their continued effectiveness. See §192.465(b), (c), and (d) for inspection and test 

requirements for cathodic protection rectifiers and interference bonds. 

§192.475 

Internal corrosion control: General. 


(a) Corrosive gas may not be transported by pipeline, unless the corrosive effect of the gas on 

the pipeline has been investigated and steps have been taken to minimize internal corrosion. 

(b) Whenever any pipe is removed from a pipeline for any reason, the internal surface must be 

inspected for evidence of corrosion. If internal corrosion is found -- 

(1) The adjacent pipe must be investigated to determine the extent of internal corrosion; 

(2) Replacement must be made to the extent required by the applicable paragraphs of 

§§192.485, 192.487, or 192.489; and 

(3) Steps must be taken to minimize the internal corrosion. 

(c) Gas containing more than 0.25 grain of hydrogen sulfide per 100 cubic feet (5.8 

milligrams/m 3 ) at standard conditions (4 parts per million) may not be stored in pipe-type or 

bottle-type holders. 

[Issued by Amdt. 192-4, 36 FR 12297, June 30, 1971; Amdt. 192-33, 43 FR 39389, Sept. 5, 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] 




1 GENERAL 


In the presence of free water, gases containing certain constituents, such as carbon dioxide, hydrogen 

sulfide, and oxygen, can be corrosive to steel pipelines. Pipeline liquids may combine with these 

constituents and cause corrosion that may be detrimental to pipeline integrity. Because of this, 

monitoring and evaluating corrosion, operating conditions, gas quality, and liquids found in pipelines are 

important elements of internal corrosion control programs. The following are considerations for 

managing internal corrosion. 

2 DESIGN CONSIDERATIONS 

If it is anticipated or has been determined that the gas to be transported is corrosive, the following 

should be considered for the design of the pipeline system. 

(a) Selection of special materials. 

(1) Nonmetallic materials. 

(2) Nonferrous metals. 

(3) Special alloy steels. 

(b) Selection of steel pipe. 

(1) Increased wall thickness. 

(2) Pipe grade. 

(3) Metallurgy. 

(4) Internal coating. 

(c) Effect of high, low, or no flow velocities and liquid accumulation. 

(d) Piping configurations that can contribute to changes in flow velocities, which can cause the 

free water and constituents to settle out of the gas stream and build into concentrations that 

could lead to internal corrosion. Examples of these configurations include the following. 

(1) Dead ends. 

(2) Sags or low spots. 

(3) Fittings and mechanical connections. 

(4) Sharp bends (vertical or horizontal). 

(5) Sudden diameter changes. 

(6) Drips. 

(e) Corrosion monitoring devices and access fittings for them. 

(f) Physical location of the pipe, since external climate, heat sources, and environment can affect 

internal temperature. 

(g) Selection and location of liquid separation, dehydration, or gas scrubbing equipment. 

3 DETECTION METHODS 

The following may be used to detect internal corrosion. 

(a) Visual inspection of piping and components. 

(1) Access ports. 

(2) Selective cut-outs. 

(b) Corrosion monitoring devices. 

(1) Corrosion coupons and spools. 

(2) Resistance probes. 

(3) Polarization probes. 

(4) Hydrogen probes and patches. 

(5) Electrochemical probes. 

(c) Sampling. 

(1) Liquids analysis. 

(i) Chemical composition. 

(ii) Microbiological composition. 

(2) Gas composition analysis. 




(3) Solids analysis. 

(i) Chemical composition. 

(ii) Microbiological composition. 

(d) Trending of analytical data. 

(e) Internal inspection tools. 

(f) Ultrasonic inspection. 

(g) Radiography. 

(h) Failure analysis. 

(i) Internal corrosion direct assessment. 

4 FREQUENCY 

The following considerations could impact the frequency of monitoring or testing. 

(a) Location and history of water removal. 

(b) Age and condition of pipe and drips. 

(c) Internal corrosion history, including leaks and ruptures. 

(d) Liquids composition. 

(e) Gas composition. 

(f) System operating parameters (e.g., temperature, pressure, volumes transported, wet system vs. 

dry). 

(g) System physical layout (e.g., topography). 

(h) Flow characteristics. 

(i) Proximity to dwellings and the public. 

(j) Pipeline segments downstream of production or storage fields where free water and constituents 

might accumulate. 

(k) Solids composition. 

(l) Past inspection results. 

(m) Past results obtained using corrosion monitoring devices. 

(n) System design (e.g., materials of construction, pipe wall thickness, pigging facilities, presence of 

drips). 

5 MITIGATIVE MEASURES 

The following measures can be used to mitigate internal corrosion. 

(a) Control of moisture level (e.g., by dehydration, separation, or temperature control). 

(b) Reduction of corrosive constituents (chemical or biological) in the gas. 

(c) Internal coating. 

(d) Liquids or solids removal. 

(1) Pigging - frequency of pigging will depend on both the volume and the analysis of materials 

received during pigging operations. 

(2) Drips - frequency of operation will depend on both the volume and analysis of materials 

removed. 

(3) Separators - frequency of maintenance will depend on changes in results from liquids analyses. 

(e) Chemical or biological treatments. 

(1) Treatments should not cause deterioration of piping system components. 

(2) Treatments should be compatible with the following. 

(i) Gas being transported. 

(ii) Downstream gas utilization and processing equipment. 

(iii) Any other treatments. 

6 REFERENCES 

(a) See 2 of the guide material under §192.53. 

(b) NACE MR0175, “Materials for Use in H2S-Containing Environments in Oil and Gas Production.” 




(c) NACE RP0175, “Control of Internal Corrosion in Steel Pipelines and Piping Systems” (Revised 

1975; Discontinued). 

(d) NACE RP0192, “Monitoring Corrosion in Oil and Gas Production with Iron Counts.” 

(e) NACE RP0775, “Preparation, Installation, Analysis, and Interpretation of Corrosion Coupons in 

Oilfield Operations.” 

(f) NACE TM0194, “Field Monitoring of Bacterial Growth in Oilfield Systems.” 

(g) NACE 3D170, Technical Committee Report, “Electrical and Electrochemical Methods for 

Determining Corrosion Rates” (Revised 1984; Withdrawn 1994). 

(h) “Evaluation of Chemical Treatments in Natural Gas System vs. MIC and Other Forms of Internal 

Corrosion Using Carbon Steel Coupons,” Timothy Zintel, Derek Kostuck, and Bruce 

Cookingham, Paper # 03574 presented at CORROSION/03 San Diego, CA. 

(i) “Field Guide for Investigating Internal Corrosion of Pipelines,” Richard Eckert, NACE Press, 

2003. 

(j) “Field Use Proves Program for Managing Internal Corrosion in Wet-Gas Systems,” Richard 

Eckert and Bruce Cookingham, Oil & Gas Journal, January 21, 2002. 

(k) “Internal Corrosion Direct Assessment,” Oliver Moghissi, Bruce Cookingham, Lee Norris, and 

Phil Dusek, Paper # 02087 presented at CORROSION/02 Denver, CO. 

(l) “Internal Corrosion Direct Assessment of Gas Transmission Pipeline – Application,” Oliver 

Moghissi, Laurie Perry, Bruce Cookingham, and Narasi Sridhar, Paper # 03204 presented at 

CORROSION/03 San Diego, CA. 

(m) “Internal Corrosion Direct Assessment of Gas Transmission Pipeline - Methodology,” Oliver 

Moghissi, Bruce Cookingham, Lee Norris, Narasi Sridhar, and Phil Dusek, Gas Research 

Institute Report GRI-02/0057. 

(n) “Microscopic Differentiation of Internal Corrosion Initiation Mechanisms in a Natural Gas 

System,” Richard Eckert, Henry Aldrich, and Chris Edwards, Bruce Cookingham, Paper # 03544 

presented at CORROSION/03 San Diego, CA. 


� §192.476 

� Internal corrosion control: Design and construction of transmission line. 

� [Effective Date:5-23-07] 

(a) Design and construction. Except as provided in paragraph (b) of this section, each new 

transmission line and each replacement of line pipe, valve, fitting, or other line component in a 

transmission line must have features incorporated into its design and construction to reduce the 

risk of internal corrosion. At a minimum, unless it is impracticable or unnecessary to do so, each 

new transmission line or replacement of line pipe, valve, fitting, or other line component in a 

transmission line must: 

(1) Be configured to reduce the risk that liquids will collect in the line; 

(2) Have effective liquid removal features whenever the configuration would allow liquids 

to collect; and 

(3) Allow use of devices for monitoring internal corrosion at locations with significant 

potential for internal corrosion. 

(b) Exceptions to applicability. The design and construction requirements of paragraph (a) of 

this section do not apply to the following: 

(1) Offshore pipeline; and 

(2) Pipeline installed or line pipe, valve, fitting or other line component replaced before 

May 23, 2007. 

(c) Change to existing transmission line. When an operator changes the configuration of a 

transmission line, the operator must evaluate the impact of the change on internal corrosion risk 

to the downstream portion of an existing onshore transmission line and provide for removal of 

liquids and monitoring of internal corrosion as appropriate.



(d) Records. An operator must maintain records demonstrating compliance with this section. 

Provided the records show why incorporating design features addressing paragraph (a)(1), (a)(2), 

or (a)(3) of this section is impracticable or unnecessary, an operator may fulfill this requirement 

through written procedures supported by as-built drawings or other construction records. 

[Issued by Amdt. 192-104, 72 FR 20055, Apr. 23, 2007] 


Guide Material 


§192.477 

Internal corrosion control: Monitoring. 


If corrosive gas is being transported, coupons or other suitable means must be used to 

determine the effectiveness of the steps taken to minimize internal corrosion. Each coupon or other 

means of monitoring internal corrosion must be checked two times each calendar year, but with 

intervals not exceeding 7½ months. 

[Issued by Amdt. 192-4, 36 FR 12297, June 30, 1971; Amdt. 192-33, 43 FR 39389, Sept. 5, 1978] 


(a) Devices that can be used to monitor internal corrosion or the effectiveness of corrosion mitigation 

measures include hydrogen probes, corrosion probes, corrosion coupons, test spools, and 

nondestructive testing equipment capable of indicating loss in wall thickness. 

(b) Consideration should be given to the site selection and the type of access station used to expose the 

device to on-stream monitoring. It is desirable to incorporate a retractable feature in the monitoring 

station to avoid facility shutdowns during periodic inspections, such as weight loss measurements, and 

for on-stream pigging of the facility. 

(c) A written procedure should be established to determine that the monitoring device is operating properly. 

(d) See guide material under §192.475 if internal corrosion is discovered or is not under mitigation. 

§192.479 

Atmospheric corrosion control: General. 


(a) Each operator must clean and coat each pipeline or portion of pipeline that is exposed to 

the atmosphere, except pipelines under paragraph (c) of this section. 

(b) Coating material must be suitable for the prevention of atmospheric corrosion. 

(c) Except portions of pipelines in offshore splash zones or soil-to-air interfaces, the operator 

need not protect from atmospheric corrosion any pipeline for which the operator demonstrates by 

test, investigation, or experience appropriate to the environment of the pipeline that corrosion will--



(1) Only be a light surface oxide; or 

(2) Not affect the safe operation of the pipeline before the next scheduled inspection. 


192-93, 68 FR 53895, Sept. 15, 2003] 

1 GENERAL 


(a) The need for coating can be determined by experience in the same or essentially identical 

environment. 

(b) The degree of surface preparation, the selection of the coating materials, and the application 

procedures must be selected to achieve the desired coating system life span. A reference is the 

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

Volume 2), which is published by the Steel Structures Painting Council. 

(c) See guide material under §192.481 for determining areas of atmospheric corrosion. 

2 EXPOSED PIPING AND RELATED FACILITIES 

The following methods should be considered for exposed piping and related facilities. 

(a) Use of coating. See 1 above. 

(b) Selection of corrosion resistant materials. 

(c) Avoidance of areas where prevailing winds or other conditions will deposit corrosive materials 

(such as salt, moisture, or industrial effluent). Protection in these areas can be provided by 

selecting a more appropriate meter and regulator location or by using a protective housing. 

(d) Use of materials or coatings or both suitable for the environment may be required for facilities 

installed in pits, vaults, or casings and that may be periodically submerged or exposed to excessive 

condensation. 

(e) Protection of regulator vent lines from plugging by corrosion products. Where practical, the vent line 

should be installed in a self-drain position and, where necessary, extended above possible flood 

level. 

(f) Use of material for vent tubing that is compatible with the environment encountered. For example, 

some kinds of plastic tubing should not be exposed to direct sunlight, and certain aluminum alloys 

should not be submerged or placed in contact with concrete. 

§192.481 

Atmospheric corrosion control: Monitoring. 


(a) Each operator must inspect each pipeline or portion of pipeline that is exposed to the 

atmosphere for evidence of atmospheric corrosion, as follows: 




If the pipeline is located: 

Onshore ................................ 

Offshore ................................ 

Then the frequency of inspection is: 

At least once every 3 calendar 

years, but with intervals not 

exceeding 39 months 

At least once each calendar year, 

but with intervals not exceeding 

15 months 

(b) During inspections the operator must give particular attention to pipe at soil-to-air 

interfaces, under thermal insulation, under disbonded coatings, at pipe supports, in splash zones, at 

deck penetrations, and in spans over water. 

(c) If atmospheric corrosion is found during an inspection, the operator must provide 

protection against the corrosion as required by §192.479. 

[Issued by Amdt. 192-4, 36 FR 12297, June 30, 1971; Amdt. 192-27, 41 FR 34598, Aug. 16, 1976; Amdt. 

