American National Standards InstitutePaul Cabot, C.G.E. GPTC Secretary (202) 824-7312 Fax (202) 824-9122 [email protected] October 20, 2011 Dear Guide Purchaser, Enclosed is Addendum

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

Fax (202) 824-9122 [email protected]

October 20, 2011

Dear Guide Purchaser,

Enclosed is Addendum 7 to ANSI GPTC Z380, Guide for Gas Transmission and Distribution

Piping Systems, 2009 Edition. Addenda are formatted to enable the replacement of pages in your

Guide with the updated enclosed pages. Please follow the enclosed page replacement instructions.

On behalf of the Gas Piping Technology Committee and the American Gas Association, thank

you for your purchase and interest in the Guide.

Sincerely

Secretary

GPTC/Z380

This is a preview of "AGA Z38010907". Click here to purchase the full version from the ANSI store.

https://webstore.ansi.org/Standards/AGA/AGAZ38010907?source=preview

B L A N K



1

GPTC GUIDE FOR GAS TRANSMISSION AND DISTRIBUTION PIPING SYSTEMS

2009 EDITON

ADDENDUM 7, July 2011 The changes in this addendum are marked by wide vertical lines inserted to the left of modified text, overwriting the left border of most tables, or a block symbol ( ▌) where needed. The Federal Regulations were updated by 1 amendment that affected 3 sections of the Guide. Seven GPTC transactions affected 17 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. Editorial updates as indicated “EU” affected 9 sections of the Guide (plus other sections impacted by page adjustments, etc.). The following table shows the affected sections, the pages to be removed, and their replacement pages.



2

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

Guide Section Reason For Change Pages to be Removed Replacement Pages

Title Page EU i/ii i/ii

Table of Contents EU ix/x ix/x

Historical Reconstruction of Part 192

Amdt. 192-117 xxv/xxvi, xxxi/xxxii xxv/xxvi, xxxi/xxxii

Historical Record of Amendments to Part 192

Amdt. 192-117 lv/lvi, lvii/lviii lv/lvi, lvii/lviii

Membership List EU lix/lx thru lxvii/lxviii lix/lx thru lxvii/lxviii

Subpart A 192.3 TR06-41 21(b)/22 21(b)/22

Subpart C 192.105 EU 47/48 47/48

192.123 EU, TR11-03 63/64, 65/66 63/64, 65/66

Subpart J 192.515 EU, TR10-24 207/208 207/208

Subpart L 192.631 Amdt. 192-117 268(a)/268(b), 268(c)/268(d)

268(a)/268(b), 268(c)/268(d)

Subpart M 192.711 TR10-30 277/278 277/278

192.717 TR10-30 279/280 279/280

Subpart O 192.907 TR10-35 329/330 329/330

192.925 TR10-35 347/348, 355/356, 356(a)/356(b), 356(c)/356(d), 356(i)/356(j), 356(m)/356(n)

347/348, 355/356, 356(a)/356(b), 356(c)/356(d), 356(i)/356(j), 356(m)/356(n)

192.931 TR10-35 356(o)/356(p) 356(o)/356(p)

192.935 TR10-35 359/360, 361/362 359/360, 361/362

192.941 TR10-35 371/372 371/372

192.943 EU 373/374 373/374

192.945 TR10-35

192.951 EU 377/378 377/378

GMA G-192-1 TR09-28, TR11-03 421/422 thru 425/426, 429/430

421/422 thru 425/426, 429/430

GMA G-192-11 TR06-41 515/516 thru 525/526 515/516 thru 525/526

GMA G-192-11A TR06-41 537/538 thru 545/546 537/538 thru 545/546

GMA G-192-15A EU, TR09-28 561/562, 563/564 561/562, 563/564

GMA G-192-15B TR09-28 564(c)/564(d) 564(c)/564(d)

GMA G-192-17 TR10-21 571/572 thru 573(b)/574 571/572 thru 573(b)/574



i

Guide for Gas Transmission

and Distribution Piping

Systems

2009 Edition

Addendum 7, July 2011

an American National Standard

Author:

Gas Piping Technology Committee (GPTC) Z380 Accredited by ANSI

Secretariat:

American Gas Association

Approved by

American National Standards Institute (ANSI) October 19, 2011

ANSI/GPTC Z380.1-2009, Addendum No. 7-2011

Catalog Number: Z3801097



GPTC GUIDE FOR GAS TRANSMISSION AND DISTRIBUTION PIPING SYSTEMS: 2009 Edition

ii

PLEASE NOTE

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

CAUTION

As part of document purchase, GPTC (using AGA as Secretariat) will try to keep purchasers informed on the current Federal Regulations as released by the Department of Transportation (DOT). This is done by periodically issuing addenda to update both the Federal Regulations and the guide material. It is the responsibility of the purchaser to obtain a copy of any addenda. Addenda are posted on the Committee’s webpage at www.aga.org/gptc. The GPTC assumes no responsibility in the event the

purchaser does not obtain addenda. The purchaser is reminded that the changes to the Regulations can be 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 2011 THE AMERICAN GAS ASSOCIATION

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

All Rights Reserved Printed in U.S.A.




Addendum 7, July 2011 ix

SUBPART N -- QUALIFICATION OF PIPELINE PERSONNEL ..................................................... 305 192.801 Scope ....................................................................................................................... 305 192.803 Definitions ................................................................................................................ 306 192.805 Qualification program ............................................................................................... 309 192.807 Recordkeeping ......................................................................................................... 315 192.809 General .................................................................................................................... 316 SUBPART O – GAS TRANSMISSION PIPELINE INTEGRITY MANAGEMENT ........................... 319 192.901 What do the regulations in this subpart cover? ....................................................... 319 192.903 What definitions apply to this subpart? .................................................................... 320 192.905 How does an operator identify a high consequence area? ..................................... 323 192.907 What must an operator do to implement this subpart? ........................................... 329 192.909 How can an operator change its integrity management program?......................... 331 192.911 What are the elements of an integrity management program? .............................. 332 192.913 When may an operator deviate its program from certain requirements of this subpart? ............................................................................................... 335 192.915 What knowledge and training must personnel have to carry out an integrity management program? .................................................................... 336 192.917 How does an operator identify potential threats to pipeline integrity and use the threat identification in its integrity program? .............................. 338 192.919 What must be in the baseline assessment plan? ................................................... 339 192.921 How is the baseline assessment to be conducted? ................................................ 344 192.923 How is direct assessment used and for what threats? ........................................... 345 192.925 What are the requirements for using External Corrosion Direct Assessment (ECDA)? .................................................................................... 346 192.927 What are the requirements for using Internal Corrosion Direct Assessment (ICDA)? ................................................................................. 356(m) 192.929 What are the requirements for using Direct Assessment for Stress Corrosion Cracking (SCCDA)? .................................................................. 356(o) 192.931 How may Confirmatory Direct Assessment (CDA) be used? ............................. 356(p) 192.933 What actions must an operator take to address integrity issues? .......................... 357 192.935 What additional preventive and mitigative measures must an operator take?................................................................................................. 359 192.937 What is a continual process of evaluation and assessment to maintain a pipeline’s integrity? ....................................................................... 364 192.939 What are the required reassessment intervals? ..................................................... 366 192.941 What is a low stress reassessment? ....................................................................... 370 192.943 When can an operator deviate from these reassessment intervals? ..................... 372 192.945 What methods must an operator use to measure program effectiveness? ................................................................................................. 374 192.947 What records must an operator keep? ................................................................... 375 192.949 How does an operator notify PHMSA? .................................................................... 376 192.951 Where does an operator file a report? .................................................................... 378 SUBPART P – GAS DISTRIBUTION PIPELINE INTEGRITY MANAGEMENT (IM) ..................... 379 192.1001 What definitions apply to this subpart? .................................................................... 379 192.1003 What do the regulations in this subpart cover? ....................................................... 379 192.1005 What must a gas distribution operator (other than a master meter or small LPG operator) do to implement this subpart? ...................................... 380 192.1007 What are the required elements of an integrity management (IM) plan? ............... 380 192.1009 What must an operator report when compression couplings fail? ..................... 380(b) 192.1011 What records must an operator keep? ............................................................... 380(b)




Addendum 6, April 2011 x

192.1013 When may an operator deviate from required periodic inspections ................... 380(c) under this part? 192.1015 What must a master meter or small liquefied petroleum gas (LPG) operator ... 380(c) do to implement this subpart? APPENDICES TO PART 192 Appendix A (Removed and reserved) ................................................................................... 381 Appendix B Qualification of Pipe ........................................................................................... 383 Appendix C Qualification of Welders for Low Stress Level Pipe .......................................... 387 Appendix D Criteria for Cathodic Protection and Determination of Measurements ............. 391 Appendix E Guidance on Determining High Consequence Areas and on Carrying out Requirements in the Integrity Management Rule .................... 393 GUIDE MATERIAL APPENDICES Guide Material Appendix G-191-1 Telephonic notice worksheet ...................................... 401 Guide Material Appendix G-191-2 Distribution system incident report .............................. 403 Guide Material Appendix G-191-3 Distribution system annual report ............................... 405 Guide Material Appendix G-191-3A Distribution system mechanical fitting failure report.................................................... 406(a) Guide Material Appendix G-191-4 Transmission and gathering systems incident report ..................................................... 407 Guide Material Appendix G-191-5 Transmission and gathering systems annual report ...................................................... 409 Guide Material Appendix G-191-6 Determination of reporting requirements for safety-related conditions .............................. 411 Guide Material Appendix G-191-7 Safety-related condition report to United States Department of Transportation ............................ 413 Guide Material Appendix G-192-1 Summary of references and related sources ............. 415 Guide Material Appendix G-192-1A Editions of material specifications, codes and standards previously incorporated by reference in the Regulations ........................................................ 439 Guide Material Appendix G-192-2 Specified minimum yield strengths ............................. 443 Guide Material Appendix G-192-3 Flexibility factor k and stress intensification factor i ......................................... 447 Guide Material Appendix G-192-4 Rules for reinforcement of welded branch connections ........................................................ 451 Guide Material Appendix G-192-5 Pipe end preparation ................................................... 461 Guide Material Appendix G-192-6 Substructure damage prevention guidelines for directional drilling and other trenchless technologies ....................................................... 467 Guide Material Appendix G-192-7 Large-scale distribution outage response and recovery .............................................................. 469 Guide Material Appendix G-192-8 Distribution Integrity Management Program (DIMP) ................................................................ 473 Guide Material Appendix G-192-9 Test conditions for pipelines other than service lines ............................................... 501 Guide Material Appendix G-192-10 Test conditions for service lines .................................. 503 Guide Material Appendix G-192-11 Gas leakage control guidelines for natural gas systems ...................................... 505 Guide Material Appendix G-192-11A Gas leakage control guidelines for petroleum gas systems ................................. 527 Guide Material Appendix G-192-12 Planned shutdown ....................................................... 547 Guide Material Appendix G-192-13 Considerations to minimize damage by outside forces .................................................................. 551 Guide Material Appendix G-192-14 [Reserved] ................................................................... 555




Addendum 7, July 2011 xxv

HISTORICAL RECONSTRUCTION OF PART 192 (Complete through Amendment 192-117)

Part 192 Subpart

Part 192 Section

Effective Date of Original Version if other than 11/12/70

Amendments (if any)

SUBPART A – GENERAL

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

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

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

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

192.8 04/14/06 192-102 192.9 192-72 + Ext., 192-95 Corr., 192-102 192.10 03/19/98 192-81, RIN 2137-AD77 192.11 11/13/72 192-68, 192-75, 192-78 [192.12] 192-10, 192-36 (removed) 192.13 192-27, 192-30, 192-102 192.14 12/30/77 192-30 192.15 192.16 09/13/95 192-74, 192-74A, 192-84 [192.17] 01/01/71 192-1, 192-27A Ext., 192-38

(removed)

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

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

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

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




Addendum 5, November 2010 xxvi

HISTORICAL RECONSTRUCTION OF PART 192 (Continued)

Part 192 Subpart

Part 192 Section


Amendments (if any)

SUBPART C – PIPE 192.101 DESIGN 192.103 192.105 192-47, 192-85 192.107 192-78, 192-84, 192-85 192.109 192-85 192.111 192-27 192.112 12/22/08 RIN 2137-AE25, 192-111 192.113 192-37, 192-51, 192-62, 192-68,

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

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

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

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

192.125 192-62, 192-85




Addendum 7, July 2011 xxxi


Part 192 Subpart

Part 192 Section


Amendments (if any)

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

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

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

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

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

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

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

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

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

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

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

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

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




Addendum 5, November 2010 xxxii


Part 192 Subpart

Part 192 Section


Amendments (if any)

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

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

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

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

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




Addendum 5, November 2010 lv

HISTORICAL RECORD OF AMENDMENTS TO PART 192

(Continued)

Amdt 192-

Subject Vol FR Pg# Published Date

Docket or RIN No.

Effective Date

Affected Sections 192.

[107 Stay] Standards for Increasing the Maximum Allowable Operating Pressure for Gas Transmission Pipelines

73 FR 72737 12/01/08 RIN 2137-AE25

[Ref. as “Eff. date stayed”]

12/22/08 112, 328, 611, 619, 620

[108] Polyamide-11 (PA-11) Plastic Pipe Design Pressures

73 FR 79002 12/24/08 RIN 2137-AE26

01/23/09 121, 123

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

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

[Ref. as (#2)]

02/17/09 7, 727, 949, 951

[110] Incorporated by Reference Update: American Petroleum Institute (API) Standards 5L and 1104*

74 FR 17099 04/14/09 RIN 2137-AE42

04/14/09 7




Addendum 7, July 2011 lvi


(Continued)

Amdt 192-


Docket or RIN No.