192-33, 43 FR 39389, Sept. 5, 1978; Amdt. 192-93, 68 FR 53895, Sept. 15, 2003] 


DETERMINING AREAS OF ATMOSPHERIC CORROSION 

(a) The presence of atmospheric corrosion can be detected best by visual inspection. 

(1) This may require ladders, scaffolds, hoists, or other suitable means of permitting inspector 

access to the structure being inspected. In addition to the locations listed in §192.481(b), 

attention should be given to locations such as clamps, rest plates, and sleeved openings. 

(2) Piping that is thermally or acoustically insulated (jacketed) should be inspected wherever 

practical. To minimize damage to the insulation, a visual inspection of the pipe may be 

performed by cutting windows into the insulation. 

(b) Exposure test racks can be used to evaluate coatings and materials in local environments such as 

industrial, coastal, and offshore locations. Many standard procedures or test methods for evaluating 

materials and coatings are available from the ASTM International. 

(c) Evidence of atmospheric corrosion on meters and regulators may also be determined by inspection 

by operator employees such as meter readers and leak survey personnel. 

§192.483 

Remedial measures: General. 


(a) Each segment of metallic pipe that replaces pipe removed from a buried or submerged 

pipeline because of external corrosion must have a properly prepared surface and must be provided 

with an external protective coating that meets the requirements of §192.461. 

(b) Each segment of metallic pipe that replaces pipe removed from a buried or submerged 

pipeline because of external corrosion must be cathodically protected in accordance with this 




subpart. 

(c) Except for cast iron or ductile iron pipe, each segment of buried or submerged pipe that is 

required to be repaired because of external corrosion must be cathodically protected in accordance 

with this subpart. 

[Issued by Amdt. 192-4, 36 FR 12297, June 30, 1971] 



§192.485 

Remedial measures: Transmission lines. 


(a) General corrosion. Each segment of transmission line pipe with general corrosion and with 

a remaining wall thickness less than that required for the MAOP of the pipeline must be replaced or 

the operating pressure reduced commensurate with the strength of the pipe based on actual 

remaining wall thickness. However, corroded pipe may be repaired by a method that reliable 

engineering tests and analyses show can permanently restore the serviceability of the pipe. 

Corrosion pitting so closely grouped as to affect the overall strength of the pipe is considered 

general corrosion for the purpose of this paragraph. 

(b) Localized corrosion pitting. Each segment of transmission line pipe with localized corrosion 

pitting to a degree where leakage might result must be replaced or repaired, or the operating 

pressure must be reduced commensurate with the strength of the pipe, based on the actual 

remaining wall thickness in the pits. 

(c) Under paragraphs (a) and (b) of this section, the strength of pipe based on actual remaining 

wall thickness may be determined by the procedure in ASME/ANSI B31G or the procedure in AGA 

Pipeline Research Committee Project PR 3-805 (with RSTRENG disk). Both procedures apply to 

corroded regions that do not penetrate the pipe wall, subject to the limitations prescribed in the 

procedures. 


192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996; Amdt. 

192-88, 64 FR 69660, Dec. 14, 1999] 

1 EVALUATION 



1.1 Introduction. 

The evaluation of the pressure strength of a corroded region in a transmission pipeline to determine 

its suitability for continued service can be made by an analytical method, by pressure testing, or by 

an alternate method. 

1.2 Pressure testing. 

The pipe containing the corroded region may be pressure tested to confirm the established MAOP, 




or to determine a lower MAOP. The pressure test should be in accordance with the general 

requirements of Subpart J (in particular §192.503), and the pressure should be held for at least 8 

hours. The established MAOP may be confirmed by testing to a pressure at least equal to the MAOP 

times the appropriate factor in Table 192.485i or ii below. A lower MAOP may be established by 

dividing the successful test pressure by the appropriate factor. 

(a) For pipeline segments that have not been confirmed for operation in the next higher class 

location, see §192.611: 

Class Location Factor 

Class 1 locations 

No buildings for human occupancy within 300 feet 

With buildings for human occupancy within 300 feet 

1.10 

1.25 

Class 2 locations 1.25 

Class 3 & 4 locations and Meter & Compressor Station 

piping in Class 1 & 2 locations 


(b) For pipeline segments that are required to be qualified for an existing class location, see 

§192.611: 

Class Location Factor 

Class 2 

Class 3 

Class 4 

TABLE 192.485ii 

1.3 Alternate Method. 

For conditions of low stress level, the following method may be used. An MAOP, not to exceed the 

established MAOP, may be determined by the following formula: 

1.25 

1.50 

1.80 

P 

StrT = 

D 

2 

Where: 

P = MAOP (not to exceed established MAOP), psig 

S = hoop stress, psig 

tr = actual remaining wall thickness at point of deepest corrosion, inches 

T = temperature derating factor, see §192.115 

D = pipe outside diameter, inches 

S must not exceed 72 percent of SMYS in Class 1 locations, 60 percent in Class 2 locations, 50 

percent in Class 3 locations, and 40 percent in Class 4 locations. 


1.5



2 REPAIR OR REPLACEMENT 

If a pipeline has an area of external corrosion that disqualifies it for service at the established MAOP, or 

if the MAOP cannot be reduced to the indicated safe level, it should be repaired or replaced. For 

acceptable methods of repair, see §§192.711(b), 192.717, and guide material under §192.713. 

§192.487 

Remedial measures: Distribution lines other than cast iron or ductile iron lines. 


(a) General corrosion. Except for cast iron or ductile iron pipe, each segment of generally 

corroded distribution line pipe with a remaining wall thickness less than that required for the MAOP 

of the pipeline, or a remaining wall thickness less than 30 percent of the nominal wall thickness, 

must be replaced. However, corroded pipe may be repaired by a method that reliable engineering 

tests and analyses show can permanently restore the serviceability of the pipe. Corrosion pitting so 

closely grouped as to affect the overall strength of the pipe is considered general corrosion for the 

purpose of this paragraph. 

(b) Localized corrosion pitting. Except for cast iron or ductile iron pipe, each segment of 

distribution line pipe with localized corrosion pitting to a degree where leakage might result must be 

replaced or repaired. 

[Issued by Amdt. 192-4, 36 FR 12297, June 30, 1971; Amdt. 192-88, 64 FR 69660, Dec. 14, 1999] 



Where inspection indicates that pitting exists which may result in leakage, the operator should consider the 

following. 

(a) Examining the corrosion history and leak records to see if the additional information from this 

examination warrants replacement of a segment of this distribution pipe. 

(b) Installing leak clamps on or over the pits. 

(c) Cleaning and coating the exposed piping in accordance with §192.461. 

(d) Applying cathodic protection. 

(e) Installing test wires for monitoring cathodic protection. 

§192.489 

Remedial measures: Cast iron and ductile iron pipelines. 


(a) General graphitization. Each segment of cast iron or ductile iron pipe on which general 

graphitization is found to a degree where a fracture or any leakage might result, must be replaced. 

(b) Localized graphitization. Each segment of cast iron or ductile iron pipe on which localized 

graphitization is found to a degree where any leakage might result, must be replaced or repaired, or 

sealed by internal sealing methods adequate to prevent or arrest any leakage. 

[Issued by Amdt. 192-4, 36 FR 12297, June 30, 1971] 





(a) For cast iron pipe, see Guide Material Appendix G-192-18. 

(b) For ductile iron, see 4.3(b) of Guide Material Appendix G-192-18. 

§192.490 

Direct assessment. 


Each operator that uses direct assessment as defined in §192.903 on an onshore transmission line 

made primarily of steel or iron to evaluate the effects of a threat in the first column must carry out 

the direct assessment according to the standard listed in the second column. These standards do 

not apply to methods associated with direct assessment, such as close interval surveys, voltage 

gradient surveys, or examination of exposed pipelines, when used separately from the direct 

assessment process. 

Threat Standard 1 

External corrosion §192.925 2 

Internal corrosion in pipelines that transport dry 

gas 

§192.927 

Stress corrosion cracking §192.929 

1 For lines not subject to Subpart O of this part, the terms "covered 

segment" and "covered pipeline segment" in §§192.925, 192.927, and 

192.929 refer to the pipeline segment on which direct assessment is 

performed. 

2 In §192.925(b), the provision regarding detection of coating damage 

applies only to pipelines subject to Subpart O of this part. 

[Issued by Amdt. 192-101, 70 FR 61571, Oct. 25, 2005] 



§192.491 

Corrosion control records. 


(a) Each operator shall maintain records or maps to show the location of cathodically protected 

piping, cathodic protection facilities, galvanic anodes, and neighboring structures bonded to the 

cathodic protection system. Records or maps showing a stated number of anodes, installed in a 

Addendum No. 8, April 2007 166(b)


DISTRIBUTION PIPING SYSTEMS: SUBPART I 

stated manner or spacing, need not show specific distances to each buried anode. 

(b) Each record or map required by paragraph (a) of this section must be retained for as long as 

the pipeline remains in service. 

(c) Each operator shall maintain a record of each test, survey, or inspection required by this 

subpart in sufficient detail to demonstrate the adequacy of corrosion control measures or that a 

corrosive condition does not exist. These records must be retained for at least 5 years, except that 

records related to §§192.465(a) and (e) and 192.475(b) must be retained for as long as the pipeline 

remains in service. 


192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996] 


In addition to the specific requirements of §192.491, the data contained in the records or maps used for 

corrosion control should include the following. 

(a) Location of test stations. 

(b) Location of rectifiers and groundbeds. 

(c) Location of galvanic anodes. 

(d) Location of corrosion control facilities, such as insulating flanges or connections, bonds, automatic 

switches, and diodes. 

(e) Readings of pipe to soil potential. 

(f) Length and location of cathodically protected segments of piping. 

(g) Location of unprotected metallic piping. 

(h) Date cathodic protection facilities placed in service. 

Addendum No. 8, April 2007 166(c)



Reserved 

Addendum No. 8, April 2007 166(d)


DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART J 

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 percent SMYS is 

recommended. 

(b) Pipelines and mains crossing highways and railroads may be tested in the same manner and to the 

same pressure as the pipeline on each side of the crossing. 

(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. 

*See Guide Material Appendix G-192-9. 

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 

Amendment No. 8, April 2007 169


DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART J 

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. 

(c) 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. 

4.2 Test procedure. 

It is recommended that pressure in the test segment be applied in increments equal to 25 percent of the 

total test pressure. At the end of each incremental increase, the pressure should be maintained while 

the test segment is checked for leaks or other sources of rapid decline in pressure. 

4.3 Locating leaks. 

The location of leaks may be determined visually, by sound, by smell, or by utilizing leak detection 

equipment. The leak detection method to be used is dependent upon the test media. Caution -- multiple 

leaks may exist. 

4.4 Repairs. 

It may be prudent to lower pressure in the test segment prior to exposing the pipe for repair. While 

temporary repairs may be made to accommodate the test, permanent repairs must satisfy requirements 

of §§192.309, 192.711, 192.713, 192.715, or 192.717 as applicable. 

Amendment No. 8, April 2007 170


DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART M 

1.3 Increased frequency. 

Consideration should be given to increased frequency for leakage surveys based on the particular 

circumstances and conditions. Surveys should be conducted most frequently in those areas with the 

greatest potential for leakage and where leakage could be expected to create a hazard. Factors to be 

considered in establishing the frequency of leakage surveys include the following. 

(a) Piping system. Age of pipe, materials, type of facilities, operating pressure, leak history records, 

and other studies. 

(b) Corrosion. Known areas of significant corrosion, or areas where corrosive environments are known 

to exist. Cased crossings of roads, highways, railroads, etc., due to susceptibility to unique 

corrosive conditions. 

(c) Piping location. Proximity to buildings or other structures and the type and use of the buildings. 

Proximity to areas of concentrations of people. 

(d) Environmental conditions and construction activity. Conditions that could increase the potential 

for leakage or cause leaking gas to migrate to an area where it could create a hazard, such as 

the following. 

(1) Weather conditions. 

(2) Areas of known frost heaving. 

(3) Wall to wall pavement. 

(4) Porous soil conditions. 

(5) Areas of high construction activity. 

(6) Trenchless excavation activities (e.g., boring). 

(7) Blasting. See Guide Material Appendix G-192-16. 

(8) Large earth moving equipment. 

(9) Heavy traffic. 

(10) Unstable soil or areas subject to earth movement. 

(e) Other. Any other condition known to the operator that has significant potential to initiate a leak or 

to permit leaking gas to migrate to an area where it could result in a hazard, such as the 

following. 

(1) Earthquake. 

(2) Subsidence. 

(3) Flooding. 

(4) An increase in operating pressure. 

(5) The extensive growth of tree roots around pipeline facilities that can exert substantial 

longitudinal force on the pipe and nearby joints. 

1.4 Special one-time surveys. 

Special one-time surveys should be considered following exposure of the pipeline to unusual stresses 

(e.g., earthquakes, blasting) or trenchless installation of foreign buried facilities that cross gas pipelines. 

1.5 Establishment and review of survey frequency. 

Leakage survey frequencies should be based on operating experience, sound judgment, and a 

knowledge of the system. Once established, frequencies should be reviewed periodically to affirm that 

they are still appropriate. Leakage surveys may be accomplished in conjunction with patrolling, 

scheduled inspections, and other routine activities. 

2 GAS LEAKAGE CONTROL GUIDELINES 

See Guide Material Appendices G-192-11 for natural gas systems and G-192-11A for petroleum gas 

systems. 

237



§192.725 

Test requirements for reinstating service lines. 


(a) Except as provided in paragraph (b) of this section, each disconnected service line must be 

tested in the same manner as a new service line, before being reinstated. 

(b) Each service line temporarily disconnected from the main must be tested from the point of 

disconnection to the service line valve in the same manner as a new service line, before 

reconnecting. However, if provisions are made to maintain continuous service, such as by 

installation of a bypass, any part of the original service line used to maintain continuous service 

need not be tested. 



§192.727 

Abandonment or deactivation of facilities. 


(a) Each operator shall conduct abandonment or deactivation of pipelines in accordance with 

the requirements of this section. 

(b) Each pipeline abandoned in place must be disconnected from all sources and supplies of 

gas; purged of gas; in the case of offshore pipelines, filled with water or inert materials; and sealed 

at the ends. However, the pipeline need not be purged when the volume of gas is so small that there 

is no potential hazard. 

(c) Except for service lines, each inactive pipeline that is not being maintained under this part 

must be disconnected from all sources and supplies of gas; purged of gas; in the case of offshore 

pipelines, filled with water or inert materials; and sealed at the ends. However, the pipeline need not 

be purged when the volume of gas is so small that there is no potential hazard. 

(d) Whenever service to a customer is discontinued, one of the following must be complied 

with: 

(1) The valve that is closed to prevent the flow of gas to the customer must be provided 

with a locking device or other means designed to prevent the opening of the valve by persons other 

than those authorized by the operator. 

(2) A mechanical device or fitting that will prevent the flow of gas must be installed in the 

service line or in the meter assembly. 

(3) The customer's piping must be physically disconnected from the gas supply and the 

open pipe ends sealed. 

(e) If air is used for purging, the operator shall insure that a combustible mixture is not present 

after purging. 

(f) Each abandoned vault must be filled with a suitable compacted material. 

(g) For each abandoned offshore pipeline facility or each abandoned onshore pipeline facility 

that crosses over, under or through a commercially navigable waterway, the last operator of that 

facility must file a report upon abandonment of that facility. 

(1) The preferred method to submit data on pipeline facilities abandoned after October 10, 

2000 is to the National Pipeline Mapping System (NPMS) in accordance with the NPMS ``Standards 

for Pipeline and Liquefied Natural Gas Operator Submissions.'' To obtain a copy of the NPMS 

Standards, please refer to the NPMS homepage at http://www.npms.phmsa.dot.gov or contact the 

NPMS National Repository at 703-317-3073. A digital data format is preferred, but hard copy 




submissions are acceptable if they comply with the NPMS Standards. In addition to the NPMSrequired 

attributes, operators must submit the date of abandonment, diameter, method of 

abandonment, and certification that, to the best of the operator's knowledge, all of the reasonably 

available information requested was provided and, to the best of the operator's knowledge, the 

abandonment was completed in accordance with applicable laws. Refer to the NPMS Standards for 

details in preparing your data for submission. The NPMS Standards also include details of how to 

submit data. 

Alternatively, operators may submit reports by mail, fax or e-mail to the Pipeline and Hazardous 

Materials Safety Administration, U.S. Department of Transportation, Room 2103, 400 Seventh Street, 

SW., Washington DC 20590; fax (202) 366-4566; e-mail, roger.little@.dot.gov. The 

information in the report must contain all reasonably available information related to the facility, 

including information in the possession of a third party. The report must contain the location, size, 

date, method of abandonment, and a certification that the facility has been abandoned in 

accordance with all applicable laws. 

(2) [Reserved]. 

[Amdt. 192-8, 37 FR 20694, Oct. 3, 1972; Amdt. 192-27, 41 FR 34598, Aug. 16, 1976; Amdt. 192-71, 59 

FR 6579, Feb. 11, 1994; Amdt. 192-89, 65 FR 54440, Sept. 8, 2000 with Amdt. 192-89 Correction, 65 FR 

57861, Sept. 26, 2000; RIN 2137-AD77, 70 FR 11135, Mar. 8, 2005; Amdt. 192-103, 72 FR 4655, Feb. 

1, 2007] 


The following general procedures are recommended and should be applied where appropriate. For planned 

shutdown in connection with abandonment or deactivation, see Guide Material Appendix G-192-12. 

1 ABANDONMENT OF TRANSMISSION PIPELINES AND DISTRIBUTION MAINS 

1.1 Check prior to abandonment. 

Office records should be checked and necessary field checks should be made to ensure the pipelines 

or mains scheduled for abandonment are disconnected from all sources and supplies of gas, such as 

other pipelines, mains, cross-over piping, meter stations, customer piping, control lines, and other 

appurtenances. 

1.2 Residual gas or hydrocarbons. 

Abandonment should not be completed until it has been determined that the volume of natural gas or 

liquid hydrocarbons contained within the abandoned section poses no potential hazard. Generally, it is 

advisable to purge 8-inch and larger pipe and long segments of smaller diameter pipe. 

1.3 Purging. 

Pipelines or mains may be purged using air, inert gas, or water. If air is used as the purging agent, 

precautions should be taken to ensure that no liquid hydrocarbons are present. See §192.629 and AGA 

XK0101, “Purging Principles and Practice” for purging of natural gas and liquid hydrocarbons. 

1.4 Sealing. 

Acceptable methods of sealing pipeline or main openings include, as applicable, the following. 

(a) Using normal end closures, such as welded or screwed caps, screwed plugs, blind flanges, and 

mechanical joint caps and plugs. 

(b) Welding steel plate to pipe ends. 

(c) Filling ends with a suitable plug material. 

(d) Pinching the ends closed. 

1.5 Additional considerations in addition to purging and sealing. 

In addition to purging and sealing, consideration should be given to the following. 




(a) Filling the abandoned segment with water or an inert gas to prevent potential combustion hazard. 

(b) Other action designed to prevent hazardous cave-ins resulting from pipe collapse caused by 

corrosion or external loading. 

1.6 Segmenting the abandoned sections. 

All valves left in the abandoned segment should be closed. If the segment is long and there are few line 

valves, consideration should be given to plugging the segment at intervals. 

1.7 Removal of above-grade facilities and filling voids. 

All above-grade valves, risers, and vault and valve box covers should be removed. Vault and valve box 

voids should be filled with suitable compacted backfill material. 

2 ABANDONMENT OF DISTRIBUTION SERVICE LINES IN CONJUNCTION WITH MAIN 

ABANDONMENT 

2.1 Curb valves and curb boxes. 

All curb valves should be closed. The top section of curb boxes located in dirt areas should be removed 

and the void filled with suitable compacted backfill material. If boxes are set in concrete or asphalt, they 

should be filled with suitable compacted backfill material to an appropriate distance from the top of the 

box and the fill completed with suitable paving material. 

2.2 Meter risers and headers. 

Meter risers and headers should be dismantled and removed from the premises. 

2.3 Service lines below grade through a basement wall. 

Where a service line enters below grade through a basement wall, the end of the service line should be 

plugged and a cap should be installed as close to the face of the wall as practical. It is not necessary to 

remove pipe from the wall unless required by particular circumstances. 

2.4 Outside meter set and above-grade entrances. 

Service lines terminating at an outside meter set or an above-grade entrance should be cut and capped 

at an appropriate depth below grade. 

3 ABANDONMENT OF SERVICE LINES FROM ACTIVE MAINS 

3.1 Disconnecting. 

Service lines abandoned from active mains should be disconnected as close to the main as practical. 

3.2 Sealing. 

The end of the abandoned portion of the service line nearest the main should be plated, capped, 

plugged, pinched, or otherwise effectively sealed. 

3.3 Other actions. 

The remainder of the service line should be abandoned as recommended in 2 above. 

4 INACTIVE PIPELINES 

4.1 General. 

Each operator should consider the following elements when determining whether to abandon or 

continue maintaining an inactive pipeline. 

(a) Location (e.g., business district, urban, suburban, rural). 

(b) Type of piping material. 

(c) Joining method (e.g., welding, fusion, compression couplings). 

(d) Cathodic protection. 

(e) Operating pressure. 




(f) Likelihood of reactivation. 

(g) Leakage and maintenance history. 

(h) Proposed construction. 

4.2 Continuing maintenance. 

Provisions for continuing maintenance of inactive pipelines should be included in the procedural manual 

for operations, maintenance, and emergencies required under §192.605. (See guide material under 

§192.3 for definition of “inactive pipeline.”) Examples of such maintenance include the following. 

(a) Regularly scheduled leakage surveys and patrolling. 

(b) Corrosion control monitoring of cathodically protected systems. 

(c) Maps and records for damage prevention. 

(d) Evaluating aboveground piping for the following. 

(i) Atmospheric corrosion. 

(ii) Susceptibility to damage from vehicles and other forces. 

(iii) Unauthorized activities. 

5 INACTIVE SERVICE LINES 

In addition to 4.2 above, the operator should consider the following for continuing maintenance of 

inactive service lines. 

(a) Identifying and documenting the location of inactive service lines in a record management system. 

(b) Developing criteria for abandonment. 

§192.729 

(Removed.) 

§192.731 


Compressor stations: Inspection and testing of relief devices. 


(a) Except for rupture discs, each pressure relieving device in a compressor station must be 

inspected and tested in accordance with §§192.739 and 192.743, and must be operated periodically 

to determine that it opens at the correct set pressure. 

(b) Any defective or inadequate equipment found must be promptly repaired or replaced. 

(c) Each remote control shutdown device must be inspected and tested at intervals not 

exceeding 15 months, but at least once each calendar year, to determine that it functions properly. 

[Amdt. 192-43, 47 FR 46850, Oct. 21, 1982] 



§192.733 

(Removed.) 


[Effective Date: 2-11-95]



§192.735 

Compressor stations: Storage of combustible materials. 

[Effective Date: ]11-12-70 

(a) Flammable or combustible materials in quantities beyond those required for everyday use, 

or other than those normally used in compressor buildings, must be stored a safe distance from the 

compressor building. 

(b) Aboveground oil or gasoline storage tanks must be protected in accordance with National 

Fire Protection Association Standard No. 30. 



§192.736 

Compressor stations: Gas detection. 



(a) Not later than September 16, 1996, each compressor building in a compressor station must 

have a fixed gas detection and alarm system, unless the building is-- 

(1) Constructed so that at least 50 percent of its upright side area is permanently open; or 

(2) Located in an unattended field compressor station of 1,000 horsepower (746 kW) or less. 

(b) Except when shutdown of the system is necessary for maintenance under paragraph (c) of 

this section, each gas detection and alarm system required by this section must-- 

(1) Continuously monitor the compressor building for a concentration of gas in air of not 

more than 25 percent of the lower explosive limit; and 

(2) If that concentration of gas is detected, warn persons about to enter the building and 

persons inside the building of the danger. 

(c) Each gas detection and alarm system required by this section must be maintained to 

function properly. The maintenance must include performance tests. 

[Issued by Amdt. 192-69, 58 FR 48460, Sept. 16, 1993; Amdt. 192-85, 63 FR 37500, July 13, 1998] 

1 GENERAL 


See §192.171 for design of gas detection and alarm systems. 

2 MAINTENANCE AND TESTING OF GAS DETECTION AND ALARM SYSTEMS 

The operator should develop the following. 

(a) Maintenance and testing procedures to ensure proper function of the gas detectors and alarm 

system. 

(b) Procedures for calibrating the gas detection equipment and verifying that the alarms are 

functioning properly.


DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART O 

SUBPART O 

GAS TRANSMISSION PIPELINE INTEGRITY MANAGEMENT 

§192.901 

What do the regulations in this subpart cover? 


This subpart prescribes minimum requirements for an integrity management program on any 

gas transmission pipeline covered under this part. For gas transmission pipelines constructed of 

plastic, only the requirements in §§192.917, 192.921, 192.935 and 192.937 apply. 

[Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 

15, 2004] 

1 GENERAL 


The requirements of Subpart O apply to all transmission pipelines including compressor stations, 

metering stations, regulator stations, valve sets, and other fabricated assemblies. The requirements of 

Subpart O do not apply to distribution lines or to gathering lines. 

2 APPLICABILITY OF THIS SUBPART 

Table 192.901i identifies the applicability of each section of Subpart O to plastic line pipe, steel line pipe 

and pipeline components. In the table, “Components” refers to gas-carrying components other than line 

pipe that are typically above ground, such as compressor stations, meter stations, and regulator 

stations. 

APPLICABILITY OF SUBPART O 

Legend: R = Required; C = Consider; NA = Not Applicable 

Natural Gas Transmission Pipeline System 

Regulation 

Section 

Covered Segment (see §192.903) Non-Covered Segment 

Plastic 

Line Pipe 

Steel Line 

Pipe Components 

Plastic 

Line Pipe 

Steel 

Line Pipe Components 

192.901 R R R R R R 

192.903 R R R R R R 

192.905 R R R R R R 

192.907 R R R C C C 

192.909 R R R NA NA NA 

192.911 C R R NA NA NA 


Addendum No. 6, September 2006 262(i)



APPLICABILITY OF SUBPART O (Continued) 

Legend: R = Required; C = Consider; NA = Not Applicable 

Natural Gas Transmission Pipeline System 

Covered Segment (see §192.903) Non-Covered Segment 

Regulation Plastic Steel 

Plastic Steel 

Section Line Pipe Line Pipe Components Line Pipe Line Pipe 

192.913 

(if used) 

NA R R NA C C 

192.915 C R R C R R 

192.917 R R R R R R 

192.919 C R R NA NA NA 

192.921 R R R NA NA NA 

192.923 NA * * NA * * 

192.925 NA * * NA * * 

192.927 NA * * NA * * 

192.929 NA * * NA * * 

192.931 NA * * NA * * 

192.933 NA R R NA C C 

192.935 R R R NA R R 

192.937 R R R R R R 

192.939 C R R NA NA NA 

192.941 

(if used) 

NA R R NA C C 

192.943 

(if used) 

NA R R NA NA NA 

192.945 C R R C C C 

192.947 C R R C C C 

192.949 R R R NA NA NA 

192.951 NA R R NA NA NA 

* See guide material under these sections for detailed discussions. 