Effective Date


[110] DFR Confirmation 74 FR 30476 06/26/09 RIN 2137-AE42

04/14/09 7

111 Editorial Amendments to the Pipeline Safety Regulations

74 FR 62503 11/30/09 RIN 2137-AE51

01/29/10 112, 121, 620

112 Control Room Management / Human Factors

74 FR 63310 12/03/09 RIN 2137-AE28

02/01/10 3, 7, 605, 615, 631

112 Correction 75 FR 5536 02/03/10 RIN 2137-AE28

Applicable 02/01/10

631

113 Integrity Management Program for Gas Distribution Pipelines

74 FR 63906 12/04/09 RIN 2137-AE15

02/02/10 383, 1001, 1003, 1005, 1007, 1009, 1011, 1013, 1015

113 Correction 75 FR 5244 02/02/10 RIN 2137-AE15

02/12/10 383, 1001, 1003, 1005, 1007, 1009, 1011, 1013, 1015

114 Periodic Updates of Regulatory References to Technical Standards and Miscellaneous Edits

75 FR 48593 08/11/10 RIN 2137-AE41

10/01/10 3, 7, 63, 65, 121, 123, 145, 191, 281, 283, 465, 711, 923, 925, 931, 935, 939,

App.B




Addendum 7, July 2011 lvii


(Continued)

Amdt 192-


Docket or RIN No.

Effective Date


115 Updates to Pipeline and Liquefied Natural Gas Reporting Requirements

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

01/01/11 945, 951

116 Mechanical Fitting Failure Reporting Requirements

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

04/04/11 383, 1001, 1007, 1009

117 Control Room Management/Human Factors

76 FR 35130 06/16/11 RIN 2137-AE64

08/15/11 631

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




Addendum 7, July 2011 lviii

Reserved




Addendum 7, July 2011 lix

GAS PIPING TECHNOLOGY COMMITTEE MEMBERSHIP LIST

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

M

ain Body

D

istribution

M

anufacturers

Transm

ission

D

esign

D

P/ER

IM

P/Corrosion

O

&M

/OQ

Plastic Pipe

Editorial

Executive

Liaison

R

egulations

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

Ambrogio, Edward Iroquois Pipeline Operating Co., Shelton, CT X X

Anderson, William AGL Resources, Atlanta, GA X X X

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

Bateman, Stephen C. City of Long Beach – Gas & Oil Dept., Long Beach, CA

X X X X

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

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

Bennett, Frank M. PPL Interstate Energy Company, Pottstown, PA X X Sec




Addendum 7, July 2011 lx

GAS PIPING TECHNOLOGY COMMITTEE MEMBERSHIP LIST (Continued)


M

ain Body

D

istribution

M

anufacturers

Transm

ission

D

esign

D

P/ER

IM

P/Corrosion

O

&M

/OQ

Plastic Pipe

Editorial

Executive

Liaison

R

egulations

Berg, Lawrence M. Pacific Gas & Electric, Walnut Creek, CA X X X

Bevers, Bruce S. Williams Gas Pipeline, Houston, TX X X X

Blaney, Steven D. NY State Dept. of Public Service, Albany, NY X X X X X

Bloome, John A. Iowa Utilities Board/NAPSR, Des Moines, IA X X X

Boros, Stephen Plastics Pipe Institute, Irving, TX X X

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

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

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

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




Addendum 7, July 2011 lxi



M

ain Body

D

istribution

M

anufacturers

Transm

ission

D

esign

D

P/ER

IM

P/Corrosion

O

&M

/OQ

Plastic Pipe

Editorial

Executive

Liaison

R

egulations

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

Cardin, Jeanne L. Southwest Gas Corp., Las Vegas, NV X X

Cary, Willard S. Energy Experts International, Neptune, NJ X X X Sec X

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

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

Cody, Leo T. National Grid, Waltham, MA X X X

Craig, Jim M. McElroy Manufacturing, Inc., Tulsa, OK X X X

Del Buono, Amerigo J. Steel Forgings, Inc., League City, TX X X

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




Addendum 7, July 2011 lxii



M

ain Body

D

istribution

M

anufacturers

Transm

ission

D

esign

D

P/ER

IM

P/Corrosion

O

&M

/OQ

Plastic Pipe

Editorial

Executive

Liaison

R

egulations

Duncombe, Lauri Williams Gas Pipeline, Salt Lake City, UT X X X

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

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

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

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

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

Frantz, John H. Consultant, Oreland, PA X X X X X Chair

Frederick, Victor M., III Omega Tools, Allentown, PA X X X

Friend, Mary S. PHMSA-OPS, Oklahoma City, OK X X X X

Gann, Jerry V. CenterPoint Energy, Houston, TX X X X

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




Addendum 7, July 2011 lxiii



M

ain Body

D

istribution

M

anufacturers

Transm

ission

D

esign

D

P/ER

IM

P/Corrosion

O

&M

/OQ

Plastic Pipe

Editorial

Executive

Liaison

R

egulations

Goetz, John Meade, McCook, IL X X

Graeser, Ralph A. PA Public Utility Comm., Harrisburg, PA X X

Groeber, Steven A. Philadelphia Gas Works, Philadelphia, PA X X X X X

Gunther, Karl M. NTSB, Washington, DC X X X

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

Hansen, James P. Elster Perfection Corp., Madison, OH X X

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

Hart, Thomas L. NSTAR Electric & Gas Corp., Westwood, MA X X X

Heintz, James R. UGI Utilities, Inc., Reading, PA X X X X

Hotinger, James M. VA State Corp. Comm., Richmond, VA X X X

Hurbanek, Stephen F. NC Utilities Commission, New Bern, NC X X

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




Addendum 7, July 2011 lxiv



M

ain Body

D

istribution

M

anufacturers

Transm

ission

D

esign

D

P/ER

IM

P/Corrosion

O

&M

/OQ

Plastic Pipe

Editorial

Executive

Liaison

R

egulations

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

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

Krummert, Lawrence M. Columbia Gas of PA, Inc., New Castle, PA X X X

Lee, Douglas M. Kadrmas, Lee & Jackson, Bismarck, ND X X X

Lever, Ernest GTI, Des Plaines, IL X X

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

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

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

Lopez, Paul A. El Paso Corp., Colorado Springs, CO X X X

Lueders, John D. DTE Energy - MichCon, Grand Rapids, MI X X Sec X

Mackay-Smith, Seth UMAC Inc., Malvern, PA X X X X

Mackin, John Equitable Gas, Pittsburgh, PA X X X




Addendum 7, July 2011 lxv



M

ain Body

D

istribution

M

anufacturers

Transm

ission

D

esign

D

P/ER

IM

P/Corrosion

O

&M

/OQ

Plastic Pipe

Editorial

Executive

Liaison

R

egulations

Marek, Marti Southwest Gas Corp., Las Vegas, NV Chair X

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

McKay, Erin Alyeska Pipeline Service Company, Anchorage, AK X X X

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

McLaren, Theron (Chris) PHMSA – SW Region, Houston, TX X X

Miller, D. Lane PHMSA-OPS, Oklahoma City, OK X X X X Sec

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

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

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

Peters, Kenneth C. El Paso Corporation, Birmingham, AL X Chair X X X

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




Addendum 7, July 2011 lxvi



M

ain Body

D

istribution

M

anufacturers

Transm

ission

D

esign

D

P/ER

IM

P/Corrosion

O

&M

/OQ

Plastic Pipe

Editorial

Executive

Liaison

R

egulations

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

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

Quezada, Leticia Nicor Gas, Naperville, IL

1st V Chair Chair

Reistetter, Dave San Diego Gas & Electric, San Diego, CA X X X

Reynolds, Donald Lee NiSource Inc., Columbus, OH X Chair X X X

Risley, Heather UGI Utilities, Reading, PA X X X

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

Schow, Boyd L. Williams Gas Pipeline, Salt Lake City, UT X X

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

Sher, Philip Philip Sher Pipeline Consultant, Cheshire, CT

2nd V Chair X

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

Sieve, Joseph PHMSA – OPS, Washington, DC X X




Addendum 7, July 2011 lxvii



M

ain Body

D

istribution

M

anufacturers

Transm

ission

D

esign

D

P/ER

IM

P/Corrosion

O

&M

/OQ

Plastic Pipe

Editorial

Executive

Liaison

R

egulations

Slagle, Richard L. Vectren Energy Delivery, Evansville, IN X Sec X Chair X

Smallwood, Larry Southern Cross Corp., Norcross, GA X X

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

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

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

Torbin, Robert N. Cutting Edge Solutions LLC, Framingham, MA X X

Troch, Steven J. Baltimore Gas & Electric Co., Baltimore, MD X X X X

Ulanday, Alfredo (Fred) S. Integrys Gas Group, Chicago, IL X X X

Veerapaneni, Ram DTE Energy – MichCon, Detroit, MI X X X X X X

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

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

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




Addendum 7, July 2011 lxviii



M

ain Body

D

istribution

M

anufacturers

Transm

ission

D

esign

D

P/ER

IM

P/Corrosion

O

&M

/OQ

Plastic Pipe

Editorial

Executive

Liaison

R

egulations

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

Wilkes, Alfred L. Performance Pipe, Plano, TX X X X X

Wolf, Brian Schmid Pipeline Construction, Mayville, WI X X X

Wolf, Richard UBE America, Birdsboro, PA X X

Wong, Anson Southern California Gas Co., Los Angeles, CA X X X



GPTC GUIDE FOR GAS TRANSMISSION AND §192.3 DISTRIBUTION PIPING SYSTEMS: 2009 Edition SUBPART A

Addendum 7, July 2011 21(b)

GLOSSARY OF COMMONLY USED ABBREVIATIONS

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

Abbreviation Meaning

ABS acrylonitrile-butadiene-styrene ACVG alternating current voltage gradient AOC abnormal operating condition ASV automatic shutoff valve BAP baseline assessment plan CAB cellulose acetate butyrate CDA confirmatory direct assessment CGI combustible gas indicator CIS close-interval survey CP cathodic protection CTS copper tube size DA direct assessment DCVG direct current voltage gradient 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 GIS geographic information system GPS global positioning system HCA high consequence area HDB hydrostatic design basis HFI hydrogen flame ionization IC internal corrosion ICDA internal corrosion direct assessment ICS Incident Command System ILI In-line inspection IMP integrity management program IPS iron pipe size IR drop voltage drop LEL lower explosive limit LNG liquefied natural gas LPG liquid petroleum gas LTHS long-term hydrostatic strength



GPTC GUIDE FOR GAS TRANSMISSION AND §192.3 DISTRIBUTION PIPING SYSTEMS: 2009 Edition SUBPART A

Addendum 4, July 2010 22

GLOSSARY OF COMMONLY USED ABBREVIATIONS (Continued)

Abbreviation Meaning

MAOP maximum allowable operating pressure MOC management of change MRS minimum required strength NDE nondestructive evaluation NPS nominal pipe size O&M operations and maintenance OCS outer continental shelf OQ operator qualification PA polyamide P&M measures preventive and mitigative measures PDB pressure design basis PE polyethylene PIC potential impact circle PIR potential impact radius PVC poly (vinyl chloride), also written as polyvinyl chloride RCV remote control valve SCADA supervisory control and data acquisition SCC stress corrosion cracking SCCDA stress corrosion cracking direct assessment SDB strength design basis SDR standard dimension ratio SME subject matter expert SMYS specified minimum yield strength USGS United States Geological Survey USCG United States Coast Guard

TABLE 192.3i



GPTC GUIDE FOR GAS TRANSMISSION AND 192.101 DISTRIBUTION PIPING SYSTEMS: 2009 Edition SUBPART C

47

SUBPART C PIPE DESIGN

§192.101 Scope.

[Effective Date: 11/12/70]

This subpart prescribes the minimum requirements for the design of pipe.

GUIDE MATERIAL

No guide material necessary.

§192.103 General.


Pipe must be designed with sufficient wall thickness, or must be installed with adequate protection, to withstand anticipated external pressures and loads that will be imposed on the pipe after installation.

GUIDE MATERIAL

1 GENERAL

The minimum wall thickness for pressure containment as calculated under §192.105 may not be adequate to withstand other forces to which the pipeline may be subjected. Consideration should be given to stresses associated with transportation, handling the pipe during construction, weight of water during testing, buoyancy, geotechnical forces, and other secondary loads that may occur during construction, operation or maintenance. Consideration should also be given to welding or mechanical joining requirements.

2 NON-STEEL PIPE

The minimum wall thickness for materials other than steel pipe are prescribed elsewhere in Part 192. See §§192.123 and 192.125.

3 REFERENCES

Numerous references are available for the calculation of external forces on pipelines. Methods include reliance on experience, empirical formula, and finite element analysis. A partial listing of references follows.

(a) API RP 5L1, “Recommended Practice for Railroad Transportation of Line Pipe.” (b) API RP 5LW, “Recommended Practice for Transportation of Line Pipe on Barges and Marine Vessels."





(c) API RP 1102, “Steel Pipelines Crossing Railroads and Highways.” (d) API RP 1117, “Movement of In-Service Pipelines.” (e) ASCE 428-5, “Guidelines for the Seismic Design of Oil and Gas Pipeline Systems" (Discontinued). (f) GRI-91/0283, “Guidelines for Pipelines Crossing Railroads.” (g) GRI-91/0284, “Guidelines for Pipelines Crossing Highways.”

§192.105 Design formula for steel pipe.


(a) The design pressure for steel pipe is determined in accordance with the following formula: P = 2 St x F x E x T

D P = Design pressure in pounds per square inch (kPa) gage. S = Yield strength in pounds per square inch (kPa) determined in accordance with §192.107. D = Nominal outside diameter of the pipe in inches (millimeters). t = Nominal wall thickness of the pipe in inches (millimeters). If this is unknown, it is determined in

accordance with §192.109. Additional wall thickness required for concurrent external loads in accordance with §192.103 may not be included in computing design pressure.