§192.903 

What definitions apply to this subpart? 

Component 

s 


The following definitions apply to this subpart. 

Assessment is the use of testing techniques as allowed in this subpart to ascertain the 

condition of a covered pipeline segment. 

Confirmatory direct assessment is an integrity assessment method using more focused 

application of the principles and techniques of direct assessment to identify internal and external 

corrosion in a covered transmission pipeline segment. 

Covered segment or covered pipeline segment means a segment of gas transmission pipeline 

located in a high consequence area. The terms gas and transmission line are defined in §192.3. 

Addendum No. 8, April 2007 262(j)



Direct assessment is an integrity assessment method that utilizes a process to evaluate certain 

threats (i.e., external corrosion, internal corrosion and stress corrosion cracking) to a covered 

pipeline segment’s integrity. The process includes the gathering and integration of risk factor data, 

indirect examination or analysis to identify areas of suspected corrosion, direct examination of the 

pipeline in these areas, and post assessment evaluation. 

High consequence area means an area established by one of the methods described in 

paragraphs (1) or (2) as follows: 

(1) An area defined as — 

(i) A Class 3 location under §192.5; or 

(ii) A Class 4 location under §192.5; or 

(iii) Any area in a Class 1 or Class 2 location where the potential impact radius is 

greater than 660 feet (200 meters), and the area within a potential impact circle contains 20 or more 

buildings intended for human occupancy; or 

(iv) Any area in a Class 1 or Class 2 location where the potential impact circle contains 

an identified site. 

(2) The area within a potential impact circle containing — 

(i) 20 or more buildings intended for human occupancy, unless the exception in 

paragraph (4) applies; or 

(ii) An identified site. 

(3) Where a potential impact circle is calculated under either method (1) or (2) to establish a 

high consequence area, the length of the high consequence area extends axially along the length of 

the pipeline from the outermost edge of the first potential impact circle that contains either an 

identified site or 20 or more buildings intended for human occupancy to the outermost edge of the 

last contiguous potential impact circle that contains either an identified site or 20 or more buildings 

intended for human occupancy. (See Figure E.I.A. in Appendix E.) 

(4) If in identifying a high consequence area under paragraph (1)(iii) of this definition or 

paragraph (2)(i) of this definition, the radius of the potential impact circle is greater than 660 feet (200 

meters), the operator may identify a high consequence area based on a prorated number of 

buildings intended for human occupancy with a distance 660 feet (200 meters) from the centerline of 

the pipeline until December 17, 2006. If an operator chooses this approach, the operator must 

prorate the number of buildings intended for human occupancy based on the ratio of an area with a 

radius of 660 feet (200 meters) to the area of the potential impact circle (i.e., the prorated number of 

buildings intended for human occupancy is equal to [20 x (660 feet [or 200 meters]/ potential impact 

radius in feet [or meters]) 2 ]). 

Identified site means each of the following areas: 

(a) An outside area or open structure that is occupied by twenty (20) or more persons on at 

least 50 days in any twelve (12)-month period. (The days need not be consecutive). Examples 

include but are not limited to, beaches, playgrounds, recreational facilities, camping grounds, 

outdoor theaters, stadiums, recreational areas near a body of water, or areas outside a rural building 

such as a religious facility); or 

(b) A building that is occupied by twenty (20) or more persons on at least five (5) days a 

week for ten (10) weeks in any twelve (12)-month period. (The days and weeks need not be 

consecutive). Examples include, but are not limited to, religious facilities, office buildings, 

community centers, general stores, 4-H facilities, or roller skating rinks); or 

(c) A facility occupied by persons who are confined, are of impaired mobility, or would be 

difficult to evacuate. Examples include but are not limited to hospitals, prisons, schools, day-care 

facilities, retirement facilities or assisted-living facilities. 

Potential impact circle is a circle of radius equal to the potential impact radius (PIR). 

Potential impact radius (PIR) means the radius of a circle within which the potential failure of a 

pipeline could have significant impact on people or property. PIR is determined by the formula r = 

0.69 * (square root of (p*d 2 )), where ‘r’ is the radius of a circular area in feet surrounding the point of 

failure, ‘p’ is the maximum allowable operating pressure (MAOP) in the pipeline segment in pounds 

per square inch and ‘d’ is the nominal diameter of the pipeline in inches. 

Addendum No. 8, April 2007 262(k)



Note: 0.69 is the factor for natural gas. This number will vary for other gases depending upon 

their heat of combustion. An operator transporting gas other than natural gas must use section 3.2 

of ASME/ANSI B31.8S-2001 (Supplement to ASME B31.8; incorporated by reference, see §192.7) to 

calculate the impact radius formula. 

Remediation is a repair or mitigation activity an operator takes on a covered segment to limit or 

reduce the probability of an undesired event occurring or the expected consequences from the 

event. 


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. 192-103, 72 FR 4655, Feb. 1, 2007] 


Glossary of Commonly Used Terms and Abbreviations Used in Subpart O 

BAP means baseline assessment plan. 

CDA means confirmatory direct assessment. 

DA means direct assessment. 

ECDA means external corrosion direct assessment. 

FAQs mean frequently asked questions. 

Framework is an early version of an operator’s Integrity Management Program (IMP), which does not have 

all the detailed processes in place. 

HCA means high consequence area. 

ICDA means internal corrosion direct assessment. 

IMP means Integrity Management Program. 

Low-frequency ERW (electric-resistance-welded) pipe is pipe that was manufactured using a 250-Hertz (Hz) 

alternating electrical current to provide heat for fusion of the weld seam. Most pipe made using this 

process was manufactured prior to 1970. 

Low-stress transmission line is a steel transmission line that operates below 30% SMYS. 

PIC means potential impact circle. 

PIR means potential impact radius. 

Plan is a particular component of the overall Integrity Management Program (IMP), and refers to a specific 

action plan and documented criteria for implementing a particular program element or rule requirement. 

Process is a step-by-step logical set of integrated activities that proceed from the initial understanding of 

what needs to be done, to the successful performance and documentation of results. 

Program is a document or a set of documents that systematically defines, controls, and implements integrity 

management. 

SCCDA means stress corrosion cracking direct assessment. 

Note: For other terms and abbreviations, see Glossary of Commonly Used Terms and Glossary of 

Commonly Used Abbreviations (Table 192.3i) of the guide material under §192.3. 

Addendum No. 8, April 2007 262(l)



integrity assessment results, data integration and risk assessment information (§192.917), and 

decisions about remediation (§192.933) and additional preventive and mitigative actions (§192.935). 

An operator must use the results from this evaluation to identify the threats specific to each covered 

segment and the risk represented by these threats. 

(c) Assessment methods. In conducting the integrity reassessment, an operator must assess 

the integrity of the line pipe in the covered segment by any of the following methods as appropriate 

for the threats to which the covered segment is susceptible (see §192.917), or by confirmatory direct 

assessment under the conditions specified in §192.931. 

(1) Internal inspection tool or tools capable of detecting corrosion, and any other threats to 

which the covered segment is susceptible. An operator must follow ASME/ANSI B31.8S 

(incorporated by reference, see §192.7), section 6.2 in selecting the appropriate internal inspection 

tools for the covered segment. 

(2) Pressure test conducted in accordance with subpart J of this part. An operator must use 

the test pressures specified in Table 3 of section 5 of ASME/ANSI B31.8S, to justify an extended 

reassessment interval in accordance with §192.939. 

(3) Direct assessment to address threats of external corrosion, internal corrosion, or stress 

corrosion cracking. An operator must conduct the direct assessment in accordance with the 

requirements listed in §192.923 and with as applicable, the requirements specified in §§192.925, 

192.927 or 192.929; 

(4) Other technology that an operator demonstrates can provide an equivalent 

understanding of the condition of the line pipe. An operator choosing this option must notify the 

Office of Pipeline Safety (OPS) 180 days before conducting the assessment, in accordance with 

§192.949. An operator must also notify a State or local pipeline safety authority when either a 

covered segment is located in a State where OPS has an interstate agent agreement, or an intrastate 

covered segment is regulated by that State. 

(5) Confirmatory direct assessment when used on a covered segment that is scheduled for 

reassessment at a period longer than seven years. An operator using this reassessment method 

must comply with §192.931. 


15, 2004 and Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004; 

Amdt. 192-103, 71 FR 33402, June 9, 2006] 



§192.939 

What are the required reassessment intervals? 


An operator must comply with the following requirements in establishing the reassessment 

interval for the operator’s covered pipeline segments. 

(a) Pipelines operating at or above 30% SMYS. An operator must establish a reassessment 

interval for each covered segment operating at or above 30% SMYS in accordance with the 

requirements of this section. The maximum reassessment interval by an allowable reassessment 

method is seven years. If an operator establishes a reassessment interval that is greater than seven 

years, the operator must, within the seven-year period, conduct a confirmatory direct assessment on 

the covered segment, and then conduct the follow-up reassessment at the interval the operator has 

established. A reassessment carried out using confirmatory direct assessment must be done in 

Addendum No. 6, September 2006 262(am)



accordance with §192.931. The table that follows this section sets forth the maximum allowed 

reassessment intervals. 

(1) Pressure test or internal inspection or other equivalent technology. An operator that 

uses pressure testing or internal inspection as an assessment method must establish the 

reassessment interval for a covered pipeline segment by — 

(i) Basing the interval on the identified threats for the covered segment (see §192.917) 

and on the analysis of the results from the last integrity assessment and from the data integration 

and risk assessment required by §192.917; or 

(ii) Using the intervals specified for different stress levels of pipeline (operating at or 

above 30% SMYS) listed in ASME/ANSI B31.8S, section 5, Table 3. 

(2) External Corrosion Direct Assessment. An operator that uses ECDA that meets the 

requirements of this subpart must determine the reassessment interval according to the 

requirements in paragraphs 6.2 and 6.3 of NACE RP0502-2002 (incorporated by reference, see 

§192.7). 

(3) Internal Corrosion or SCC Direct Assessment. An operator that uses ICDA or SCCDA in 

accordance with the requirements of this subpart must determine the reassessment interval 

according to the following method. However, the reassessment interval cannot exceed those 

specified for direct assessment in ASME/ANSI B31.8S, section 5, Table 3. 

(i) Determine the largest defect most likely to remain in the covered segment and the 

corrosion rate appropriate for the pipe, soil and protection conditions; 

(ii) Use the largest remaining defect as the size of the largest defect discovered in the 

SCC or ICDA segment; and 

(iii) Estimate the reassessment interval as half the time required for the largest defect 

to grow to a critical size. 

(b) Pipelines Operating Below 30% SMYS. An operator must establish a reassessment interval 

for each covered segment operating below 30% SMYS in accordance with the requirements of this 

section. The maximum reassessment interval by an allowable reassessment method is seven years. 

An operator must establish reassessment by at least one of the following — 

(1) Reassessment by pressure test, internal inspection or other equivalent technology 

following the requirements in paragraph (a)(1) of this section except that the stress level referenced 

in paragraph (a)(1)(ii) of this section would be adjusted to reflect the lower operating stress level. If 

an established interval is more than seven years, the operator must conduct by the seventh year of 

the interval either a confirmatory direct assessment in accordance with §192.931, or a low stress 

reassessment in accordance with §192.941. 

(2) Reassessment by ECDA following the requirements in paragraph (a)(2) of this section. 

(3) Reassessment by ICDA or SCCDA following the requirements in paragraph (a)(3) of this 

section. 

(4) Reassessment by confirmatory direct assessment at 7-year intervals in accordance with 

§192.931, with reassessment by one of the methods listed in paragraphs (b)(1 ) through (b)(3) of this 

section by year 20 of the interval. 

(5) Reassessment by the low stress assessment method at 7-year intervals in accordance 

with §192.941 with reassessment by one of the methods listed in paragraphs (b)(1) through (b)(3) of 

this section by year 20 of the interval. 

(6) The following table sets forth the maximum reassessment intervals. Also refer to 

Appendix E.II for guidance on Assessment Methods and Assessment Schedule for Transmission 

Pipelines Operating Below 30% SMYS. In case of conflict between the rule and the guidance in the 

Appendix, the requirements of the rule control. An operator must comply with the following 

requirements in establishing a reassessment interval for a covered segment: 

Addendum No. 8, April 2007 262(an)



Assessment 

Method 

Internal Inspection 

Tool, Pressure 

Test or Direct 

Assessment 

Confirmatory 

Direct Assessment 

Low Stress 

Reassessment 

Maximum Reassessment Interval 

Pipeline operating at or 

above 50% SMYS 

Pipeline operating at or 

above 30% SMYS, up 

to 50% SMYS 

10 years(*) 15 years(*) 20 years(**) 

7 years 7 years 7 years 

Pipeline operating 

below 30% SMYS 

Not Applicable Not Applicable 7 years + ongoing 

actions specified in 

§192.941 

(*) A Confirmatory direct assessment as described in §192.931 must be conducted by year 7 in 

a 10-year interval and years 7 and 14 of a 15-year interval. 

(**) A low stress reassessment or Confirmatory direct assessment must be conducted by years 

7 and 14 of the interval. 