F = Design factor determined in accordance with §192.111. E = Longitudinal joint factor determined in accordance with §192.113. T = Temperature derating factor determined in accordance with §192.115. (b) If steel pipe that has been subjected to cold expansion to meet the SMYS is subsequently heated, other than by welding or stress relieving as a part of welding, the design pressure is limited to 75 percent of the pressure determined under paragraph (a) of this section if the temperature of the pipe exceeds 900 oF (482 oC) at any time or is held above 600 oF (316 oC) for more than 1 hour. [Amdt. 192-47, 49 FR 7567, Mar. 1, 1984; Amdt. 192-85, 63 FR 37500, July 13, 1998]

GUIDE MATERIAL 1 WALL THICKNESS

The nominal wall thickness (t) should not be less than that determined by the considerations given in the guide material under §192.103.

2 NOMINAL OUTSIDE DIAMETER

The nominal outside diameter (D) used in the design formula is listed in Table 192.105i for nominal pipe sizes (NPS) 12 and less. For pipe greater than NPS 12, the nominal pipe size and nominal outside diameter are the same. Pipe may be ordered by the nominal pipe size; however, the nominal outside diameter is required in the design formula for steel pipe.





consistent with that operating temperature; or (2) Above the following applicable temperatures: (i) For thermoplastic pipe, the temperature at which the HDB used in the design formula under §192.121 is determined. (ii) For reinforced thermosetting plastic pipe, 150 oF (66 oC). (c) The wall thickness for thermoplastic pipe may not be less than 0.062 inches (1.57 millimeters). (d) The wall thickness for reinforced thermosetting plastic pipe may not be less than that listed in the following table:

Nominal size in

inches (millimeters)

Minimum wall thickness in

inches (millimeters)

2 (51) 3 (76) 4 (102) 6 (152)

0.060 (1.52) 0.060 (1.52) 0.070 (1.78) 0.100 (2.54)

(e) The design pressure for thermoplastic pipe produced after July 14, 2004 may exceed a gauge pressure of 100 psig (689 kPa) provided that: (1) The design pressure does not exceed 125 psig (862 kPa); (2) The material is a PE2406 or a PE3408 as specified within ASTM D2513-99 (incorporated by reference, see §192.7); (3) The pipe size is nominal pipe size (IPS) 12 or less; and (4) The design pressure is determined in accordance with the design equation defined in §192.121. (f) The design pressure for polyamide-11 (PA-11) pipe produced after January 23, 2009 may exceed a gauge pressure of 100 psig (689 kPa) provided that: (1) The design pressure does not exceed 200 psig (1379 kPa); (2) The pipe size is nominal pipe size (IPS or CTS) 4-inch or less; and (3) The pipe has a standard dimension ratio of SDR-11 or greater (i.e., thicker pipe wall). [Amdt. 192-31, 43 FR 13880, Apr. 3, 1978; Amdt. 192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-93, 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; Amdt. 192-103, 71 FR 33402, June 9, 2006; RIN 2137-AE26, 73 FR 79002, Dec. 24, 2008; Amdt. 192-114, 75 FR 48593, Aug. 11, 2010]

GUIDE MATERIAL 1 IMPACT AND DUCTILITY (a) The impact and ductility properties of plastics should be evaluated when the material is intended for

use in facilities subjected to low temperatures. Lower temperatures will affect thermoplastic pipe by increasing stiffness and vulnerability to impact damage.

(b) Significant impact or shock loads on thermoplastic pipe at low temperatures can fracture the pipe. Care should be taken to avoid dropping or striking the pipe with handling equipment, tools, or other objects.




Addendum 3, March 2010 64

(c) For coiled pipe, lower temperatures will require more effort to uncoil the pipe, and it can spring back forcibly if the ends are not anchored or restrained. The forceful movement of the loose pipe ends becomes more pronounced in cold weather and personnel should be aware of this for their own safety. Extra precautions should be taken when installing larger-diameter coiled pipe (>3-inch) in cold temperature conditions. The manufacturer of straightening and re-rounding equipment should be consulted for recommendations regarding low-temperature equipment operation.

2 PETROLEUM GASES The pressure-temperature relationship with petroleum gases should be such that condensation will not

occur when using PE piping. 3 HOT TAPS (a) When making a hot-plate saddle fusion on PE pipelines, the probability of a blowout increases with

an increase in pressure or a decrease in wall thickness. This should be considered, particularly when performing hot-plate saddle fusion on PE pipelines as follows: 1-inch and 1¼-inch pipe with an SDR greater than 10, and 2-inch, 3-inch, and 4-inch pipe with an SDR greater than 11. Where this is a concern, the pipeline pressure may need to be reduced during such fusions. Alternatively, a heavier-wall thickness could be used than that required by the pressure design formula. See PPI TR-41, “Generic Saddle Fusion Joining Procedure for Polyethylene Gas Piping.”

(b) Electrofusion tapping tees may be used as an alternate to hot-plate, fusion tapping tees to reduce the probability of blowouts when hot tapping PE pipes. The manufacturer of the electrofusion fitting should be contacted for recommendations.

(c) Mechanical tapping tees may be used as an alternative to heat-fusion tapping tees to avoid the possibility of blowouts when tapping PE pipes.

4 EFFECTS OF LIQUID HYDROCARBONS 4.1 General.

Liquid hydrocarbons such as gasoline, diesel fuel, and condensates, either inside the pipe or in the surrounding soil, are known to have a detrimental effect on PE and PVC plastic piping materials. PA 11 piping is not affected by liquid hydrocarbons. Contact the piping manufacturer for specific recommendations.

4.2 Effect on design pressure (see §192.121). (a) If thermoplastic materials covered by ASTM D 2513 are to be exposed continuously to liquid

hydrocarbons, it is recommended that the design pressure be de-rated in accordance with the following formula. See 4.3 below for references on this subject.

Pde-rated = P§192.121 x DFC Where: Pde-rated = De-rated design pressure, gauge, psig (kPa). P§192.121 = Design pressure, gauge, psig (kPa) determined under §192.121. DFC = Chemical Design Factor determined in accordance with Table 192.123i.





Pipe Material Chemical Design Factor PA (polyamide) 1.00 PE (polyethylene) 0.50 PVC (polyvinyl chloride) 0.50

TABLE 192.123i

(b) If PE or PVC pipe is to be exposed intermittently to liquid hydrocarbons, the pipe manufacturer

should be consulted to determine the appropriate DFC.

4.3 References. (a) PA pipe. (1) “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. (2) “Polyamide 11 Liners Withstand Hydrocarbons, High Temperature,” A. Berry, Pipeline & Gas

Journal, December 1998, p. 81. (b) PE pipe. (1) PPI TR-9, “Recommended Design Factors and Design Coefficients for Thermoplastic Pressure

Pipe.” (2) PPI TR-22, “Polyethylene Piping Distribution Systems for Components of Liquid Petroleum

Gases.” (3) “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.

(4) “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.

(5) GRI 96/0194, “Service Effects of Hydrocarbons on Fusion and Mechanical Performance of Polyethylene Gas Distribution Piping.”

(c) PVC pipe. “Prediction of Organic Chemical Permeation through PVC Pipe,” A.R. Berens, Research

Technology, November 1985, p. 57. 5 PLASTIC PIPE MANUFACTURED BEFORE MAY 18, 1978 The following language was removed from §192.123(b)(2)(i) by Amendment 192-93: “However, if the pipe was manufactured before May 18, 1978 and its long-term hydrostatic strength was determined at 73 ºF (23 ºC), it may be used at temperatures up to 100 ºF (38 ºC).”

This language permitted the installation and operation of plastic pipe manufactured prior to May 18, 1978, at temperatures up to 100 ºF using the 73 ºF HDB. This sentence was removed since this vintage plastic pipe is no longer available nor is it still being installed. However, pipe installed under this clause is “grandfathered” and can continue to be operated at temperatures up to 100 ºF using the 73 ºF HDB.

6 MECHANICAL FITTINGS ASTM Subcommittee F17.60 publishes the following specifications to qualify mechanical fittings that

connect plastic pipe for design temperatures from -20 ºF to 140 ºF. (a) ASTM F1924, “Standard Specification for Plastic Mechanical Fittings for Use on Outside

Diameter Controlled Polyethylene Gas Distribution Pipe and Tubing.” (b) ASTM F1948, “Standard Specification for Metallic Mechanical Fittings for Use on Outside

Diameter Controlled Thermoplastic Gas Distribution Pipe and Tubing.”





(c) ASTM F1973, “Standard Specification for Factory Assembled Anodeless Risers and Transition Fittings in Polyethylene (PE) and Polyamide 11 (PA11) and Polyamide 12 (PA12) Fuel Gas Distribution Systems.”

§192.125 Design of copper pipe.


(a) Copper pipe used in mains must have a minimum wall thickness of 0.065 inches (1.65 millimeters) and must be hard drawn. (b) Copper pipe used in service lines must have wall thickness not less than that indicated in the following table:

Standard size inch

(millimeter)

Nominal O.D. inch

(millimeter)

Wall thickness inch (millimeter)

Nominal Tolerance

1/2 (13) 5/8 (16) 3/4 (19) 1 (25) 1 1/4 (32) 1 1/2 (38)

.625 (16) .750 (19) .875 (22) 1.125 (29) 1.375 (35) 1.625 (41)

.040 (1.06) .042 (1.07) .045 (1.14) .050 (1.27) .055 (1.40) .060 (1.52)

.0035 (.0889) .0035 (.0889) .0040 (.1020) .0040 (.1020) .0045 (.1143) .0045 (.1143)

(c) Copper pipe used in mains and service lines may not be used at pressures in excess of 100 p.s.i. (689 kPa) gage. (d) Copper pipe that does not have an internal corrosion resistant lining may not be used to carry gas that has an average hydrogen sulfide content of more than 0.3 grains/100 ft3 (6.9/m3) under standard conditions. Standard conditions refers to 60 oF and 14.7 psia (15.6 oC and one atmosphere) of gas. [Amdt. 192-62, 54 FR 5625, Feb. 6, 1989; Amdt. 192-85, 63 FR 37500, July 13, 1998]

GUIDE MATERIAL See §192.377 for additional requirement regarding copper service lines.



GPTC GUIDE FOR GAS TRANSMISSION AND §192.515 DISTRIBUTION PIPING SYSTEMS: 2009 Edition SUBPART J


2.2 Tests in excess of 50 percent SMYS. When the test will result in hoop stresses in excess of 50 percent of SMYS, particularly in uprating

facilities, each operator should consider the following precautionary measures to ensure that the test area is kept clear of persons not directly engaged in the testing operation.

(a) Placing caution signs or barriers along the pipeline route wherever deemed appropriate, such as at roads and public corridors. These should be supplemented by security patrols or guards or both in residential areas, industrial areas and at river crossings.

(b) Aerial surveillance of the pipeline route, when practical, to monitor activity in the test area when testing with natural gas, inert gas or air.

(c) Notifying parties located in the general vicinity of the pipeline to avoid the test area during the period of the test.

(d) Notifying law enforcement agencies, fire departments, state and county highway departments, railroad and utility companies with facilities in the test area and, as applicable, airport operators regarding the scope and period of the test.

(e) When the test is being conducted in high exposure areas, consideration should be given to the following.

(1) Scheduling the test at a time to minimize public exposure. (2) Limiting the length of the test section to minimize potential hazards. 2.3 Tests in excess of 90 percent SMYS. When the test pressure will produce a hoop stress in excess of 90 percent of SMYS, the following

additional precautions may be considered to minimize the risk to occupants of buildings in close proximity to the pipeline.

(a) Using pre-tested pipe. (b) Pre-testing the segment. (c) Using energy absorbing devices (e.g., sandbag barriers, backfill, piling, and walls). 3 HAZARDS ASSOCIATED WITH FILLING AND DEWATERING PIPELINES FOR HYDROSTATIC

TESTING (a) During the filling and dewatering processes, significant and sudden variations in pressure may occur

within the pipeline and the temporary filling and dewatering piping. These variations can be caused by changes in velocity of the pig passing through bends in the pipeline or of the pig and water due to changes in pipeline elevation. Compressed air escaping around a pig can also create a source for stored energy within the pipeline. The release of this stored energy, as well as surges transferred from the pipeline to the temporary filling and dewatering piping, can result in pipe movement.

(b) When conducting a hydrostatic test, the following should be considered when filling and dewatering pipelines.

(1) Prepare a detailed test plan that includes the required equipment, test duration, and test pressure.

(2) Conduct training for the individuals involved with the test that includes a review of the test and dewatering plan, instructions on the filling/dewatering system installation and techniques, and proper coupling and anchoring methods.

(3) Perform an engineering analysis of the existing and temporary piping systems to identify the forces that could adversely affect the integrity of the pipeline, the integrity of temporary fill piping, or the integrity and stability of the drainage components, such as excessive or variable pressures caused by a stuck pig or leaks. An engineering analysis may consist of the following.

(i) Designing the temporary piping system within the parameters of the hydrostatic pressure test. Consider factors such as the diameter and pressure rating of the temporary piping system (including couplings and fittings), the joining method, and the piping geometry.

(ii) Accounting for hydrostatic head pressure caused by changes in elevation. (iii) Considering pressure variations or thrust due to changes in direction at bends, elbows,

and dead-ends. (iv) Determining the proper joining method for the temporary piping system.



GPTC GUIDE FOR GAS TRANSMISSION AND §192.515 DISTRIBUTION PIPING SYSTEMS: 2009 Edition SUBPART J


(4) Develop installation techniques that address forces expected during the filling, testing, and dewatering operations. Those techniques would include effective anchoring systems that prevent pipe movement, separation, or whipping. Piping components (e.g., couplings, flanges, valves) should be free of damage and installed in accordance with manufacturer’s instructions.

(5) Inspect temporary pipe, couplings, and fittings to ensure they are in good condition and rated for the pressure and temperature conditions specified for the test.

(6) Ensure that anchoring and support systems are installed in accordance with the plan. (7) Control access to the area around the test site by establishing a limited-access zone to keep out

persons not involved with the test. (c) For additional background information on this subject, see OPS Advisory Bulletin ADB-04-01 (69 FR

58225, Sept. 29, 2004; reference Guide Material Appendix G-192-1, Section 2). 4 ENVIRONMENTAL CONSIDERATIONS Each operator, in fulfilling the local, state, and federal environmental regulations with respect to the

disposal of the test medium, should, among other things, give consideration to the following. (a) Selecting water from satisfactory sources. (b) Mitigating erosion and flooding of the area where the water is being discharged. (c) Using filters, impoundment facilities or other appropriate methods to ensure that the atmosphere

and the surface waters are not unnecessarily contaminated by the products being discharged. (d) Using silencers, during the blowdown operation, where sound might be generated which is

objectionable to area residents. (e) Scheduling and locating the blowdown to minimize public objection to the noise generated.

§192.517 Records.


(a) Each operator shall make, and retain for the useful life of the pipeline, a record of each test performed under §§192.505 and 192.507. The record must contain at least the following information: (1) The operator's name, the name of the operator's employee responsible for making the test, and the name of any test company used. (2) Test medium used. (3) Test pressure. (4) Test duration. (5) Pressure recording charts, or other record of pressure readings. (6) Elevation variations, whenever significant for the particular test. (7) Leaks and failures noted and their disposition. (b) Each operator must maintain a record of each test required by §§192.509, 192.511, and 192.513 for at least 5 years. [Amdt. 192-93, 68 FR 53895, Sept. 15, 2003]



GPTC GUIDE FOR GAS TRANSMISSION AND §192.629 DISTRIBUTION PIPING SYSTEMS: 2009 Edition SUBPART L

Addendum 7, July 2011 268(a)

§192.629 Purging of pipelines.


(a) When a pipeline is being purged of air by use of gas, the gas must be released into one end of the line in a moderately rapid and continuous flow. If gas cannot be supplied in sufficient quantity to prevent the formation of a hazardous mixture of gas and air, a slug of inert gas must be released into the line before the gas. (b) When a pipeline is being purged of gas by use of air, the air must be released into one end of the line in a moderately rapid and continuous flow. If air cannot be supplied in sufficient quantity to prevent the formation of a hazardous mixture of gas and air, a slug of inert gas must be released into the line before the air.

GUIDE MATERIAL 1 REFERENCE AGA XK0101, “Purging Principles and Practice.” 2 NOTIFICATIONS For notification of public officials and the public in the vicinity of purge or discharge, see 4 of the guide

material under §192.751.

§192.631 Control room management.

▌[Effective Date: 08/15/11]

(a) General. (1) This section applies to each operator of a pipeline facility with a controller working in a control room who monitors and controls all or part of a pipeline facility through a SCADA system. Each operator must have and follow written control room management procedures that implement the requirements of this section, except that for each control room where an operator’s activities are limited to either or both of: (i) Distribution with less than 250,000 services, or (ii) Transmission without a compressor station, the operator must have and follow written procedures that implement only paragraphs (d) (regarding fatigue), (i) (regarding compliance validation), and (j) (regarding compliance and deviations) of this section. (2) The procedures required by this section must be integrated, as appropriate, with operating and emergency procedures required by §§192.605 and 192.615. An operator must develop the procedures no later than August 1, 2011, and must implement the procedures according to the following schedule. The procedures required by paragraphs (b), (c)(5), (d)(2) and (d)(3), (f) and (g) of this section must be implemented no later than October 1, 2011. The procedures required by paragraphs (c)(1) through (4), (d)(1), (d)(4), and (e) must be implemented no later than August 1, 2012. The training procedures required by paragraph (h) must be implemented no later than August 1, 2012, except that any training required by another paragraph of this section must be implemented no later than the deadline for that paragraph. (b) Roles and responsibilities. Each operator must define the roles and responsibilities of a





controller during normal, abnormal, and emergency operating conditions. To provide for a controller’s prompt and appropriate response to operating conditions, an operator must define each of the following: (1) A controller’s authority and responsibility to make decisions and take actions during normal operations; (2) A controller’s role when an abnormal operating condition is detected, even if the controller is not the first to detect the condition, including the controller’s responsibility to take specific actions and to communicate with others; (3) A controller’s role during an emergency, even if the controller is not the first to detect the emergency, including the controller’s responsibility to take specific actions and to communicate with others; and (4) A method of recording controller shift-changes and any hand-over of responsibility between controllers. (c) Provide adequate information. Each operator must provide its controllers with the information, tools, processes and procedures necessary for the controllers to carry out the roles and responsibilities the operator has defined by performing each of the following: (1) Implement sections 1, 4, 8, 9, 11.1, and 11.3 of API RP 1165 (incorporated by reference, see §192.7) whenever a SCADA system is added, expanded or replaced, unless the operator demonstrates that certain provisions of sections 1, 4, 8, 9, 11.1, and 11.3 of API RP 1165 are not practical for the SCADA system used; (2) Conduct a point-to-point verification between SCADA displays and related field equipment when field equipment is added or moved and when other changes that affect pipeline safety are made to field equipment or SCADA displays; (3) Test and verify an internal communication plan to provide adequate means for manual operation of the pipeline safely, at least once each calendar year, but at intervals not to exceed 15 months; (4) Test any backup SCADA systems at least once each calendar year, but at intervals not to exceed 15 months; and (5) Establish and implement procedures for when a different controller assumes responsibility, including the content of information to be exchanged. (d) Fatigue mitigation. Each operator must implement the following methods to reduce the risk associated with controller fatigue that could inhibit a controller’s ability to carry out the roles and responsibilities the operator has defined: (1) Establish shift lengths and schedule rotations that provide controllers off-duty time sufficient to achieve eight hours of continuous sleep; (2) Educate controllers and supervisors in fatigue mitigation strategies and how off-duty activities contribute to fatigue; (3) Train controllers and supervisors to recognize the effects of fatigue; and (4) Establish a maximum limit on controller hours-of-service, which may provide for an emergency deviation from the maximum limit if necessary for the safe operation of a pipeline facility. (e) Alarm management. Each operator using a SCADA system must have a written alarm management plan to provide for effective controller response to alarms. An operator’s plan must include provisions to: (1) Review SCADA safety-related alarm operations using a process that ensures alarms are accurate and support safe pipeline operations; (2) Identify at least once each calendar month points affecting safety that have been taken off scan in the SCADA host, have had alarms inhibited, generated false alarms, or that have had forced or manual values for periods of time exceeding that required for associated maintenance or operating activities; (3) Verify the correct safety-related alarm set-point values and alarm descriptions at least once each calendar year, but at intervals not to exceed 15 months; (4) Review the alarm management plan required by this paragraph at least once each calendar year, but at intervals not exceeding 15 months, to determine the effectiveness of the




Addendum 7, July 2011 268(c)

plan; (5) Monitor the content and volume of general activity being directed to and required of each controller at least once each calendar year, but at intervals not to exceed 15 months, that will assure controllers have sufficient time to analyze and react to incoming alarms; and (6) Address deficiencies identified through the implementation of paragraphs (e)(1) through (e)(5) of this section. (f) Change management. Each operator must assure that changes that could affect control room operations are coordinated with the control room personnel by performing each of the following: (1) Establish communications between control room representatives, operator’s management, and associated field personnel when planning and implementing physical changes to pipeline equipment or configuration; (2) Require its field personnel to contact the control room when emergency conditions exist and when making field changes that affect control room operations; and (3) Seek control room or control room management participation in planning prior to implementation of significant pipeline hydraulic or configuration changes. (g) Operating experience. Each operator must assure that lessons learned from its operating experience are incorporated, as appropriate, into its control room management procedures by performing each of the following: (1) Review incidents that must be reported pursuant to 49 CFR part 191 to determine if control room actions contributed to the event and, if so, correct, where necessary, deficiencies related to: (i) Controller fatigue; (ii) Field equipment; (iii) The operation of any relief device; (iv) Procedures; (v) SCADA system configuration; and (vi) SCADA system performance. (2) Include lessons learned from the operator’s experience in the training program required by this section. (h) Training. Each operator must establish a controller training program and review the training program content to identify potential improvements at least once each calendar year, but at intervals not to exceed 15 months. An operator’s program must provide for training each controller to carry out the roles and responsibilities defined by the operator. In addition, the training program must include the following elements: (1) Responding to abnormal operating conditions likely to occur simultaneously or in sequence; (2) Use of a computerized simulator or non-computerized (tabletop) method for training controllers to recognize abnormal operating conditions; (3) Training controllers on their responsibilities for communication under the operator’s emergency response procedures; (4) Training that will provide a controller a working knowledge of the pipeline system, especially during the development of abnormal operating conditions; and (5) For pipeline operating setups that are periodically, but infrequently used, providing an opportunity for controllers to review relevant procedures in advance of their application. (i) Compliance validation. Upon request, operators must submit their procedures to PHMSA or, in the case of an intrastate pipeline facility regulated by a State, to the appropriate State agency. (j) Compliance and deviations. An operator must maintain for review during inspection: (1) Records that demonstrate compliance with the requirements of this section; and (2) Documentation to demonstrate that any deviation from the procedures required by this section was necessary for the safe operation of a pipeline facility.




Addendum 7, July 2011 268(d)

[Issued by Amdt. 192-112, 74 FR 63310, Dec. 3, 2009 with Amdt. 192-112 Correction, 75 FR 5536, Feb. 3, 2010; Amdt. 192-117, 76 FR 35130, June 16, 2011]

GUIDE MATERIAL

No guide material available at present.



GPTC GUIDE FOR GAS TRANSMISSION AND §192.711 DISTRIBUTION PIPING SYSTEMS: 2009 Edition SUBPART M


GUIDE MATERIAL (a) Prior to permanent mechanical or welded repair of a steel pipeline operating at greater than 20% SMYS,

the operator should determine the thickness and integrity of the pipe wall by ultrasonic or other means. Where deterioration or lamination is found, steps should be taken to ensure a safe repair.

(b) See guide material under §§192.703, 192.713, 192.751, and 192.933.

§192.713 Transmission lines: Permanent field repair of imperfections and damages.


(a) Each imperfection or damage that impairs the serviceability of pipe in a steel transmission line operating at or above 40 percent of SMYS must be -- (1) Removed by cutting out and replacing a cylindrical piece of pipe; or (2) Repaired by a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe. (b) Operating pressure must be at a safe level during repair operations. [Amdt. 192-27, 41 FR 34598, Aug. 16, 1976; Amdt. 192-88, 64 FR 69660, Dec. 14, 1999]

GUIDE MATERIAL 1 GENERAL 1.1 Welding. (a) Appropriate procedures for welding on pipelines in service should be used. Some important factors

to be considered in these procedures are the use of a low-hydrogen welding process, the welding sequence, the effect of wall thickness and heat input, and the quenching effect of the gas flow.

(b) Welding should be done only on sound metal far enough from the defect so that the localized heating will not have an adverse effect on the defect. The soundness of the metal may be determined by visual and other nondestructive inspection.

(c) A reference is API Std 1104, "Welding of Pipelines and Related Facilities", Appendix B, "In-Service Welding."

1.2 Additional precautions. (a) Care should be taken in excavating around the pipe so that it is not damaged. (b) Pounding on the pipe (e.g., to remove corrosion products or pipe coating, or to improve the fit of the

sleeve) should be avoided. 1.3 Reliable engineering tests and analyses. See guide material under §192.485. 2 REPLACEMENT (§192.713(a)(1)) The operator should consider the possibility that some degree of impairment may have occurred beyond

the area of immediate concern. The impairment may be due to a defect in the longitudinal weld, external or internal corrosion, or damage by excavating equipment at another location when excavation work covers a large area. The pipe on each side of the known impairment should be examined to determine the extent of the replacement.




278

3 REPAIR (§192.713(a)(2)) 3.1 General. (a) The use of an appropriately designed full-encirclement split sleeve is recognized as an acceptable

repair method. Other methods, including the use of composite reinforced sleeve material, may also be available. However, operators are cautioned that not all repair methods are suitable for permanent repair of leaking or through-wall defects. Review the manufacturer’s installation requirements before deciding to use a composite sleeve to make permanent repair. The repair method selected should:

(1) Have or achieve a strength at least equal to that required for the MAOP of the pipe being repaired, and

(2) Be capable of withstanding the anticipated circumferential and longitudinal stresses, including additional stress due to external loading.

(b) In determining the length of the repair, the operator should consider that: (1) Some degree of impairment might have occurred beyond the area of immediate concern (see 2

above), and (2) Full-encirclement sleeves should not be less than 4 inches in length. (c) A wide variety of repair methods has been used successfully in the natural gas pipeline industry.

Sleeves may be used to reduce the stress in, or reinforce, a pipe defect that is not leaking, or to repair a leaking defect. It is important that any repair method or sleeve be carefully designed and tested to ensure its reliability for the conditions of installation.

3.2 Fillet welds. Fillet welds on pressurized carrier piping are prone to cracking due to the extreme cooling action.

Examination of completed welds by radiographic or ultrasonic means may not detect such cracking due to the geometry of the fillet weld. Therefore, the following is recommended.

(a) Use of low-hydrogen welding processing; (b) Employment of multi-pass welding techniques with visual examination after each pass; and (c) If visual examination indicates further nondestructive inspection is necessary, either magnetic

particle or liquid penetrant inspection may be used. 3.3 Design considerations for repair sleeves. A reference for one set of sleeve designs is PRCI L22279, "Further Studies of Two Methods for

Repairing Defects in Line Pipe." For evaluating other available designs or developing new designs, consider the following factors. (a) All sleeves should be designed for strength at least equal to the maximum allowable operating

pressure of the repaired pipe. (b) Sleeves should not be less than 4 inches in length. In determining the length of a sleeve, the

operator should consider that some degree of impairment may have occurred beyond the immediate area. See 2 above.

(c) The use of a low hydrogen welding procedure for longitudinal and circumferential welds. The integrity of these welds is affected by heat dissipation due to gas flow through the line and extra metal mass adjacent to the weld.