Amdt. 192-103, 71 FR 33402, June 9, 2006; Editorial Note: Regulation adjusted per e-CFR as advised 

by PHMSA/OPS] 



§192.941 

What is a low stress reassessment? 


(a) General. An operator of a transmission line that operates below 30% SMYS may use the 

following method to reassess a covered segment in accordance with §192.939. This method of 

reassessment addresses the threats of external and internal corrosion. The operator must have 

conducted a baseline assessment of the covered segment in accordance with the requirements of 

§§192.919 and 192.921. 

(b) External corrosion. An operator must take one of the following actions to address external 

corrosion on the low stress covered segment. 

(1) Cathodically protected pipe. To address the threat of external corrosion on cathodically 

protected pipe in a covered segment, an operator must perform an electrical survey (i.e. indirect 

examination tool/method) at least every 7 years on the covered segment. An operator must use the 

results of each survey as part of an overall evaluation of the cathodic protection and corrosion 

threat for the covered segment. This evaluation must consider, at minimum, the leak repair and 

inspection records, corrosion monitoring records, exposed pipe inspection records, and the pipeline 

environment. 

(2) Unprotected pipe or cathodically protected pipe where electrical surveys are impractical. 

Addendum No. 8, April 2007 262(ao)



If an electrical survey is impractical on the covered segment an operator must — 

(i) Conduct leakage surveys as required by §192.706 at 4-month intervals; and 

(ii) Every 18 months, identify and remediate areas of active corrosion by evaluating 

leak repair and inspection records, corrosion monitoring records, exposed pipe inspection records, 

and the pipeline environment. 

(c) Internal Corrosion. To address the threat of internal corrosion on a covered segment, an 

operator must — 

(1) Conduct a gas analysis for corrosive agents at least once each calendar year; 

(2) Conduct periodic testing of fluids removed from the segment. At least once each 

calendar year test the fluids removed from each storage field that may affect a covered segment; 

and 

(3) At least every seven (7) years, integrate data from the analysis and testing required by 

paragraphs (c)(1)- (c)(2) with applicable internal corrosion leak records, incident reports, safety- 

related condition reports, repair records, patrol records, exposed pipe reports, and test records, and 

define and implement appropriate remediation actions. 


15, 2004 and Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004] 



§192.943 

When can an operator deviate from these reassessment intervals? 


(a) Waiver from reassessment interval in limited situations. In the following limited instances, 

OPS may allow a waiver from a reassessment interval required by §192.939 if OPS finds a waiver 

would not be inconsistent with pipeline safety. 

(1) Lack of internal inspection tools. An operator who uses internal inspection as an 

assessment method may be able to justify a longer reassessment period for a covered segment if 

internal inspection tools are not available to assess the line pipe. To justify this, the operator must 

demonstrate that it cannot obtain the internal inspection tools within the required reassessment 

period and that the actions the operator is taking in the interim ensure the integrity of the covered 

segment. 

(2) Maintain product supply. An operator may be able to justify a longer reassessment 

period for a covered segment if the operator demonstrates that it cannot maintain local product 

supply if it conducts the reassessment within the required interval. 

(b) How to apply. If one of the conditions specified in paragraph (a)(1) or (a)(2) of this section 

applies, an operator may seek a waiver of the required reassessment interval. An operator must 

apply for a waiver in accordance with 49 U.S.C. 60118(c), at least 180 days before the end of the 

required reassessment interval, unless local product supply issues make the period impractical. If 

local product supply issues make the period impractical, an operator must apply for the waiver as 

soon as the need for the waiver becomes known. 



Addendum No. 6, September 2006 262(ap)




1 GENERAL 

OPS allows waivers in limited instances. A waiver is not required in the following situations. 

(a) When reassessment intervals established are more frequent than those required by §192.939. 

(b) Where an Integrity Management Program meets the criteria for exceptional performance in 

§192.913. 

2 CONDITIONS FOR A WAIVER 

A waiver can be requested under the following conditions. 

(a) Unavailability of internal inspection tools. 

Operators may consider a general contract provision with their internal inspection tool service 

provider that requires written notification of tool availability. However, to support the request for 

waiver, an operator should consider obtaining documentation on the lack of availability from 

multiple vendors. This documentation might include the following. 

(1) Request for Proposal (RFP). 

(2) Letters from vendors. 

(3) Timeline of activities. 

(b) Inability to maintain supply. 

An operator should consider submitting documentation substantiating the basis and possible 

duration that local gas supply cannot be maintained. Documentation might include the following. 

(1) Operational flow control notifications from an upstream pipeline operator. 

(2) Supply nominations. 

(3) SCADA system data (i.e., flow rates and pressures). 

(4) Weather conditions. 

(5) Potential customer outages. 

(6) Upstream service interruptions. 

(7) Natural disasters. 

3 WAIVER APPLICATIONS 

(a) Applications for a waiver can be made as follows. 

(1) From an interstate pipeline operator to OPS in accordance with 49 USC 60118(c) - Waivers 

approved by Secretary. 

(2) From an intrastate pipeline operator to its state authority in accordance with 49 USC 60118(d) - 

Waivers approved by State Authorities. If the state does not have a current pipeline program 

certification, the operator applies to OPS in accordance with 49 USC 60118(c). 

(b) The application should include the following. 

(1) Information about the pipeline segment and HCA involved. 

(2) Supporting documentation. 

(3) The date when an assessment will take place. 

§192.945 

What methods must an operator use to measure program effectiveness? 


(a) General. An operator must include in its integrity management program methods to 

measure, on a semi-annual basis, whether the program is effective in assessing and evaluating the 

integrity of each covered pipeline segment and in protecting the high consequence areas. These 

measures must include the four overall performance measures specified in ASME/ANSI B31.8S 

Addendum No. 6, September 2006 262(aq)



(incorporated by reference, see §192.7), section 9.4, and the specific measures for each identified 

threat specified in ASME/ANSI B31.8S, Appendix A. An operator must submit the four overall 

performance measures, by electronic or other means, on a semi-annual frequency to OPS in 

accordance with § 192.951. An operator must submit its first report on overall performance 

measures by August 31, 2004. Thereafter, the performance measures must be complete through 

June 30 and December 31 of each year and must be submitted within 2 months after those dates. 

(b) External corrosion direct assessment. In addition to the general requirements for 

performance measures in paragraph (a) of this section, an operator using direct assessment to 

assess the external corrosion threat must define and monitor measures to determine the 

effectiveness of the ECDA process. These measures must meet the requirements of §192.925. 



Amdt. 192-103, 71 FR 33402, June 9, 2006] 

1 REPORTING MEASURES 


The required reporting measures are provided in the “Instructions for Semi-Annual Reporting of 

Performance Measures,” available at the OPS website 

http://opsweb.rspa.dot.gov/gasimp/docs/Gas%20IMP%20Reporting%20Instructions.pdf. 

2 ADDITIONAL PERFORMANCE MEASURES 

Operators are required to maintain the threat-specific performance measures identified in ASME 

B31.8S, Table 9. Operators are not required to report these measures to PHMSA, but must make the 

records available for inspection. 

3 EXTERNAL CORROSION DIRECT ASSESSMENT 

Operators using ECDA are required to define performance measures. Guidance can be found in 

Section 6.4 of NACE RP0502. 

§192.947 

What records must an operator keep? 


An operator must maintain, for the useful life of the pipeline, records that demonstrate 

compliance with the requirements of this subpart. At minimum, an operator must maintain the 

following records for review during an inspection. 

(a) A written integrity management program in accordance with §192.907; 

(b) Documents supporting the threat identification and risk assessment in accordance with 

§192.917; 

(c) A written baseline assessment plan in accordance with§192.919; 

(d) Documents to support any decision, analysis and process developed and used to 

implement and evaluate each element of the baseline assessment plan and integrity management 

program. Documents include those developed and used in support of any identification, calculation, 

amendment, modification, justification, deviation and determination made, and any action taken to 

implement and evaluate any of the program elements; 

Addendum No. 8, April 2007 262(ar)



(e) Documents that demonstrate personnel have the required training, including a description 

of the training program, in accordance with §192.915; 

(f) Schedule required by §192.933 that prioritizes the conditions found during an assessment 

for evaluation and remediation, including technical justifications for the schedule. 

(g) Documents to carry out the requirements in §§192.923 through 192.929 for a direct 

assessment plan; 

(h) Documents to carry out the requirements in §192.931 for confirmatory direct assessment; 

(i) Verification that an operator has provided any documentation or notification required by this 

subpart to be provided to OPS, and when applicable, a State authority with which OPS has an 

interstate agent agreement, and a State or local pipeline safety authority that regulates a covered 

pipeline segment within that State. 



1 PROGRAM AND PROCESS RECORDS 


1.1 General. 

Operators should maintain, for the useful life of the pipeline, documents to support decisions, analyses, 

and processes related to development, implementation, and evaluation of the integrity management 

program. 

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 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. 

Addendum No. 8, April 2007 262(as)



(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 OPS and state pipeline safety authorities 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 to the Pipeline and Hazardous Materials Safety Administration, U.S. 

Department of Transportation, Room 2103, 400 Seventh Street, SW., Washington, DC 20590; 

(b) Sending the notification by fax to (202) 366-4566; or 

(c) Entering the information directly on the Integrity Management Database (IMDB) Web site at 

http://primis.phmsa.dot.gov/gasimp/. 


15, 2004; RIN 2137-AD77, 70 FR 11135, Mar. 8, 2005; Amdt. 192-103, 72 FR 4655, Feb. 1, 2007] 

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 

Addendum No. 8, April 2007 262(at)



the following information. 


(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. 


(2) Description of system. 

(3) Justification for using ICDA. 

(4) How public safety will be maintained. 

(d) Section 192.933, when the operator cannot meet the schedule and cannot provide safety 

through temporary pressure reduction. Notifications include the following information. 


(2) Reason why the schedule cannot be met or temporary pressure reduction cannot be 

implemented. 

(3) How public safety will be maintained. 

2 NOTIFICATION METHODS 

2.1 Notification to OPS. 

An operator should use only one notification option to OPS; that is, by mail, telefacsimile, or online 

submission. The website for online submission is http://primis.phmsa.dot.gov/gasimp. 

2.2 Notification to state authorities. 

Where OPS has an interstate agent agreement, or an intrastate covered segment is regulated by 

that state, an operator must also notify the state pipeline safety authority. A reference for state 

contacts is available at http://www.napsr.org. 

3 REFERENCE 

OPS Advisory Bulletin ADB-05-04 (70 FR 43939, July 29, 2005), accessible via the Federal Register 

(FR) at www.gpoaccess.gov/fr/advanced.html. 

§192.951 

Where does an operator file a report? 

� [Effective Date 3-05-07] 

An operator must send any performance report required by this subpart to the Information 

Resources Manager — 

(a) By mail to the Pipeline and Hazardous Materials Safety Administration, U.S. Department of 

Transportation, Room 2103, 400 Seventh Street S.W., Washington, DC 20590; 

(b) Via fax to (202) 366-4566; or 

(c) Through the online reporting system provided by PHMSA for electronic reporting available 

at the PHMSA Home Page at http://phmsa.dot.gov. 


15, 2004; RIN 2137-AD77, 70 FR 11135, Mar. 8, 2005; Amdt. 192-103, 72 FR 4655, Feb. 1, 2007] 

Addendum No. 8, April 2007 262(au)



1 REQUIRED REPORTS 


See the following sections for information regarding specific reporting requirements. 

(a) Section 192.945, regarding performance measures. 

(b) Section 192.913, regarding additional performance measures for exceptional performance 

programs. 

(c) Sections 192.913 and 192.945 do not require reporting to state pipeline safety authorities. 

However, intrastate operators should consider submitting a copy of the reports to their state 

authorities. 

2 REPORTING METHOD 

An operator should use only one reporting option to OPS; that is, by mail, via facsimile, or by going 

online electronically. Use the website listed in §192.949 to obtain the current mailing address or 

facsimile telephone number for notifications. 

Addendum No. 8, April 2007 262(av)

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 each violation Form Approved 

for each day the violation continues up to a maximum of $1,000,000 as provided in 49 USC 60122. OMB No. 2137-0522 

U.S. Department of Transportation 

Pipeline and Hazardous Materials 

Safety Administration 

ANNUAL REPORT FOR CALENDAR YEAR 20___ 

GAS DISTRIBUTION SYSTEM 

PART A - OPERATOR INFORMATION DOT USE ONLY 

INITIAL REPORT � 

SUPPLEMENTAL REPORT � 

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 

1. GENERAL 

Report miles of main and number of services in system at end of year. 

STEEL 

UNPROTECTED CATHODICALLY 

PROTECTED PLASTIC 

CAST/ 

WROUGHT 

IRON 

DUCTIL 

E 

IRON 

COPPER 

BARE COATED BARE COATED 

MILES OF MAIN 

NO. OF 

SERVICES 

2. MILES OF MAINS IN SYSTEM AT END OF YEAR 

MATERIAL 

STEEL 

UNKNOWN 2" OR LESS OVER 2" 

THRU 4" 

DUCTILE IRON 

COPPER 

CAST/WROUGHT 

IRON 

PLASTIC 

1. PVC 

2. PE 

3. ABS 

OTHER 

OTHER 

SYSTEM TOTALS 

OVER 4" 

THRU 8" 

OVER 8" 

THRU 12” 

OTHER OTHER TOTAL 

OVER 12" TOTAL 

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

MATERIAL 

STEEL 

UNKNOWN 1" OR LESS OVER 1" 

THRU 2" 

DUCTILE IRON 

COPPER 

CAST/WROUGHT 

IRON 

PLASTIC 

1. PVC 

2. PE 

3. ABS 

OTHER 

OTHER 

SYSTEM TOTALS 

Form PHMSA F 7100.1-1 (12-05) 

OVER 2" 

THRU 4" 

OVER 4" 

THRU 8” 

Reproduction of this form is permitted. 

OVER 8" TOTAL

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 

MILES OF MAIN 

NUMBER OF SERVICES 

PART C - TOTAL LEAKS ELIMINATED/REPAIRED DURING YEAR PART D - TOTAL NUMBER OF LEAKS ON FEDERAL LAND 

REPAIRED OR SCHEDULED FOR REPAIR 

CAUSE OF LEAK 

Mains Services 

CORROSION 

NATURAL FORCES 

EXCAVATION 

OTHER OUTSIDE FORCE 

DAMAGE 

PART E - PERCENT OF UNACCOUNTED FOR GAS 

MATERIAL OR WELDS 

EQUIPMENT 

Unaccounted for gas as a percent of total input for the12 months 

ending June 30 of the reporting year. 

[(Purchased gas + produced gas) 

OPERATIONS 

OTHER 

minus (customer use + company use + appropriate adjustments)] 

divided by (purchased gas + produced gas) equals percent unaccounted 

for. 

NUMBER OF KNOWN SYSTEM LEAKS AT 

END OF YEAR SCHEDULED FOR REPAIR 

PART F - ADDITIONAL INFORMATION 

PART G - PREPARER AND AUTHORIZED SIGNATURE 

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 

TOTAL

GPTC GUIDE FOR GAS TRANSMISSION AND Guide Material Appendix G-192-1 


GUIDE MATERIAL APPENDIX G-192-1 

SUMMARY OF REFERENCES AND RELATED SOURCES 

(Reorganized and updated for 2003 Edition, Addendum No. 2) 

CONTENTS 

1 MATERIAL SPECIFICATIONS, CODES, STANDARDS, AND OTHER DOCUMENTS 

1.1 Pipe – Metallic 

1.2 Pipe – Plastic [See "Plastic Related"] 

1.3 Valves [See other related references under "Fittings – Flanged" and "Fittings – Miscellaneous"] 

1.4 Fittings – Flanged 

1.5 Fittings – Threaded 

1.6 Fittings – Welded 

1.7 Fittings – Miscellaneous 

1.8 Bolts & Gaskets 

1.9 Corrosion Related 

1.10 Dimensional Standards 

1.11 Plastic Related 

1.12 Pressure & Flow Devices 

1.13 Structure Steel & Supports 

1.14 Other Documents 

2 GOVERNMENTAL DOCUMENTS 

3 TECHNICAL PAPERS & PUBLICATIONS 

3.1 Emergency Related 

3.2 Corrosion Related 

3.3 Plastic Related 

3.4 Uncased Pipe and Directional Drilling Related 

3.5 Safety and Integrity Management Related 

4 PUBLISHING ORGANIZATIONS 

5 ADDITIONAL INFORMATION RESOURCES 

6 SUMMARY OF WEBSITES 




Reserved 

314



GUIDE MATERIAL APPENDIX G-192-1 

SUMMARY OF REFERENCES AND RELATED SOURCES 

(Reorganized and updated for 2003 Edition, Addendum No. 2) 

1 MATERIAL SPECIFICATIONS, CODES, STANDARDS, AND OTHER DOCUMENTS 

The publications listed below provide information on pipe, components, specifications, and topics other 

than those covered currently or previously by Part 192. The list is intended to include all such 

publications referenced throughout the guide material. For some publication titles, certain initial words 

have been omitted for brevity, e.g., ASTM B43, "Standard Specification for Seamless Red Brass Pipe, 

Standard Sizes" is presented here as "Seamless Red Brass Pipe, Standard Sizes." Under some 

conditions, the application of the information is limited by provisions of Part 192 and this Guide. See 

Editorial Conventions of the Guide for explanation of "Discontinued." Most material specifications, 

codes, standards, and many other documents have been developed and approved in accordance with 

American National Standards Institute (ANSI) procedures and typically carry added identification 

referencing ANSI. Such identification is not routinely shown in the Guide. The appropriate guide 

material section is listed for each publication where applicable. Unless otherwise noted, the publications 

listed below are the latest available editions. 

1.1 PIPE - METALLIC 

ANSI A21.52 Ductile – Iron Pipe, Centrifugally Cast for Gas 

(Revised1991; Discontinued) 

§192.557 

API RP 5LW Transportation of Line Pipe on Barges and Marine Vessels §192.65 

§192.103 

ASME I00396 History of Line Pipe Manufacturing in North America §192.3 

ASTM A120 Pipe, Steel, Black and Hot-Dipped, Zinc-Coated 

(Galvanized) Welded and Seamless for Ordinary Uses 

(Withdrawn 1987) 

ASTM A155 Electric-Fusion Welded Steel Pipe for High-Pressure 

Service (Withdrawn 1978; Replaced by ASTM A671) 

ASTM B43 Seamless Red Brass Pipe, Standard Sizes 

AWWA C101 Thickness Design of Cast Iron Pipe (Discontinued) §192.557 

AWWA C150 Thickness Design of Ductile-Iron Pipe §192.557 

1.2 PIPE – PLASTIC 

[See 1.11 Plastic Related] 




1.3 VALVES 

[See other related references under 1.4 Fittings-Flanged and 1.7 Fittings-Miscellaneous] 

API Std 600 Bolted Bonnet Steel Gate Valves for Petroleum and Natural 

Gas Industries 

ASME B16.33 Manually Operated Metallic Gas Valves for Use in Gas 

Piping Systems Up to 125 psig (Sizes NPS ½ - NPS 2) 

§192.145 

§192.145 

ASME B16.34 Valves - Flanged, Threaded, and Welding End §192.145 

ASME B16.38 Large Metallic Valves for Gas Distribution (Manually 

Operated, NPS 2½ to 12, 125 psig Max) 

1.4 FITTINGS – FLANGED 

§192.145 

ASME B16.47 Large Diameter Steel Flanges (NPS 26 through NPS 60) §192.147 

AWWA C207 Steel Pipe Flanges for Waterwork Service, Sizes 4 Inch 

Through 144 Inch 

MSS SP-6 Finishes for Contact Faces of Pipe Flanges and 

Connecting-End Flanges of Valves and Fittings 

1.5 FITTINGS - THREADED 

§192.147 

ASME B16.3 Malleable Gray Iron Threaded Fittings §192.149 

ASME B16.4 Gray Iron Threaded Fittings §192.149 

ASME B16.14 Ferrous Pipe Plugs, Bushings and Locknuts with Pipe 

Threads 

ASME B16.15 Cast Bronze Threaded Fittings, Classes 125 and 250 §192.149 

1.6 FITTINGS - WELDED 

ASME B16.9 Factory-Made Wrought Steel Buttwelding Fittings §192.149 

App. G-192-3 

ASME B16.25 Buttwelding Ends 

ASME B16.28 Wrought Steel Buttwelding Short Radius Elbows and 

Returns 

ASTM A234 Piping Fittings of Wrought Carbon Steel and Alloy Steel for 

Moderate and High Temperature Service 

ASTM A420 Piping Fittings of Wrought Carbon Steel and Alloy Steel for 

Low-Temperature Service 

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

§192.157 




1.7 FITTINGS - MISCELLANEOUS 

ANSI A21.14 Ductile Iron Fittings, 3-Inch Through 24-Inch for Gas §192.557 

ASME B16.11 Forged Fittings, Socket-Welding and Threaded §192.149 

App.G-192-5 

ASME B16.18 Cast Copper Alloy Solder Joint Pressure Fittings 

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

Fittings 

ASME B16.36 Orifice Flanges 

ASME B16.48 Steel Line Blanks 

ASME B16.49 Factory-Made Wrought Steel Buttwelding Induction Bends 

for Transportation and Distribution Systems 

ASTM A105 Carbon Steel Forgings for Piping Applications 

ASTM A181 Carbon Steel Forgings for General-Purpose Piping 

ASTM A182 Forged or Rolled Alloy-Steel Pipe Flanges, Forged Fittings, 

and Valves and Parts for High-Temperature Service 

ASTM A350 Carbon and Low-Alloy Steel Forgings, Requiring Notch 

Toughness Testing for Piping Components 

ASTM A733 Welded and Seamless Carbon Steel and Austenitic 

Stainless Steel Pipe Nipples 

§192.149 

MSS SP-79 Socket-Welding Reducer Inserts §192.149 

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

Threaded 

1.8 BOLTS & GASKETS 

§192.149 

AGA CPR-83-4-1 Threaded Fastener Torquing §192.147 

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

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

Wound and Jacketed 

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

§192.147 

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

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

ASTM A193 Alloy Steel and Stainless Steel Bolting Materials for High- 

Temperature Service 

ASTM A194 Carbon and Alloy Steel Nuts for Bolts for High-Pressure or 

High-Temperature Service, or Both 

Addendum No. 6, September 2006 317 

§192.147 

§192.147



1.8 BOLTS & GASKETS (Continued) 

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

ASTM A320 Alloy Steel Bolting Materials for Low-Temperature Service §192.147 

ASTM A354 Quenched and Tempered Alloy Steel Bolts, Studs, and 

Other Externally Threaded Fasteners 

§192.147 

ASTM A449 Quenched and Tempered Steel Bolts and Studs §192.147 

1.9 CORROSION RELATED 

NACE MR0175 Materials for Use in H2S-Containing Environments in Oil 

and Gas Production 

§192.53 

§192.475 

NACE RP0102 In-Line Inspection of Pipelines §192.150 

NACE RP0169 Control of External Corrosion on Underground or 

Submerged Metallic Piping Systems 

NACE RP0173 Collection and Identification of Corrosion Products (Revised 

1973; Discontinued) 

NACE RP0175 Control of Internal Corrosion in Steel Pipelines and Piping 

Systems (Revised 1975; Discontinued) 

NACE RP0177 Mitigation of Alternating Current and Lightning Effects on 

Metallic Structures and Corrosion Control Systems 

NACE RP0192 Monitoring Corrosion in Oil and Gas Production with Iron 

Counts 

§192.453 

§192.455 

§192.461 

§192.463 

§192.473 

App. D 

§192.617 

§192.475 

§192.467 

§192.475 

NACE RP0200 Steel-Cased Pipeline Practices §192.323 

§192.467 

NACE RP0274 High-Voltage Electrical Inspection of Pipeline Coatings §192.461 

NACE RP0375 Wax Coating Systems for Underground Piping Systems §192.461 

NACE RP0775 Preparation, Installation, Analysis, and Interpretation of 

Corrosion Coupons in Oilfield Operations 

§192.475 

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

NACE 3D170 Technical Committee Report, Electrical and 

Electrochemical Methods for Determining Corrosion Rates 

(Revised 1984; Withdrawn 1994) 

NACE 35100 Technical Committee Report, In-Line Nondestructive 

Inspection of Pipelines 

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

Specifications - Volume 2 


§192.475 

§192.150 

§192.479



1.10 DIMENSIONAL STANDARDS 

API Spec 5B Threading, Gauging, and Thread Inspection of Casing, 

Tubing, and Line Pipe Threads 

ASME B1.20.1 Pipe Threads, General Purpose, Inch 

ASME B1.20.3 Dryseal Pipe Threads, Inch 

1.11 PLASTIC RELATED 

AGA XR0104 Plastic Pipe Manual For Gas Service §192.285 

§192.321 

§192.751 

ASME I00353 Installation of Plastic Gas Pipeline in Steel Conduits Across 

Bridges 

ASTM D696 Test Method for Coefficient of Linear Thermal Expansion of 

Plastics 

ASTM D2235 Solvent Cement for Acrylonitrile-Butadiene-Styrene (ABS) 

Plastic Pipe and Fittings 

ASTM D2560 Solvent Cements for Cellulose Acetate Butyrate (CAB) 

Plastic Pipe, Tubing and Fittings (Withdrawn 1986) 

App. G-192-21 

§192.281 

§192.281 

§192.281 

ASTM D2657 Heat Fusion Joining of Polyolefin Pipe and Fittings §192.281 

ASTM D2837 Standard Test Method for Obtaining Hydrostatic Design 

Basis for Thermoplastic Pipe Materials or Pressure Design 

Basis for Thermoplastic Pipe Products 

ASTM D2855 Making Solvent-Cemented Joints with Poly (Vinyl Chloride) 

(PVC) Pipe and Fittings 

ASTM F689 Determination of the Temperature of Above-Ground Plastic 

Gas Pressure Pipe Within Metallic Casings 

ASTM F1041 Guide for Squeeze-Off of Polyolefin Gas Pressure Pipe and 

Tubing 

§192.3 

§192.63 

§192.121 

§192.281 

§192.321 

ASTM F1290 Electrofusion Joining of Polyolefin Pipe and Fittings §192.281 

ASTM F1563 Tools to Squeeze-Off Polyethylene (PE) Gas Pipe or 

Tubing 

§192.321 

GRI-92/0147.1 Users’ Guide on Squeeze-Off of Polyethylene Gas Pipes §192.321 

GRI-94/0205 Guidelines and Technical Reference on Gas Flow Shut-Off 

in Polyethylene Pipes Using Squeeze Tools 

GRI-96/0194 Service Effects of Hydrocarbons on Fusion and Mechanical 

Performance of Polyethylene Gas Distribution Piping 


§192.321 

§192.123



1.11 PLASTIC RELATED (Continued) 

PPI - Handbook of PE 

Pipe 

Above Ground Applications for Polyethylene Pipe 

Note: Available as individual chapter of the PPI Handbook 

of Polyethylene Pipe 

PPI TN-13 General Guidelines for Butt, Saddle and Socket Fusion of 

Unlike Polyethylene Pipes and Fittings 

PPI TR-4 PPI Listing of Hydrostatic Design Basis (HDB), Strength 

Design Basis (SDB), Pressure Design Basis (PDB) and 

Minimum Required Strength (MRS) Ratings for 

Thermoplastic Piping Materials or Pipe 

PPI TR-9 Recommended Design Factors and Design Coefficients for 

Thermoplastic Pressure Pipe 

PPI TR-22 Polyethylene Piping Distribution Systems for Components 

of Liquid Petroleum Gases 

PPI TR-33 Generic Butt Fusion Joining Procedure for Polyethylene 

Gas Pipe 

PPI TR-41 Generic Saddle Fusion Joining Procedure for Polyethylene 

Gas Piping 

PPI Tech. Comm. 