Circumferential welds at the sleeve ends are required when repairing a leaking defect. However,

end welds may or may not be beneficial for a non-leaking defect. If end welds are used on a non-leaking defect, consideration should be given to equalizing the pressure across the defect. One way to do this is by tapping the carrier pipe in order to connect the annular space between the carrier pipe and the sleeve to the pressure inside the carrier pipe.

(d) Sealing the ends of non-pressure containing sleeves, possibly by means other than welding, to prevent corrosion in the annular space between the carrier pipe and the sleeve.





(e) The capacity of end welds to withstand all anticipated circumferential and longitudinal stresses, including external forces. Special attention should be given to stresses resulting from unusually long sleeves or sleeves subject to bending stresses.

4 REPAIR PRESSURE (§192.713(b)) 4.1 General. In establishing a safe level of pressure in a pipeline that is to remain in service during repair operations,

the primary consideration is the severity of the defect to be repaired. This includes consideration of both depth and geometry (i.e., the amount of stress concentration, such as in sharp-bottomed gouges). Severe defects should not be repaired under pressure unless the operator has sufficient experience to make a sound evaluation of the defect. In addition, the effect of any known secondary stresses should be considered.

4.2 Special consideration. While welding reinforcements directly to pressurized pipe has been done successfully at higher stress

levels, the following formula describes a recommended maximum pressure for this procedure.

PS t

D=

−2 332 0 72)( )( .

Where: P = Internal pressure, psig S = Specified minimum yield strength, psi t = Nominal pipe wall thickness, inches D = Nominal outside diameter, inches

§192.715 Transmission lines: Permanent field repair of welds.


Each weld that is unacceptable under §192.241(c) must be repaired as follows: (a) If it is feasible to take the segment of transmission line out of service, the weld must be repaired in accordance with the applicable requirements of §192.245. (b) A weld may be repaired in accordance with §192.245 while the segment of transmission line is in service if: (1) The weld is not leaking; (2) The pressure in the segment is reduced so that it does not produce a stress that is more than 20 percent of the SMYS of the pipe; and (3) Grinding of the defective area can be limited so that at least 1/8 inch (3.2 millimeters) thickness in the pipe weld remains. (c) A defective weld which cannot be repaired in accordance with paragraph (a) or (b) of this section must be repaired by installing a full encirclement welded split sleeve of appropriate design. [Amdt. 192-85, 63 FR 37500, July 13, 1998]

GUIDE MATERIAL See guide material under §192.713 regarding repair sleeves.





§192.717 Transmission lines: Permanent field repair of leaks.


Each permanent field repair of a leak on a transmission line must be made by -- (a) Removing the leak by cutting out and replacing a cylindrical piece of pipe; or (b) Repairing the leak by one of the following methods: (1) Install a full encirclement welded split sleeve of appropriate design, unless the transmission line is joined by mechanical couplings and operates at less than 40 percent of SMYS. (2) If the leak is due to a corrosion pit, install a properly designed bolt-on-leak clamp. (3) If the leak is due to a corrosion pit and on pipe of not more than 40,000 p.s.i. (276 MPa) gage SMYS, fillet weld over the pitted area a steel plate patch with rounded corners, of the same or greater thickness than the pipe, and not more than one-half of the diameter of the pipe in size. (4) If the leak is on a submerged offshore pipeline or submerged pipeline in inland navigable waters, mechanically apply a full encirclement split sleeve of appropriate design. (5) Apply a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe. [Amdt. 192-11, 37 FR 21816, Oct. 14, 1972; Amdt. 192-27, 41 FR 34598, Aug. 16, 1976; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-88, 64 FR 69660, Dec. 14, 1999]

GUIDE MATERIAL (a) For information regarding replacement and repair sleeves, see 2 and 3 of the guide material under

§192.713. (b) For information regarding reliable engineering tests and analyses, see guide material under §192.485. (c) For information regarding scheduling integrity management repairs, see 2 of the guide material under

§192.933.

§192.719 Transmission lines: Testing of repairs.


(a) Testing of replacement pipe. If a segment of transmission line is repaired by cutting out the damaged portion of the pipe as a cylinder, the replacement pipe must be tested to the pressure required for a new line installed in the same location. This test may be made on the pipe before it is installed. (b) Testing of repairs made by welding. Each repair made by welding in accordance with §§192.713, 192.715, and 192.717 must be examined in accordance with §192.241. [Amdt. 192-54, 51 FR 41634, Nov. 18, 1986]

GUIDE MATERIAL When tie-in girth welds are not strength tested, they should be nondestructively tested in accordance with §192.241.



GPTC GUIDE FOR GAS TRANSMISSION AND §192.907 DISTRIBUTION PIPING SYSTEMS: 2009 Edition SUBPART O


§192.907 What must an operator do to implement this subpart?


(a) General. No later than December 17, 2004, an operator of a covered pipeline segment must develop and follow a written integrity management program that contains all the elements described in §192.911 and that addresses the risks on each covered transmission pipeline segment. The initial integrity management program must consist, at a minimum, of a framework that describes the process for implementing each program element, how relevant decisions will be made and by whom, a time line for completing the work to implement the program element, and how information gained from experience will be continuously incorporated into the program. The framework will evolve into a more detailed and comprehensive program. An operator must make continual improvements to the program. (b) Implementation Standards. In carrying out this subpart, an operator must follow the requirements of this subpart and of ASME/ANSI B31.8S (incorporated by reference, see §192.7) and its appendices, where specified. An operator may follow an equivalent standard or practice only when the operator demonstrates the alternative standard or practice provides an equivalent level of safety to the public and property. In the event of a conflict between this subpart and ASME/ANSI B31.8S, the requirements in this subpart control. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan. 15, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006]

GUIDE MATERIAL

1 WRITTEN PROGRAM 1.1 General.

A written program provides a road map for assessment, integration and analysis of data, and courses of action available in managing pipeline integrity. The program can incorporate or reference existing policies and procedures that may address the elements listed in §192.911. The operator should consider conducting a gap analysis between current policies and procedures and the requirements of Subpart O to determine if additional plans, processes, or procedures may be required.

1.2 Development. The operator should consider the following when developing its Integrity Management Program (IMP). (a) Existing O&M procedures. (b) Existing management systems (e.g., quality assurance and management of change). (c) Existing environmental and safety programs. (d) “FAQs” from the PHMSA-OPS website at http://primis.phmsa.dot.gov/gasimp/faqlist.gim. (e) “Inspection Protocols” from the PHMSA-OPS website at http://primis.phmsa.dot.gov/gasimp/prolist.gim. (f) Process “Flowcharts” from the PHMSA-OPS website at http://primis.phmsa.dot.gov/gasimp/. 1.3 References. (a) “Pipeline Risk Management Manual,” W. Kent Muhlbauer, Gulf Professional Publishing, ISBN: 0-7506-7579-9. (b) GPTC-Z380-TR-1, “Review of Integrity Management for Natural Gas Transmission Pipelines,” an

ANSI Technical Report by GPTC (AGA Catalog Number X69806).





2 OPERATORS WITH NO HCAs

Operators that have determined that there are no HCAs should document how that determination was made. The operator must develop a written process for identifying new HCAs. See guide material under §192.905. If HCAs are subsequently discovered, the operator is required to develop an IMP.

3 INCORPORATION BY REFERENCE 3.1 General. Subpart O requires use of the following documents, which are incorporated by reference in §192.7. (a) ASME B31.8S, “Supplement to B31.8 on Managing System Integrity of Gas Pipelines.” (b) NACE SP0502, “Pipeline External Corrosion Direct Assessment Methodology.” An operator must meet the requirements of Subpart O and the referenced sections of these

documents. In the event of a conflict between ASME B31.8S and NACE SP0502, the more stringent requirement should be followed.

3.2 ASME B31.8S. (a) This standard contains non-mandatory “should” statements. The operator should evaluate each

of these and take appropriate action. The operator may choose alternative practices; however, the operator should document the justification for doing so. Considerations might include the following.

(1) Acceptable levels of safety and integrity. (2) Appropriateness to conditions. (3) Technological improvements. (b) Appendices A and B2 of this standard are titled as “non-mandatory”; however, the requirements

of these appendices are mandatory because Subpart O specifically incorporates them. (c) “Must” and “shall” statements in this standard are mandatory. (d) References in Subpart O to ASME B31.8S are listed below in Table 192.907i.

SUMMARY OF INCORPORATED REFERENCES TO ASME B31.8S

ASME B31.8S Subpart O References

General §§192.907(b); 192.911; 192.913(a), (b)(1), & (c); 192.935(b)(1)(iv)

Section 2 §192.917(a)

Section 3.2 §192.903 - definition of potential impact radius

Section 4 §192.917(b) & (d)

Section 5 §§192.917(c) & (d); 192.921(a)(2); 192.935(a); 192.937(c)(2); 192.939(a)(1)(ii) & (a)(3)

Section 6.2 §§192.921(a)(1); 192.937(c)(1)

Section 6.4 §§192.923(b)(1) & (b)(2); 192.925(b), (b)(1), (b)(2), (b)(3), & (b)(4); 192.927(b)

Section 7 §192.933(c) & (d)(1)

Section 9 §192.911(i)

Section 9.4 §192.945(a)

Section 10 §192.911(m)





(3) Direct examination. In addition to the requirements in ASME/ANSI B31.8S section 6.4 and NACE SP0502–2008, section 5, the plan’s procedures for direct examination of indications from the indirect examination must include — (i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a covered segment; (ii) Criteria for deciding what action should be taken if either: (A) Corrosion defects are discovered that exceed allowable limits (Section 5.5.2.2 of NACE SP0502–2008), or (B) Root cause analysis reveals conditions for which ECDA is not suitable (Section 5.6.2 of NACE SP0502–2008); (iii) Criteria and notification procedures for any changes in the ECDA Plan, including changes that affect the severity classification, the priority of direct examination, and the time frame for direct examination of indications; and (iv) Criteria that describe how and on what basis an operator will reclassify and reprioritize any of the provisions that are specified in section 5.9 of NACE SP0502–2008. (4) Post assessment and continuing evaluation. In addition to the requirements in ASME/ANSI B31.8S section 6.4 and NACE SP0502–2008, section 6, the plan’s procedures for post assessment of the effectiveness of the ECDA process must include — (i) Measures for evaluating the long-term effectiveness of ECDA in addressing external corrosion in covered segments; and (ii) Criteria for evaluating whether conditions discovered by direct examination of indications in each ECDA region indicate a need for reassessment of the covered segment at an interval less than that specified in §192.939. (See Appendix D of NACE SP0502–2008.) [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan. 15, 2004, Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004 and Amdt. 192-95 Correction, 69 FR 29903, May 26, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006; Amdt. 192-114, 75 FR 48593, Aug. 11, 2010]

GUIDE MATERIAL Note:

All references to NACE throughout this section of guide material are specifically to NACE SP0502-2008 as incorporated by reference in §192.7. (NACE SP0505-2008 is the reaffirmed RP0502-2002.) Example: An abbreviated NACE 5.2.1 means NACE SP0502-2008, Paragraph 5.2.1. In all cases, the NACE referenced materials shall be consulted as per the Regulations.

1 PURPOSE External Corrosion Direct Assessment (ECDA) is a methodology to assess the integrity of pipe and pipe

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

2 GENERAL REQUIREMENTS (a) A written ECDA plan is required to be based on the following. (1) Section 192.925. (2) ASME B31.8S, Section 6.4. (3) NACE SP0502. (b) The ECDA plan should include its purpose, objectives, and instructions to personnel. (c) Written procedures are required to address the following four process steps (see §192.925(b)). (1) Pre-assessment. (2) Indirect examination (inspection). (3) Direct examination.





(4) Post-assessment and continuing evaluation. (d) Section 192.947(d) requires documents to support decisions, analyses, and processes developed

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

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

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

Note: It is required that operators using ECDA develop and implement a direct assessment plan

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

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

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

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

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

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

Category Examples of Critical Data Elements

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

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

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

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

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

TABLE 192.925i





NUMBER OF DIRECT EXAMINATIONS REQUIRED BY NACE SP0502

When ECDA is Being Applied for the First Time in the Segment

With Identified Indications No Identified Indications Immediate Action Scheduled Action Monitoring

All indications that are prioritized as immediate require direct examination. (NACE(1) 5.10.2.1)

If no immediate indications in region, then perform excavations on the 2 most severe scheduled indications in each region. (NACE(1) 5.10.2.2.1)

If an ECDA region contains only monitored indications (i.e., no immediate or scheduled indications), 2 excavations are required at the indications most likely to have corrosion. (NACE(1) 5.10.2.3.1)

In the region identified as most likely for corrosion, from the Pre-Assessment Step, perform at least 2 excavations at locations identified as the most likely to have corrosion. (NACE(1) 5.10.1 and 5.10.1.2)

For indications that were reprioritized from immediate to scheduled, follow the scheduled guidelines in the next column. (NACE(1) 5.10.2.1.1)

If an ECDA region contains scheduled indications and 1 or more immediate indications, then perform 2 excavations on the most severe scheduled indications in the region. (NACE(1) 5.10.2.2.2)

If the results of the excavation at a scheduled indication show corrosion that is deeper than 20% of the original wall thickness and that is deeper or more severe than at an immediate indication, then do at least 2 more direct examinations (i.e., the indications with next highest priority). (NACE(1) 5.10.2.2.3)

Process Validation Dig: Perform at least 2 additional direct examinations on the pipeline segment (NACE(1) 6.4.2.1). The direct examinations shall be conducted at randomly selected locations, one of which is categorized as scheduled (or monitored if no scheduled indications exist) and one in an area where no indication was detected. These digs must occur within an HCA. (1) All NACE references are to paragraphs in NACE SP0502-2008.