Project 141 

1.12 PRESSURE & FLOW DEVICES 

Standard Practice for Electrofusion Joining Polyolefin Pipe 

and Fittings 

API RP 520 P2 Sizing, Selection and Installation of Pressure-Relieving 

Devices in Refineries, Part 2 Installation 

API RP 525 Testing Procedure for Pressure-Relieving Devices 

Discharging Against Variable Back Pressure (Revised 

1960; Discontinued) 

ASTM F1802 Test Method for Performance Testing of Excess Flow 

Valves 

§192.321 

App. G-192-21 

§192.281 

§192.283 

§192.121 

§192.123 

§192.121 

§192.123 

§192.281 

§192.283 

§192.281 

§192.283 

§192.281 

§192.201 

§192.743 

§192.381 

MSS SP-115 Excess Flow Valves for Natural Gas Service §192.381 

NBBI Relieving Capacities of Safety Valves and Relief Valves 

Approved by the National Board (Discontinued) 

1.13 STRUCTURAL STEEL & SUPPORTS 

ASTM A36 Carbon Structural Steel 

MSS SP-58 Pipe Hangers and Supports - Materials, Design and 

Manufacture 

§192.201 

§192.357 

MSS SP-69 Pipe Hangers and Supports - Selection and Application §192.357 




1.14 OTHER DOCUMENTS 

AGA X69804 Historical Collection of Natural Gas Pipeline Safety 

Regulations 

Forward 

Editorial Notes 

AGA XF0277 Classification of Gas Utility Areas for Electrical Installations §192.163 

AGA XK0101 Purging Principles and Practice §192.629 

§192.727 

AGA XL8920 Attention Prioritizing and Pipe Replacement/Renewal 

Decisions 

§192.457 

§192.703 

App. G-192-18 

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 

App. G-192-15 

API RP 1117 Movement of In-Service Pipelines §192.103 

§192.703 

APWA Excavator's Damage Prevention Guide and One-Call 

Systems International Directory (includes Uniform Color 

Code) 

AREMA Manual for Railway Engineering, Chapter 1 – Roadway and 

Ballast (for Part 5 – Pipelines) 

ASCE 428-5 Guidelines for the Seismic Design of Oil and Gas Pipeline 

Systems (Discontinued) 

§192.614 

App. G-192-15 

§192.103 

ASME B31.1 Power Piping §192.141 

ASME B31.2 Fuel Gas Piping 

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 B31.9 Building Services Piping 

ASME Guide SI-1 ASME Orientation and Guide for Use of SI (Metric) Units App. G-192-M 

ASNT ILI-PQ In-line Inspection Personnel Qualification and Certification §192.915 

ASTM D6273 Standard Test Methods for Natural Gas Odor Intensity §192.625 

ASTM E84 Test Method for Surface Burning Characteristics of Building 

Materials 

Addendum No. 6, September 2006 321 

§192.163



1.14 OTHER DOCUMENTS (Continued) 

AWS A3.0 Standard Welding Terms and Definitions §192.3 

§192.221 

CoGDEM Gas Detection and Calibration Guide App. G-192-11 

App. G-192-11A 

GPTC-Z380-TR-1 Review of Integrity Management for Natural Gas 

Transmission Pipelines 

§192.907 

GRI-91/0283 Guidelines for Pipelines Crossing Railroads §192.103 

App. G-192-15 

GRI-91/0284 Guidelines for Pipelines Crossing Highways §192.103 

App. G-192-15 

GRI-91/0285 Technical Summary and Database for Guidelines for 

Pipelines Crossing Railroads and Highways 

GRI-91/0285.1 Executive Summary: Technical Summary and Database for 

Guidelines for Pipelines Crossing Railroads and Highways 

App. G-192-15 

App. G-192-15 

IAPMO Uniform Plumbing Code §192.141 

NCB Subsidence Engineers Handbook, National Coal Board 

Mining Department (U.K.), 1975 

NFPA 10 Portable Fire Extinguishers 

App. G-192-13 

NFPA 14 Installation of Standpipe and Hose Systems §192.141 

NFPA 24 Installation of Private Fire Service Mains and Their 

Appurtenances 

§192.141 

NFPA 54/ANSI Z223.1 National Fuel Gas Code Figure 192.11A 

Figure 192.11B 

NFPA 220 Types of Building Construction 

NFPA 224 Homes and Camps in Forest Areas (Discontinued) §192.163 

NFPA 921 Guide for Fire and Explosion Investigations §192.617 

PRCI L22279 Further Studies of Two Methods for Repairing Defects in 

Line Pipe 

§192.713 

PRCI L51406 Pipeline Response to Buried Explosive Detonations App. G-192-16 

PRCI L51574 Non-Conventional Means for Monitoring Pipelines in Areas 

of Soil Subsidence or Soil Movement 

App. G-192-13 

PRCI L51717 Pipeline In-Service Relocation Engineering Manual §192.703 




1.14 OTHER DOCUMENTS (Continued) 

PRCI L51740 Evaluation of the Structural Integrity of Cold Field-Bent Pipe §192.313 

PRCI PC-PISCES Personal Computer - Pipeline Soil Crossing Evaluation 

System (PC-PISCES), Version 2.0 (Related to API RP 

1102) 

UL 723 Test for Surface Burning Characteristics of Building 

Materials 

2 GOVERNMENTAL DOCUMENTS 

NTSB Report 

PAB-98-02 

NTSB Report 

SIR-98-01 

Pipeline Accident Brief -- Fire and Explosion, Midwest Gas 

Company, Waterloo, Iowa, October 17, 1994 

Special Investigation Report -- Brittle-Like Cracking in 

Plastic Pipe for Gas Service 

OPS Common Ground -- Study of One-Call Systems and 

Damage Prevention Best Practices, August 1999 

OPS ADB-99-01 Advisory Bulletin -- Susceptibility of Certain Polyethylene 

Pipe Manufactured by Century Utility Products, Inc. to 

Premature Failure Due to Brittle-Like Cracking (64 FR 

12211, Mar. 11, 1999) 

OPS ADB-99-02 Advisory Bulletin -- Potential Susceptibility of Plastic Pipe 

Installed Between the [Years] 1960 and the Early 1980s to 

Premature Failure Due to Brittle-Like Cracking (64 FR 

12212, Mar. 11, 1999) 

OPS ADB-02-06 Advisory Bulletin – Standards for Classifying Natural Gas 

Gathering Lines (67 FR 64447, Oct. 18, 2002) 

OPS ADB-02-07 Advisory Bulletin -- Notification of the Susceptibility to 

Premature Brittle-Like Cracking of Older Plastic Pipe (67 

FR 70806, Nov. 26, 2002 with Correction, 67 FR 72027, 

Dec. 3, 2002) 

OPS ADB-03-03 

Advisory Bulletin – Identified Sites for Possible Inclusion as 

High Consequence Areas (HCAs) in Gas Integrity 

Management Programs (68 FR 42458, July 17, 2003) 

OPS ADB-04-01 Advisory Bulletin -- Hazards Associated with De-Watering 

of Pipelines (69 FR 58225, Sept. 29, 2004) 

OPS ADB-05-04 Advisory Bulletin -- Notification Required by the Integrity 

Management Regulations in 49 CFR Part 192, Subpart O 

(70 FR 43939, July 29, 2005) 

OPS-DOT.RSPA/DMT 

10-85-1 

Addendum No. 7, December 2006 323 

Safety Criteria for the Operation of Gaseous Hydrogen 

Pipelines (Discontinued) 

App. G-192-15 

§192.163 

§192.613 

§192.613 

§192.614 

§192.613 

§192.613 

§192.9 

§192.613 

§192.905 

§192.515 

§192.949 

§192.1



3 TECHNICAL PAPERS & REPORTS 

3.1 EMERGENCY RELATED 

"First at the Scene" by J.M. Lennon, Director of Claims, Philadelphia Electric Company; 

AGA Operating Section Proceedings - 1983. 

"How to Protect the Company at the Scene of an Incident" by Robert E. Kennedy, Director 

of Claims, Claim & Security Department, The Brooklyn Union Gas Company; AGA 

Operating Section Proceedings - 1983. 

3.2 CORROSION RELATED 

“Evaluation of Chemical Treatments in Natural Gas System vs. MIC and Other Forms of 

Internal Corrosion Using Carbon Steel Coupons,” Timothy Zintel, Derek Kostuck, and 

Bruce Cookingham, Paper # 03574 presented at CORROSION/03 San Diego, CA. 

“Field Guide for Investigating Internal Corrosion of Pipelines,” Richard Eckert, NACE 

Press, 2003 

“Field Use Proves Program for Managing Internal Corrosion in Wet-Gas Systems,” 

Richard Eckert and Bruce Cookingham, Oil & Gas Journal, January 21, 2002 

“Internal Corrosion Direct Assessment,” Oliver Moghissi, Bruce Cookingham, Lee Norris, 

and Phil Dusek, Paper # 02087 presented at CORROSION/02 Denver, CO 

“Internal Corrosion Direct Assessment of Gas Transmission Pipeline – Application,” Oliver 

Moghissi, Laurie Perry, Bruce Cookingham, and Narasi Sridhar, Paper # 03204 presented 

at CORROSION/03 San Diego, CA 

“Internal Corrosion Direct Assessment of Gas Transmission Pipeline - Methodology,” 

Oliver Moghissi, Bruce Cookingham, Lee Norris, Narasi Sridhar, and Phil Dusek, Gas 

Research Institute Report GRI-02/0057 

“Microscopic Differentiation of Internal Corrosion Initiation Mechanisms in a Natural Gas 

System,” Richard Eckert, Henry Aldrich, and Chris Edwards, Bruce Cookingham, Paper # 

03544 presented at CORROSION/03 San Diego, CA. 

3.3 PLASTIC RELATED 

“An Evaluation of Polyamide 11 for Use in High Pressure/High Temperature Gas Piping 

Systems,” T.J. Pitzi et al., 15th Plastic Fuel Gas Pipe Symposium Proceedings - 1997, p. 

107. 

"Correlating Aldyl 'A' and Century PE Pipe Rate Process Method Projections With Actual 

Field Performance," E.F. Palermo, Ph.D., Plastics Pipes XII Conference, April 2004. 

“Mechanical Integrity of Fusion Joints Made from Polyethylene Pipe Exposed to Heavy 

Hydrocarbons,” S.M. Pimputkar, 14th Plastic Fuel Gas Pipe Symposium Proceedings - 

1995, p. 141. 

“Polyamide 11 Liners Withstand Hydrocarbons, High Temperature,” A. Berry, Pipeline & 

Gas Journal, December 1998, p. 81. 

“Prediction of Organic Chemical Permeation through PVC Pipe,” A.R. Berens, Research 

Technology, November 1985, p. 57. 

“Strength of Fusion Joints Made from Polyethylene Pipe Exposed to Heavy 

Hydrocarbons,” S.M. Pimputkar, 15th Plastic Fuel Gas Pipe Symposium Proceedings - 

1997, p. 309. 


§192.617 

§192.617 

§192.475 

§192.475 

§192.475 

§192.475 

§192.475 

§192.475 

§192.475 

§192.123 

§192.613 

§192.123 

§192.123 

§192.123 

§192.123



3.4 UNCASED PIPE AND DIRECTIONAL DRILLING RELATED 

"Drilling Fluids in Pipeline Installation by Horizontal Directional Drilling - A Practical 

Applications Manual," J.D. Hair & Associates, Inc., Cebo Holland B.V., 1994. 

"Guidelines For A Successful Directional Crossing Bid Package," 1996 Directory of the 

North American Trenchless Technology Contractors. 

"Installation of Pipelines by Horizontal Directional Drilling, An Engineering Design Guide, " 

Prepared for the Offshore and Onshore Design Applications Supervisory Committee, of 

the PRCI, at the American Gas Association, J.D. Hair and Associates, Louis J. 

Cappozzolli and Associates, Inc., Stress Engineering Services, Inc., January 15, 1995. 

"Measurement Techniques in Horizontal Directional Drilling," Ir. J. Gorter, N.V. 

Nederlandse Gasunie, The Netherlands, February 1993. 

"Piping Handbook," Fourth Edition, J.H. Walker and Sabin Crocker, 1930, McGraw-Hill 

Inc., New York, NY; data re-affirmed in Sixth Edition, published 1992. 