TABLE 192.925ii





NUMBER OF DIRECT EXAMINATIONS REQUIRED BY NACE SP0502

When ECDA is Being Applied a Second or Subsequent Time on the Segment

With Identified Indications No Identified Indications Immediate Action Scheduled Action Monitoring

All indications that are prioritized as immediate require direct examination. (NACE(1) 5.10.2.1)

If no immediate indications in region, then perform 1 excavation on the most severe scheduled indication in the region. (NACE(1) 5.10.2.2.1)

If an ECDA region contains only monitored indications (i.e., no immediate or scheduled indications), 1 excavation is required at the indication most likely to have corrosion. (NACE(1) 5.10.2.3.1)

In the region identified as most likely for corrosion, from the Pre-Assessment Step, perform at least 1 excavation at the location identified as the most likely to have corrosion. (NACE(1) 5.10.1 & 5.10.1.2)

For indications that were reprioritized from immediate to scheduled, follow the scheduled guidelines in the next column. (NACE(1) 5.10.2.1.1)

If an ECDA region contains scheduled indications and 1 or more immediate indications, then perform 1 excavation on the most severe scheduled indication in the region. (NACE(1) 5.10.2.2.2)

If the result of the excavation at a scheduled indication show corrosion that is deeper than 20% of the original wall thickness and that is deeper or more severe than at an immediate indication, then do at least 1 more direct examination (i.e., the indication with next highest priority). (NACE(1) 5.10.2.2.3)

Process Validation Dig: Perform at least 1 additional direct examination at a random location within an HCA where no indications were detected in only one region in the segment (NACE 6.4.2). (1) All NACE references are to paragraphs in NACE SP0502-2008.

TABLE 192.925iii




Addendum 5, November 2010 356(a)

Following are three examples where a pipeline segment contains two HCAs (HCA 1 and HCA 2). There are two ECDA regions (R1 and R2) with Region 2 being the most likely to have corrosion. In these examples, no corrosion defects are found that are deeper than 20% of the original wall thickness and that are deeper or more severe than at an immediate indication (NACE 5.10.2.2.3). These examples assume that the results of the direct examinations do not require the need to reprioritize the severity classification (NACE 5.9).

Indirect inspections conducted over the HCAs. The examples note the number of indications as a result

of integrating the inspection data. Example 1 is a pipeline segment with no indications. Example 2 is a pipeline segment with scheduled and monitored indications but no immediate indications. Example 3 is a pipeline segment with immediate, scheduled, and monitored indications.

DIAGRAM FOR EXAMPLES 1 THROUGH 3 Pipe Segment showing 2 HCAs and 2 Regions

Pipeline Segment A-B

B A

FIGURE 192.925A

HCA 1

HCA 2

R1

R1

R2

R2





The following three tables show the number of direct examinations necessary to meet the requirements of §192.925 and NACE SP0502 for each example.

EXAMPLE 1: PIPELINE SEGMENT WITH NO INDICATIONS

Number of Indications Number of Direct Examinations Additional

Examinations for First-Time ECDA

Tota

l Exa

min

atio

ns

(Firs

t Tim

e)

Prio

rity

HCA 1 HCA 2 P

riorit

y

Step 3 Direct Exam

Step 4 Validation

Tota

l Step

3

Step

4

Tota

l Add

ition

al

HCA 1 HCA 2 Any HCA

R1 R2 R1 R2 R1 R2 R1 R2 Any Region

R2 Any HCA

Any Region

Any HCA

I 0 0 0 0 I 0 0 0 0 0 0 0 0 0 0 S 0 0 0 0 S 0 0 0 0 0 0 0 0 0 0 M 0 0 0 0 M 0 0 0 0 0 0 0 0 0 0

NI 0 1A 0 0 1B 2 1C 1D 2 4 Total Examinations

(If not first time) 2

Total Additional

2

4

(A) If there are no indications, NACE(1) 5.10.1 requires 1 excavation in the region identified as most likely for corrosion (for this example R2 was chosen). (B) For process validation, NACE(1) 6.4.2 requires a second dig, which can be in any region or any HCA. (C) For first-time ECDA, NACE(1) 5.10.1 requires an additional dig in R2, and (D) NACE(1) 6.4.2 requires an additional validation dig which can be in any region.

I = Immediate Priority:

S = Schedule M = Monitored NI = No Indications (1) All NACE references are to paragraphs in NACE SP0502-2008.

TABLE 192.925iv




Addendum 7, July 2011 356(c)

EXAMPLE 2: PIPELINE SEGMENT WITH SCHEDULED AND MONITORED INDICATIONS

(NO IMMEDIATE INDICATIONS)

Number of Indications Number of Direct Examinations Additional Examinations for First-Time ECDA

Tota

l Exa

min

atio

ns

(Firs

t Tim

e)

Prio

rity HCA 1 HCA 2

Prio

rity

Step 3

Direct Exam

Step 4

Validation

Tota

l Step

3

Step

3

Step

4

Tota

l Add

ition

al

HCA 1 HCA 2 Any HCA HCA 1

HCA 2

Any HCA

R1 R2 R1 R2 R1 R2 R1 R2 Any Region R1 R2

I 0 0 0 0 I 0 0 0 0 0 0 0 0 0 0 0 S 2 4 1 2 S 0 1A 1A 0 0 2 1C 1C 1D 3 5 M 6 9 7 9 M 0 0 0 0 0 0 0 0 0 0 0

NI 0 0 0 0 1B 1 0 0 0 0 1 Total Examinations

(If not first time) 3 Total Additional 3 6

(A) Identifies the most severe scheduled defect in the Region. If there are no immediate indications, NACE(1) 5.10.2.2 requires that the most severe scheduled indication in each region be examined. (B) For process validation, NACE(1) 6.4.2 requires a dig in a randomly selected location, which can be in any region within any HCA. (C) For first-time ECDA, NACE(1) 5.10.2.2 requires an additional examination of the next most severe scheduled indication in each region. (D) NACE(1) 6.4.2 requires a second validation dig.



TABLE 192.925v




Addendum 7, July 2011 356(d)

EXAMPLE 3: PIPELINE SEGMENT WITH IMMEDIATE, SCHEDULED, AND MONITORED INDICATIONS

Number of Indications Number of Direct Examinations Additional Examinations for First-Time ECDA

Tota

l Exa

min

atio

ns

(Firs

t Tim

e)

Prio

rity HCA 1 HCA 2

Prio

rity

Step 3

Direct Exam

Step 4

Validation

Tota

l Ste

p 3

Ste

p 3

Ste

p 4

Tota

l Add

ition

al

HCA 1 HCA 2 Any HCA HCA 1

HCA 2

Any HCA

R1 R2 R1 R2 R1 R2 R1 R2 Any Region R1 R2

I 2 0 1 1 I 2 0 1 1 0 4A 0 0 0 0 4 S 2 4 1 2 S 0 1B 1B 0 0 2 1C 1C 1E 3 5 M 6 9 7 9 M 0 0 0 0 0 0 0 0 0 0 0

NI 0 0 0 0 1D 1 0 0 0 0 1 Total Examinations

(If not first time) 7 Total Additional 3 10

(A) All immediate indications need to be excavated. (NACE(1) 5.10.2.1) (B) Identify and excavate the most severe scheduled indication in each Region. (NACE(1) 5.10.2.2) (C) For first-time application, identify and excavate the next most severe scheduled indication in each Region. (NACE(1) 5.10.2.2) (D) NACE(1) 6.4.2 requires a validation dig at a randomly selected location where no indication was detected, which can be in any region within any HCA. (E) For first-time application, NACE(1) 6.4.2.1 requires an excavation at a scheduled indication (or monitored if no scheduled indications exist).



TABLE 192.925vi




Addendum 7, July 2011 356(i)

(c) Root cause. For each root cause where corrosion activity was worse than expected, indications that occur in the

pipeline segment where similar root-cause conditions exist (e.g., foreign line crossing, light rail) shall be identified and reevaluated (NACE 5.9.3).

(d) Remediation. (1) If repair and recoating or replacement is performed, the indication is no longer a threat to the

pipeline and may be removed from further consideration after completion of the root-cause analysis and the required mitigation activities.

(2) If remediation is performed other than that in paragraph (a) (e.g., increase in cathodic protection current), an indication that was initially placed in the immediate or scheduled priority category may be moved to the scheduled or monitored priority category, respectively, provided subsequent indirect inspections justify reducing the indication severity.

(3) If corrosion is found on a covered pipeline segment that could adversely affect the integrity of the line, §192.917(e)(5) requires the operator to evaluate and remediate, as necessary, all transmission pipeline segments (both covered and non-covered) having similar material coating and environmental characteristics.

(4) For non-covered segments, the operator should establish a schedule for evaluating and remediating, as necessary, the similar segments that is consistent with the operator’s O&M procedures for testing and repair of facilities under Part 192.

5.8 First-time application. When applying ECDA for the first time, §192.925(b)(3) and NACE SP0502 require the operator to

provide more stringent direct examination criteria than what is required for subsequent assessments. Provision for the more stringent criteria is required to be documented in the ECDA plan. Examples of more stringent criteria for the direct examination step include the following.

(a) Performing additional direct examinations. (b) Performing a larger excavation to inspect nearby indications. (c) Performing additional NDE testing such as magnetic particle, radiographic, or ultrasonic inspection

on suspected indications or welds. (d) Performing additional sampling such as measuring soil resistivity or measuring AC potentials. (e) Resurveying the ECDA region after immediate indications are repaired, to determine if other

indications were masked by the large indication. 6 POST-ASSESSMENT (a) Objectives. The objective of the post-assessment step is to define reassessment intervals and

assess the overall effectiveness of the ECDA process. See NACE 6.1.1. (b) Reassessment interval. As stated in NACE 6.1.3, the conservatism of the reassessment interval is

not easy to quantify because there are uncertainties in the estimates or measurements of remaining flaw sizes, maximum corrosion rates, and the periods of a year in which defects grow by corrosion. To account for these uncertainties, the assessment interval calculated during the Post-Assessment Step is based on a half-life concept. Conservative growth rates are to be combined with estimated remaining flaw sizes to calculate the true life of the defect. The reassessment interval is then set at the lower half of that value or the maximum allowed reassessment interval.

(c) Outline of post-assessment step. The post-assessment step is broken down into five activities as follows.

(1) Remaining flaw size estimation. (2) Corrosion growth rate calculation. (3) Remaining life and reassessment interval calculation. (4) Assessment of ECDA effectiveness. (5) Feedback (continuous improvement).




Addendum 4, July 2010 356(j)

6.1 Remaining flaw size estimation. (a) If no corrosion defects are found, then the remaining life is the same as a new pipe. (b) It is required to use the most severe, non-unique external corrosion defect that is found during direct

examinations of all indications to determine the remaining life for all "scheduled" indications not excavated (NACE 6.2). The most severe external corrosion may not necessarily be the one with the deepest pit but the one that results in the lowest failure pressure. The root cause analysis determines which defects are unique (e.g., corrosion from a known stray current source, third-party damage at a foreign line crossing) and which are non-unique (e.g., insufficient cathodic protection).

(c) As an alternative, a pipeline operator may substitute a different flaw size value based on a statistical or more sophisticated analysis of the excavated severities. In addition, an operator may use pre-assessment defect information from maintenance and operation excavations to improve the estimate of the maximum remaining flaw size.

6.2 Corrosion growth rate calculation. (a) The corrosion growth rate is required to be based on a sound engineering analysis (NACE 6.2.3). If

available, an operator should use actual corrosion rate information for the region. Actual corrosion rates may be determined by direct measurement of wall thickness as a function of time on the pipeline in question. An operator should review data collected in the pre-assessment records to determine if this information is available. For example, an operator has a recent measurement of pipe wall loss (e.g., from direct examination). The wall loss divided by the number of years the pipeline has been in service may provide an adequate corrosion rate.

(b) If actual corrosion rate data on the pipeline region is not available, NACE Appendix D provides guidance on other methods to estimate corrosion rates. Appendix D provides a default corrosion pitting rate of 16 mils per year (mpy) (1mil = 0.001 inch) when other data is unavailable. The 16 mpy rate can be reduced to 12 mpy if it can be shown that the CP levels of the effected pipeline regions had at least 40 mV of polarization (considering IR drop) since installation (NACE D3.3).

(c) Acceptable alternatives to estimate the corrosion rate are referenced in NACE Appendix D. This Appendix provides information on various analytical techniques such as corrosion coupon analysis, linear polarization resistance measurement, and electrical resistance probes. It also discusses the various soil and environmental factors that affect corrosion rates.

6.3 Remaining life and reassessment interval calculation. (a) NACE 6.2.4 requires the operator to use sound engineering analysis to estimate the remaining life

of the maximum remaining flaw. The operator may use the formula provided in NACE 6.2.4.1 or the following equivalent equation.

Remaining Life Equation:

Where: RL = Remaining life (years) Pf = Burst pressure RSTRENG (psig) MAOP = Maximum allowable operating pressure (psig) t = Wall thickness (inches) CR = Corrosion rate (inches/year)

yield pressure = D

tSMYS ))()(2(

SMYS = Specified minimum yield strength (psi) D = Outside diameter (inches)

)(( x 85.0CRtMAOP)P

pressureyieldRL f −=




Addendum 7, July 2011 356(m)

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

Remaining Strength of Corroded Pipe,” (RSTRENG). (b) ASME B31G, “Manual for Determining the Remaining Strength of Corroded Pipelines.” (c) NACE SP0502-2008, “Pipeline External Corrosion Direct Assessment Methodology.” (d) PHMSA-OPS Protocols, “Gas Integrity Management Inspection Manual, Inspection Protocols with

Results Forms,” specifically Section D, DA Plan. (e) GTI-04/0071, “External Corrosion Direct Assessment (ECDA) Implementation Protocol.”