3.5 SAFETY AND INTEGRITY MANAGEMENT RELATED 

"Pipeline Risk Management Manual," W. Kent Muhlbauer, Elsevier/Gulf Professional 

Publishing, ISBN: 0-7506-7579-9 

4 PUBLISHING ORGANIZATIONS 

App. G-192-15A 

App. G-192-15A 

App. G-192-15A 

App. G-192-15A 

App. G-192-15 

§192.907 

The specifications, codes, standards, and other documents listed in Sections 1 and 2 are published by 

the following organizations: 

AGA American Gas Association 

400 North Capitol Street, NW Publications: 

Washington, DC 20001 See Techstreet 

Phone: 202/824-7000 

FAX: 202/824-7115 

On line: www.aga.org 

ANSI American National Standards Institute 

25 West 43 rd Street 

New York, NY 10036 

Phone: 212/642-4900 

FAX: 212/302-1286 

On line: www.ansi.org 

Search: www.nssn.org 

API American Petroleum Institute 

1220 L Street, NW Publications: 

Washington, D.C. 20005-4070 See Global Engineering Documents 

Phone: 202/682-8417 

FAX: 202/682-8154 

On line: www.api.org 




APWA American Public Works Association Note: Free download available at 

2345 Grand Boulevard, Suite 500 www.apwa.net/About/PET/RightOfWay/One-Call 

Kansas City, MO 64108-2641 for: 

Phone: 816/472-6100 • One-Call Directory 

FAX: 816/472-1610 • Marking Guidelines 

On line: www.apwa.net • Color Code & Marking Guidelines 

AREMA American Railway Engineering and Maintenance of Way Association 

8201 Corporate Drive, Suite 1125 

Landover, MD 20785 

Phone: 301-459-3200 

FAX: 301-459-8077 

On line: www.arema.org 

ASCE The American Society of Civil Engineers 

1801 Alexander Bell Drive 

Reston, VA 20191-4400 

Phone: 800/548-2723 

FAX: 703/295-6222 

On line: www.asce.org 

ASME The American Society of Mechanical Engineers International 

& Information Central Center for Research and Technology 

ASME/ Orders and Inquiries Development: 

CRTD P.O. Box 2900 1828 L Street, NW, Suite 906 

Fairfield, NJ 07007-2900 Washington, DC 20036-5104 

Phone: 800/843-2763 Phone: 202/785-3756 

FAX: 973/882-1717 FAX: 202/785-8120 

On line: www.asme.org On line: www.asme.org/research 

ASNT American Society for Nondestructive Testing 

P.O. Box 28518 

1711 Arlingate Lane 

Columbus, OH 43228-0518 

Phone: 800-222-2768 

Fax: 614-274-6899 

On line: www.asnt.org 

ASTM ASTM International (Formerly American Society for Testing and Materials) 

100 Barr Harbor Drive 

West Conshohocken, PA 19428-2959 

Phone: 610/832-9585 

FAX: 610/832-9555 

On line: www.astm.org 

AWS American Welding Society 

550 NW LeJune Road 

Miami, FL 33126 

Phone: 305/443-9353 

FAX: 305/443-5951 

On line: www.aws.org 




AWWA American Water Works Association 

6666 W. Quincy Avenue 

Denver, CO 80235 

Phone: 303/794-7711 

FAX: 303/347-0804 

On line: www.awwa.org 

CoGDEM The Council of Gas Detection and Environmental Monitoring 

Unit 11, Theobald Business Park 

Knowl Piece, Wilbury Way 

Hitchin, Herts, SG4 0TY, UK 

Phone: +44(0) 1462 434322 

FAX: +44(0) 1462 434488 

On line: www.cogdem.org.uk 

DIPRA Ductile Iron Pipe Research Association 

245 Riverchase Parkway East, Suite O 

Birmingham, AL 35244 

Phone: 205/402-8700 

FAX: 205/402-8730 

On line: www.dipra.org 

GTI Gas Technology Institute 

(Formerly 1700 S. Mount Prospect Road 

GRI) Des Plaines, IL 60018-1804 

Phone: 847/768-0500 

Orders: 630/406-5994 

FAX: 630/403-5995 

On line: www.gastechnology.org 

IAPMO International Association of Plumbing and Mechanical Officials 

5001 E. Philadelphia Street 

Ontario, CA 91761 

Phone: 909/472-4100 

Orders: 800/854-2766 

FAX: 909/472-4150 

On line: www.iapmo.org/iapmo 

MSS Manufacturers Standardization Society of the Valve and Fittings Industry 

127 Park Street, N.E. 

Vienna, VA 22180 

Phone: 703/281-6613 

FAX: 703/281-6671 

On line: www.mss-hq.org 

NACE NACE International 

1440 South Creek Drive 

Houston, TX 77084-4906 

Phone: 281/228-6223 

FAX: 281/228-6329 

On line: www.nace.org 




NBBI National Board of Boiler and Pressure Vessel Inspectors 

1055 Crupper Avenue 

Columbus, Ohio 43229-1183 

Phone: 614/888-8320 

FAX: 614/848-3474 

On line: www.nationalboard.org 

NCB National Coal Board (Replaced by The Coal Authority in 1994) 

The Coal Authority 

200 Lichfield Lane 

Mansfield, Nottinghamshire NG18 4RG 

Phone: 01623-427-162 

On line: www.coal.gov.uk 

NFPA National Fire Protection Association 

1 Batterymarch Park 

Quincy, MA 02169-7471 

Phone: 800/344-3555 

FAX: 800/593-6372 

On line: www.nfpa.org 

OPS DOT/PHMSA/Office of Pipeline Safety 

Attn: Freedom of Information Act Request 

1200 New Jersey Ave., SE, Room E22321 


Phone: 202/366-4595 

FAX: 202/366-4566 

On line: ops.dot.gov 

PPI Plastics Pipe Institute 

1825 Connecticut Avenue, NW, Suite 680 

Washington, D.C. 20009 

Phone: 202/462-9607 

FAX: 202/462-9779 

On line: www.plasticpipe.org 

PRCI Pipeline Research Council International 

Home Office: Publications: 

1401 Wilson Boulevard; Suite 1101 See TTI 

Arlington, VA 22209-2505 

Phone: 703/387-0190 

Fax: 703/387-0192 

On line: www.prci.org 

SSPC Steel Structures Painting Council (Name changed in 1997 to SSPC: The Society for 

Protective Coatings) 

SSPC: The Society for Protective Coatings 

40 24th Street, 6th Floor 

Pittsburgh, PA 15222-4656 

Phone: 877/281-7772 

FAX: 412/281-9992 

On line: www.sspc.org 

Addendum No. 8, April 2007 326(b)



UL Underwriters Laboratories 

333 Pfingsten Road 

Northbrook, IL 60062-2096 

Phone: 847/272-8800 

FAX: 847/272-8129 

On line: www.ul.com 

5 ADDITIONAL INFORMATION RESOURCES 

ACGIH American Conference of Governmental Industrial Hygienists 

1330 Kemper Meadow Drive 

Cincinnati, Ohio 45240 

Phone: 513/742-2020 

Fax: 513/742-3355 

On line: www.ACGIH.org 

ASHRAE American Society of Heating, Refrigerating and Air-Conditioning Engineers, Inc. 

1791 Tullie Circle, N.E. 

Atlanta, GA 30329 

Phone: 404/636-8400 

FAX: 404/321-5478 

On line: www.ashrae.com 

Battelle Battelle 

505 King Avenue 

Columbus, OH 43201-2693 

Phone: 614/424-6393 

FAX: 614/424-3819 

On line: www.battelle.org 

BOCA Building Officials and Code Administrators International, Inc. (Replaced in 1994 by the 

or International Codes Council) 

ICC International Codes Council 

5203 Leesburg Pike, Suite 600 

Falls Church, VA 22041 

Phone: 888/422-7233 

FAX: Birmingham, AL 205-592-7001 

Chicago, IL 708/799-4981 

Wittier, CA 562/699-4522 

On line: www.iccsafe.org 

Federal U.S. Government Printing Office 

Register 732 North Capitol Street, NW 


On line: www.gpoaccess.gov/fr/advanced.html 

Global Global Engineering Documents 

15 Inverness Way East 

Englewood, CO 80112 

Phone: 800/854-7179 (Local: 303/397-7956) 

FAX: 303/397-2740 

On line: www.global.ihs.com 

Addendum No. 8, April 2007 326(c)



ILI ILI Infodisk, Inc. 

610 Winters Avenue 

Paramus, NJ 07652 

Phone: 866/816-9444 

Publications & Sales Phone: 888/454-2688 

FAX: 201/986-7886 

On line: www.ili-info.com 

ILS International Library Service 

2722 North 650 Street 

P.O. Box 735 

Provo, Utah 84603 

Phone: 801/374-6214 

FAX: 801/374-0634 

On line: www.normas.com 

NTIS National Technical Information Service 

Technology Administration 

U.S. Department of Commerce 

5285 Port Royal Road 

Springfield, VA 22161 

Phone: 703/605-6000 

Fax: 703/605-6900 

On line: www.ntis.gov 

NTSB National Transportation Safety Board 

490 L'Enfant Plaza, SW 


Phone: 800/877-6799 (Local: 202/314-6551) 

Fax: 202/314-6132 

On line: www.ntsb.gov 

Techstreet Techstreet 

777 East Eisenhower Parkway 

Ann Arbor, MI 48108 

Phone: 800/699-9277 

Fax: 734/913-3946 

On line: www.techstreet.com 

TTI Technical Toolboxes, Inc. 

3801 Kirby Drive, Suite 520 

P.O. Box 980550 

Houston, TX 77098-0550 

Phone: 713/630-0505 

Fax: 713/630-0560 

On line: www.ttoolboxes.com 

Addendum No. 8, April 2007 326(d)



6 SUMMARY OF WEBSITES 

Legend: GMA = Guide Material Appendix 

Site Reference Website Link Guide Location 

ACGIH website www.acgih.org GMA G-192-1 

AGA website www.aga.org §192.613 

GMA G-192-1 

ANSI search www.nssn.org GMA G-192-1 

ANSI website www.ansi.org GMA G-192-1 

API website www.api.org GMA G-192-1 

APWA free downloads www.apwa.net/About/PET/RightOfWay/One-Call GMA G-192-1 

APWA website www.apwa.net GMA G-192-1 

ASCE website www.asce.org GMA G-192-1 

ASHRAE website www.ashrae.com GMA G-192-1 

ASME Research www.asme.org/research GMA G-192-1 

ASME website www.asme.org GMA G-192-1 

ASTM website www.astm.org GMA G-192-1 

AWS website www.aws.org GMA G-192-1 

AWWA website awwa.org GMA G-192-1 

Battelle website www.battelle.org GMA G-192-1 

BOCA or ICC website www.iccsafe.org GMA G-192-1 

CoGDEM website www.cogdem.org.uk GMA G-192-1 

DIPRA website www.dipra.org GMA G-192-1 

Emergency Response www.the911site.com §192.905 

Federal Prisons www.bop.gov §192.905 

Federal Register website www.gpoaccess.gov/fr/advanced.html GMA G-192-1 

4-H Facilities dmoz.org/Society/People/Generations_and_ 

§192.905 

Age_Groups/Youth/Organizations/4-H/Camps/ 

Global Engineering website www.global.ihs.com GMA G-192-1 

GTI website www.gastechnology.org GMA G-192-1 

Hospitals adams.mgh.harvard.edu/hospitalwebusa.html §192.905 

IAPMO website www.iapmo.org/iapmo GMA G-192-1 

ILI Infodisk website www.ili-info.com GMA G-192-1 

ILS website www.normas.com GMA G-192-1 

MSS website www.mss-hq.org GMA G-192-1 

NACE website www.nace.org GMA G-192-1 

NAPSR website www.napsr.org §192.909 

§192.949 

National Parks www.recreation.gov §192.905 

NBBI website www.nationalboard.org GMA G-192-1 

NCB website www.coal.gov.uk GMA G-192-1 

NFPA website www.nfpa.org GMA G-192-1 

NRC pipeline reports website www.nrc.uscg.mil/pipelinereporttxt.htm §191.5 

NTIS website www.ntis.gov GMA G-192-1 

NTSB reports www.ntsb.gov/publictn §192.613 

NTSB website www.ntsb.gov GMA G-192-1 

OPS Advisory Bulletins via FR www.gpoaccess.gov/fr/advanced.html §192.9 

§192.613 

Addendum No. 8, April 2007 326(d-1)



Site Reference (Continued) Website Link Guide Location 

OPS Home Page ops.dot.gov §192.951 

GMA G-192-1 

OPS Information Officer email roger.little@dot.gov §192.727 

OPS Integrity Management primis.phmsa.dot.gov/gasimp §192.949 

Database 

OPS NPMS homepage www.npms.phmsa.dot.gov §192.727 

OPS Report Forms ops.dot.gov/library/forms/forms.htm §191.9 

§191.11 

GMA G-191-2 

GMA G-191-3 

GMA G-191-4 

GMA G-191-5 

OPS Reporting Measures http://opsweb.rspa.dot.gov/gasimp/docs/ 

§192.945 

Partnership for Excellence in 

Pipeline Safety 

(NASFM/PHMSA) 

Gas%20IMP%20Reporting%20Instructions.pdf 

www.safepipelines.org §192.905 

PPI website www.plasticpipe.org GMA G-192-1 

PRCI website www.prci.org GMA G-192-1 

SSPC website www.sspc.org GMA G-192-1 

Technical Paper (see 

reference under §192.613) 

www.aga.org/gptc §192.613 

TTI website www.ttoolboxes.com GMA G-192-1 

UL website www.ul.com GMA G-192-1 

US Census Bureau Tool tiger.census.gov/cgi-bin/mapbrowse-tbl 

GMA G-191-2 

GMA G-191-4 

Addendum No. 8, April 2007 326(d-2)

GPTC Z380.1 - Addendum No. 8 - 2007 - American Gas Association

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