§192.927 What are the requirements for using

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

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




Addendum 4, July 2010 356(n)

(2) ICDA region identification. An operator’s plan must identify where all ICDA Regions are located in the transmission system, in which covered segments are located. An ICDA Region extends from the location where liquid may first enter the pipeline and encompasses the entire area along the pipeline where internal corrosion may occur and where further evaluation is needed. An ICDA Region may encompass one or more covered segments. In the identification process, an operator must use the model in GRI 02-0057, “Internal Corrosion Direct Assessment of Gas Transmission Pipelines - Methodology,” (incorporated by reference, see §192.7). An operator may use another model if the operator demonstrates it is equivalent to the one shown in GRI 02-0057. A model must consider changes in pipe diameter, locations where gas enters a line (potential to introduce liquid) and locations down stream of gas drawoffs (where gas velocity is reduced) to define the critical pipe angle of inclination above which water film cannot be transported by the gas. (3) Identification of locations for excavation and direct examination. An operator’s plan must identify the locations where internal corrosion is most likely in each ICDA region. In the location identification process, an operator must identify a minimum of two locations for excavation within each ICDA Region within a covered segment and must perform a direct examination for internal corrosion at each location, using ultrasonic thickness measurements, radiography, or other generally accepted measurement technique. One location must be the low point (e.g., sags, drips, valves, manifolds, dead-legs, traps) within the covered segment nearest to the beginning of the ICDA Region. The second location must be further downstream, within a covered segment, near the end of the ICDA Region. If corrosion exists at either location, the operator must — (i) Evaluate the severity of the defect (remaining strength) and remediate the defect in accordance with §192.933; (ii) As part of the operator’s current integrity assessment either perform additional excavations in each covered segment within the ICDA region, or use an alternative assessment method allowed by this subpart to assess the line pipe in each covered segment within the ICDA region for internal corrosion; and (iii) Evaluate the potential for internal corrosion in all pipeline segments (both covered and non-covered) in the operator’s pipeline system with similar characteristics to the ICDA region containing the covered segment in which the corrosion was found, and as appropriate, remediate the conditions the operator finds in accordance with §192.933. (4) Post-assessment evaluation and monitoring. An operator’s plan must provide for evaluating the effectiveness of the ICDA process and continued monitoring of covered segments where internal corrosion has been identified. The evaluation and monitoring process includes — (i) Evaluating the effectiveness of ICDA as an assessment method for addressing internal corrosion and determining whether a covered segment should be reassessed at more frequent intervals than those specified in §192.939. An operator must carry out this evaluation within a year of conducting an ICDA; and (ii) Continually monitoring each covered segment where internal corrosion has been identified using techniques such as coupons, UT sensors or electronic probes, periodically drawing off liquids at low points and chemically analyzing the liquids for the presence of corrosion products. An operator must base the frequency of the monitoring and liquid analysis on results from all integrity assessments that have been conducted in accordance with the requirements of this subpart, and risk factors specific to the covered segment. If an operator finds any evidence of corrosion products in the covered segment, the operator must take prompt action in accordance with one of the two following required actions and remediate the conditions the operator finds in accordance with §192.933. (A) Conduct excavations of covered segments at locations downstream from where the electrolyte might have entered the pipe; or (B) Assess the covered segment using another integrity assessment method allowed by this subpart. (5) Other requirements. The ICDA plan must also include — (i) Criteria an operator will apply in making key decisions (e.g., ICDA feasibility, definition of ICDA Regions, conditions requiring excavation) in implementing each stage of the ICDA process;




Addendum 4, July 2010 356(o)

(ii) Provisions for applying more restrictive criteria when conducting ICDA for the first time on a covered segment and that become less stringent as the operator gains experience; and (iii) Provisions that analysis be carried out on the entire pipeline in which covered segments are present, except that application of the remediation criteria of §192.933 may be limited to covered segments. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan. 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]

GUIDE MATERIAL


§192.929 What are the requirements for using Direct Assessment for

Stress Corrosion Cracking (SCCDA)? [Effective Date: 07/10/06]

(a) Definition. Stress Corrosion Cracking Direct Assessment (SCCDA) is a process to assess a covered pipe segment for the presence of SCC primarily by systematically gathering and analyzing excavation data for pipe having similar operational characteristics and residing in a similar physical environment. (b) General requirements. An operator using direct assessment as an integrity assessment method to address stress corrosion cracking in a covered pipeline segment must have a plan that provides, at minimum, for — (1) Data gathering and integration. An operator’s plan must provide for a systematic process to collect and evaluate data for all covered segments to identify whether the conditions for SCC are present and to prioritize the covered segments for assessment. This process must include gathering and evaluating data related to SCC at all sites an operator excavates during the conduct of its pipeline operations where the criteria in ASME/ANSI B31.8S (incorporated by reference, see §192.7), Appendix A3.3 indicate the potential for SCC. This data includes at minimum, the data specified in ASME/ANSI B31.8S, Appendix A3. (2) Assessment method. The plan must provide that if conditions for SCC are identified in a covered segment, an operator must assess the covered segment using an integrity assessment method specified in ASME/ANSI B31.8S, Appendix A3, and remediate the threat in accordance with ASME/ANSI B31.8S, Appendix A3, section A3.4. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan. 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]

GUIDE MATERIAL





Addendum 7, July 2011 356(p)

§192.931 How may Confirmatory Direct Assessment (CDA) be used?


An operator using the confirmatory direct assessment (CDA) method as allowed in §192.937 must have a plan that meets the requirements of this section and of §§192.925 (ECDA) and §192.927 (ICDA). (a) Threats. An operator may only use CDA on a covered segment to identify damage resulting from external corrosion or internal corrosion. (b) External corrosion plan. An operator’s CDA plan for identifying external corrosion must comply with §192.925 with the following exceptions. (1) The procedures for indirect examination may allow use of only one indirect examination tool suitable for the application. (2) The procedures for direct examination and remediation must provide that — (i) All immediate action indications must be excavated for each ECDA region; and (ii) At least one high risk indication that meets the criteria of scheduled action must be excavated in each ECDA region. (c) Internal corrosion plan. An operator’s CDA plan for identifying internal corrosion must comply with §192.927 except that the plan’s procedures for identifying locations for excavation may require excavation of only one high risk location in each ICDA region. (d) Defects requiring near-term remediation. If an assessment carried out under paragraph (b) or (c) of this section reveals any defect requiring remediation prior to the next scheduled assessment, the operator must schedule the next assessment in accordance with NACE SP0502-2008 (incorporated by reference, see §192.7), section 6.2 and 6.3. If the defect requires immediate remediation, then the operator must reduce pressure consistent with §192.933 until the operator has completed reassessment using one of the assessment techniques allowed in §192.937. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan. 15, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006; Amdt. 192-114, 75 FR 48593, Aug. 11, 2010]

GUIDE MATERIAL Note: All references to NACE throughout this section of guide material are specifically to NACE SP0502-2008 as incorporated by reference in §192.7. (NACE SP0502-2008 is the reaffirmed RP0502-2002.) Example: An abbreviated NACE 1.1.7 means NACE SP0502-2008, Paragraph 1.1.7. In all cases, the NACE referenced materials shall be consulted as per the Regulations. 1 PURPOSE Confirmatory Direct Assessment (CDA) is a methodology to assess the integrity of a pipeline that is

subject to the threats of external corrosion and internal corrosion. CDA may be used to meet the reassessment intervals of §192.939. See guide material under §192.939. 2 GENERAL REQUIREMENTS (a) If an operator uses CDA, a written CDA plan is required. The plan is to be based on the following. (1) Section 192.931. (2) Section 192.925, External Corrosion Direct Assessment (ECDA), with exceptions noted in

§192.931(b). (3) Section 192.927, Internal Corrosion Direct Assessment (ICDA), with exceptions noted in

§192.931(c). (4) NACE SP0502.




Addendum 6, April 2011 359

(ii) Permits. (iii) Right-of-way.

(2) Technical justification that the pressure reduction is still adequate should consider one or more of the following.

(i) Effect of continued corrosion. (ii) Environmental changes. (iii) Additional pressure cycles. (iv) Class location changes. (v) Validation of the existing pressure reduction. (c) If the existing pressure reduction is no longer adequate, the operator should do one of the following. (1) Make further reduction in operating pressure. (2) Repair or replace the pipe. (3) Take pipeline out of service.

§192.935 What additional preventive and mitigative measures must an operator take?


(a) General requirements. An operator must take additional measures beyond those already required by Part 192 to prevent a pipeline failure and to mitigate the consequences of a pipeline failure in a high consequence area. An operator must base the additional measures on the threats the operator has identified to each pipeline segment. (See §192.917.) An operator must conduct, in accordance with one of the risk assessment approaches in ASME/ANSI B31.8S (incorporated by reference, see §192.7), section 5, a risk analysis of its pipeline to identify additional measures to protect the high consequence area and enhance public safety. Such additional measures include, but are not limited to, installing Automatic Shut-off Valves or Remote Control Valves, installing computerized monitoring and leak detection systems, replacing pipe segments with pipe of heavier wall thickness, providing additional training to personnel on response procedures, conducting drills with local emergency responders and implementing additional inspection and maintenance programs. (b) Third party damage and outside force damage. (1) Third party damage. An operator must enhance its damage prevention program, as required under §192.614 of this part, with respect to a covered segment to prevent and minimize the consequences of a release due to third party damage. Enhanced measures to an existing damage prevention program include, at a minimum — (i) Using qualified personnel (see §192.915) for work an operator is conducting that could adversely affect the integrity of a covered segment, such as marking, locating, and direct supervision of known excavation work. (ii) Collecting in a central database information that is location specific on excavation damage that occurs in covered and non covered segments in the transmission system and the root cause analysis to support identification of targeted additional preventative and mitigative measures in the high consequence areas. This information must include recognized damage that is not required to be reported as an incident under part 191. (iii) Participating in one-call systems in locations where covered segments are present. (iv) Monitoring of excavations conducted on covered pipeline segments by pipeline personnel. If an operator finds physical evidence of encroachment involving excavation that the operator did not monitor near a covered segment, an operator must either excavate the area near the encroachment or conduct an above ground survey using methods defined in NACE SP0502–2008 (incorporated by reference, see §192.7). An operator must excavate, and remediate, in accordance with ANSI/ASME B31.8S and §192.933 any indication of coating holidays or discontinuity warranting direct examination. (2) Outside force damage. If an operator determines that outside force (e.g., earth movement, floods, unstable suspension bridge) is a threat to the integrity of a covered segment, the operator must take measures to minimize the consequences to the covered segment from outside force damage. These measures include, but are not limited to, increasing the frequency of aerial, foot or other methods of patrols, adding external protection, reducing external stress, and relocating the





line. (c) Automatic shut-off valves (ASV) or Remote control valves (RCV). If an operator determines, based on a risk analysis, that an ASV or RCV would be an efficient means of adding protection to a high consequence area in the event of a gas release, an operator must install the ASV or RCV. In making that determination, an operator must, at least, consider the following factors — swiftness of leak detection and pipe shutdown capabilities, the type of gas being transported, operating pressure, the rate of potential release, pipeline profile, the potential for ignition, and location of nearest response personnel. (d) Pipelines operating below 30% SMYS. An operator of a transmission pipeline operating below 30% SMYS located in a high consequence area must follow the requirements in paragraphs (d)(1) and (d)(2) of this section. An operator of a transmission pipeline operating below 30% SMYS located in a Class 3 or Class 4 area but not in a high consequence area must follow the requirements in paragraphs (d)(1), (d)(2) and (d)(3) of this section. (1) Apply the requirements in paragraphs (b)(1)(i) and (b)(1)(iii) of this section to the pipeline; and (2) Either monitor excavations near the pipeline, or conduct patrols as required by §192.705 of the pipeline at bi-monthly intervals. If an operator finds any indication of unreported construction activity, the operator must conduct a follow up investigation to determine if mechanical damage has occurred. (3) Perform semi-annual leak surveys (quarterly for unprotected pipelines or cathodically protected pipe where electrical surveys are impractical). (e) Plastic transmission pipeline. An operator of a plastic transmission pipeline must apply the requirements in paragraphs (b)(1)(i), (b)(1)(iii) and (b)(1)(iv) of this section to the covered segments of the pipeline. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan. 15, 2004, Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004 and Amdt. 192-95 Correction, 69 FR 29903, May 26, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006; Amdt. 192-114, 75 FR 48593, Aug. 11, 2010]

GUIDE MATERIAL 1 ADDITIONAL PREVENTIVE AND MITIGATIVE (P&M) MEASURES (§192.935(a) and (c))

To comply with §192.935, an operator must conduct a risk analysis of all pipelines within HCAs, and determine for each applicable threat on each covered segment whether any of the following (which exceed the requirements of other subparts of Part 192) will prevent pipeline failure or mitigate the consequences of such a failure.

(a) Installation of an automatic shutoff valve (ASV) or a remote control valve (RCV). (1) To comply with §192.935(c), an operator must consider the following factors in determining if an

ASV or RCV would be an efficient means of adding protection in an HCA. (i) Swiftness of leak detection. Example: There may be no advantage to installing an ASV or

RCV on segments where adequate SCADA or other monitoring methods allow for quick operator response to leakage.

(ii) Shutdown capabilities in the area. Example: An ASV or RCV might not make shutdown any faster or easier in locations where adequate valving and easy access already exists.

(iii) Type of gas. Example: An ASV or RCV might mitigate the environmental impact of leakage on a pipeline carrying heavier-than-air gases.

(iv) Operating pressure. Example: Higher-pressure lines hold a larger volume of gas. An ASV or RCV on such a line may reduce the volume of release and potential for ignition.

(v) Potential release rate. Example: Installing an ASV or RCV may affect the duration of the potential release rate.

(vi) Pipeline profile. Example: Heavier-than-air gases can pool in low elevation spots. An ASV or RCV in such locations may allow faster shut off and, therefore, less accumulation of gas.





(vii) Potential for ignition. Example: Areas that have known sources of ignition (e.g., foundries) might benefit from an ASV or RCV.

(viii) Location of nearest response personnel. Example: Locations where operator response is timely may not benefit from the installation of an ASV or RCV.

(2) An operator may also consider the following. (i) Seasonal weather restrictions that can impede access. (ii) Depth of pipe as it relates to access for squeeze-off. (iii) River crossings or other geographical features that affect access for maintenance or

response. (iv) Proximity of the HCA to existing valves. (v) Population density. (vi) Wide pressure fluctuations due to normal operating conditions (e.g., power plant

locations). (vii) Maintenance, reliability, and cost-benefit issues. (b) Installation of computerized monitoring and leak detection systems.

An operator may consider the following, which could provide earlier leak or pipeline rupture detection.

(1) Increasing the locations monitored by SCADA. (2) Automating data gathering from other monitoring devices such as pressure transmitters. (c) Replacing pipe with that of heavier-wall thickness, which is more resistant to damage from external

forces. (d) Providing additional training on response procedures. An operator may consider the following. (1) Increasing the frequency of emergency response training. (2) Conducting tabletop or field drills. (3) Hiring a third party with expertise in emergency response to conduct training. (4) Attending emergency response training offered by industry associations. (e) Conducting drills with local emergency responders. The operator may consider the following. (1) Including the drill as part of liaison meetings with emergency responders. (2) Working with local multi-agency, emergency coordination groups. (3) Incorporating the drill into local fire or police academy curriculum. (f) Implementing additional inspection and maintenance programs. The operator may consider the following. (1) Increasing leak survey frequencies. (2) Increasing patrol frequencies. (3) Using procedures with more stringent criteria than required by the Regulations. (4) Increasing facility inspection frequencies. 2 THIRD-PARTY DAMAGE (§192.935(b)(1))

To comply with §192.935(b)(1) for the specific threat of third-party damage, an operator must do the following.

(a) Qualify personnel to conduct the following activities related to work the operator is conducting in a covered segment.

(1) Locating the pipeline. (2) Marking the pipeline. (3) Directly supervising known excavation work. A qualification for this activity might include the

following. (i) Recognition of line-locate markings. (ii) Knowledge of one-call requirements. (iii) Knowledge of operator’s applicable procedures, including emergency response. (iv) Understanding the risks of various excavation methods. (4) Other activities that could adversely affect the integrity of the pipeline. (b) Use a central database to collect the following. (1) Excavation damage information for covered and non-covered segments. This might include the

following. (i) Number of leaks or ruptures. (ii) Number of known damages not resulting in leaks or ruptures. (iii) Excavation method.





(iv) Name of excavator causing damage. (2) Root cause analysis data to identify targeted P&M measures for HCAs. This might include the

number of damages where: (i) No line locate was requested. (ii) Line was incorrectly marked. (iii) Line was not marked. (iv) Construction procedures were not followed correctly (e.g., exposing lines during boring). (3) Damage data that is not DOT reportable (reference Part 191 requirements). This might include

known items such as the following. (i) Dents. (ii) Gouges. (iii) Coating damage. (iv) Damage to pipeline supports or river anchors. (c) Participate in a one-call program wherever there are covered segments. (d) Monitor excavations on covered segments. An operator may want to consider the following. (1) Mapping HCAs so field personnel can easily recognize when they are in an area that requires

monitoring. (2) Creating a business process that alerts the appropriate departments of pending excavations. (3) Working with the local One-Call Center to notify excavators and operators when monitoring is

required. (4) Training line locators to notify appropriate personnel when they know work will take place in an

HCA. (5) Documenting excavation monitoring using one or more of the following. (i) Time card accounting. (ii) Special forms. (iii) Time-stamped electronic data. (iv) Maps. (e) When there is physical evidence of an excavation near a covered segment that the operator did not

monitor, either excavate the area or conduct an aboveground survey as defined in NACE SP0502-2008 (e.g., DCVG). Examples of how to identify an encroachment might include the following.

(1) New pavement patches. (2) Heavy equipment on site. (3) Disturbed earth. (4) New structures requiring excavation (e.g., fence posts, telephone poles, buildings, slabs). (5) Exposed pipe. (6) New landscaping. (7) One-call documentation. 3 OUTSIDE FORCE DAMAGE (§192.935(b)(2))

To comply with §192.935(b)(2) for the specific threat of outside force damage (e.g., earth movement, floods, unstable suspension bridge), an operator must take additional measures to minimize the consequences of outside force.

(a) The measures include the following. (1) Increasing the frequency of patrols. This may allow faster recognition of damage. (2) Adding external protection. This might include the following. (i) Installing fencing or other barriers to impede earth movement. (ii) External slabs or additional cover. (3) Reducing external stress. This might include the following. (i) Installing expansion joints. (ii) Removing overburden. (4) Relocating the pipeline to an area with less exposure to outside forces. This might include

lowering or raising the pipeline. (b) An operator may also consider installing the following. (1) River anchors where appropriate. (2) Elevated relief or vent stacks on regulator stations. (3) Additional bridge hangers or pipe supports.





[Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan. 15, 2004 and Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004]

GUIDE MATERIAL 1 GENERAL Low stress reassessment is an integrity assessment method that may be used by an operator to

address the threats of external corrosion and internal corrosion. This method can only be used for transmission lines operating below 30% SMYS. Prior to applying this method, the operator is required to complete a baseline integrity assessment in accordance with §§192.919 and 192.921. The low stress reassessment is required at intervals not exceeding 7 years, and a full reassessment (in-line inspection, pressure test, or direct assessment) is required no more than 20 years after the previous full assessment. Appendix E to Part 192 (Tables E.II.2 and E.II.3) provides guidance on low stress reassessment.

2 EXTERNAL CORROSION 2.1 Cathodically protected pipe where electrical surveys are practical. (a) If low stress reassessment is used on cathodically protected pipe, an electrical survey (i.e., indirect

examination tool or method) is required. Examples of electrical surveys are listed below. Appendix A of NACE SP0502-2008, “External Corrosion Direct Assessment Methodology” provides additional information on each type of survey listed.

(1) Close-interval survey (CIS). (2) Current voltage gradient surveys (ACVG and DCVG). (3) Pearson survey. (4) Alternating current attenuation survey (electromagnetic). (5) Cell-to-cell survey. (b) An operator should have procedures to conduct an electrical survey. The following factors should be

considered when developing written procedures. (1) Electrical safety precautions. (2) Equipment and instrumentation. (3) IR drop considerations, where applicable. (4) Locating and marking pipe. (5) Distance between survey points. (6) Data documentation. (7) Data analysis. (8) Remediation criteria. (9) Post-assessment analysis. 2.2 Unprotected pipe or cathodically protected pipe where electrical surveys are impractical. (a) Leak surveys. See guide material under §192.706 and the applicable sections of Guide Material

Appendix G-192-11. (b) Areas of active corrosion. See guide material under §192.465. (c) For conditions where electrical-type surveys may be impractical, see guide material under §192.465. 2.3 Overall evaluation.

An overall evaluation of the external corrosion threat is required. This evaluation should consider the following.

(a) Leak repair records. See guide material in Guide Material Appendix G-192-11 for examples of types of records that may be considered.




372

(b) Inspection records. Examples of these types of records may include prior assessments, patrolling, leak surveys, and continuing surveillance activities. See guide material under §§192.613, 192.705, and in Guide Material Appendix G-192-17.

(c) Corrosion monitoring records. See guide material under §192.491. (d) Exposed pipe records. See guide material under §192.459. (e) Pipeline environment. The operator should consider the following factors in regards to the pipeline

environment. (1) Soil resistivity (high or low). (2) Soil moisture (wet or dry). (3) Soil types (e.g., rocky, sandy, clay, loam). (4) Land use that may result in soil contaminants that promote corrosive activity, (e.g., spill areas,

industrial sites, agricultural sites, land fills). (5) Unusual soil conditions (e.g., swamps, peat bogs, cinders, foreign fill). (6) Other known conditions that could affect the probability of corrosion, (e.g., soil pH, bacteria). 3 INTERNAL CORROSION (a) See guide material under §192.475 for information on gas and liquid analysis, and appropriate

remediation (mitigative) actions. Gas and liquid samples should be taken at locations representative of operating conditions for the covered segment.

(b) The operator is required to integrate data from the gas and liquid analysis and testing with other internal corrosion information listed below.

(1) Internal corrosion leak records. See guide material in Guide Material Appendix G-192-11 for examples of the types of records that may be considered.

(2) Incident reports. See guide material under §191.15. (3) Safety-related condition reports. See guide material under §§ 191.23 and 191.25. (4) Repair records. See Guide Material Appendix G-192-17. (5) Exposed pipe records. See guide material under §192.475. (6) Analysis and testing records. These records may include coupon analysis results or other

records that might indicate the potential for internal corrosion.

§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. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan. 15, 2004 and Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004]

GUIDE MATERIAL 1 GENERAL PHMSA-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 PHMSA-OPS in accordance with 49 USC 60118(c) -

Waivers approved by Secretary. (2) From an intrastate pipeline operator to its state agency 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 PHMSA-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 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 (incorporated by reference, see §192.7 of this part), 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 as part of the annual report required by §191.17 of this subchapter. (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. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan. 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; Amdt. 192-115, 75 FR 72878, Nov. 26, 2010]

GUIDE MATERIAL

This guide material is under review following Amendment 192-115. 1 REPORTING MEASURES

The required reporting measures are provided in the “Instructions for Semi-Annual Reporting of Performance Measures,” available at the PHMSA-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-OPS, 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 SP0502.





SE, Washington, DC 20590-0001; (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/. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan. 15, 2004; RIN 2137-AD77, 70 FR 11135, Mar. 8, 2005; Amdt. 192-103, 72 FR 4655, Feb. 1, 2007; RIN 2137-AE29, 73 FR 16562, Mar. 28, 2008; RIN 2137-AE29 (#2), 74 FR 2889, Jan. 16, 2009]

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

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

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

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

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

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

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

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

following information. (1) Operator name and ID. (2) Reason for remediation delays. (3) Technical justification that pressure reduction is sufficient for maintaining public safety. (f) Section 192.933(a)(2), when a pressure reduction exceeds 365 days and the existing pressure

reduction is no longer adequate, notifications should include the following information. (1) Operator name and ID. (2) Reason for the remediation delay. (3) Steps the operator is implementing to maintain public safety, which could include a further

reduction in pressure, and technical justification that the reduction is sufficient for maintaining public safety.





2 NOTIFICATION METHODS 2.1 Notification to PHMSA-OPS.

An operator should use only one notification option to PHMSA-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 PHMSA-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 www.napsr.org.

3 REFERENCE

OPS Advisory Bulletin ADB-05-04 (70 FR 43939, July 29, 2005; see Guide Material Appendix G-192-1, Section 2).

§192.951 Where does an operator file a report?


An operator must file any report required by this subpart electronically to the Pipeline and Hazardous Materials Safety Administration in accordance with §191.7 of this subchapter. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan. 15, 2004; RIN 2137-AD77, 70 FR 11135, Mar. 8, 2005; Amdt. 192-103, 72 FR 4655, Feb. 1, 2007; RIN 2137-AE29, 73 FR 16562, Mar. 28, 2008; RIN 2137-AE29 (#2), 74 FR 2889, Jan. 16, 2009; Amdt. 192-115, 75 FR 72878, Nov. 26, 2010]

GUIDE MATERIAL

This guide material is under review following Amendment 192-115. 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 agency. 2 REPORTING METHOD

(a) An operator should use only one reporting option to PHMSA-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.

(b) OPS Advisory Bulletin ADB-07-01 requires that the annual and semiannual IMP performance reports be signed by a senior executive officer and include the title of the officer. See OPS ADB-07-01 (72 FR 20175, April 23, 2007; reference Guide Material Appendix G-192-1, Section 2).



GPTC GUIDE FOR GAS TRANSMISSION AND Guide Material Appendix G-192-1 DISTRIBUTION PIPING SYSTEMS: 2009 Edition


1.9 CORROSION RELATED (Continued)

NACE RP0200 Steel-Cased Pipeline Practices §192.323 §192.467

NACE RP0204 Stress Corrosion Cracking (SCC) Direct Assessment Methodology

§192.613

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 SP0106 Control of Internal Corrosion in Steel Pipelines and Piping Systems

§192.476

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

§192.476

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)

§192.475

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

§192.476

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

§192.150

NACE 35103 External Stress Corrosion Cracking of Underground Pipelines

§192.613

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

§192.479

1.10 DIMENSIONAL STANDARDS

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

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

ASME B1.20.3 Dryseal Pipe Threads, Inch





1.11 PLASTIC RELATED

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

App. G-192-15B

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

§192.321

ASTM D696 Test Method for Coefficient of Linear Thermal Expansion of Plastics

§192.281

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

§192.281

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

§192.281

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

§192.3 §192.63 §192.121

ASTM D2855 Making Solvent-Cemented Joints with Poly (Vinyl Chloride) (PVC) Pipe and Fittings

§192.281

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

§192.321

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

ASTM F1804 Standard Practice for Determining Allowable Tensile Load for Polyethylene (PE) Gas Pipe During Pull-in Installation

App. G-192-15B

ASTM F1924 Plastic Mechanical Fittings for Use on Outside Diameter Controlled Polyethylene Gas Distribution Pipe and Tubing

§192.123

ASTM F1948 Metallic Mechanical Fittings for Use on Outside Diameter Controlled Thermoplastic Gas Distribution Pipe and Tubing

§192.123

ASTM F1962 Standard Guide for Use of Maxi-Horizontal Directional Drilling for Placement of Polyethylene Pipe or Conduit Under Obstacles, Including River Crossings

App. G-192-15B

ASTM F1973 Factory Assembled Anodeless Risers and Transition Fittings in Polyethylene (PE) and Polyamide 11 (PA11) and Polyamide 12 (PA12) Fuel Gas Distribution Systems

§192.123

GRI-92/0147.1 Users’ Guide on Squeeze-Off of Polyethylene Gas Pipes §192.321





1.11 PLASTIC RELATED (Continued)

GRI-94/0205 Guidelines and Technical Reference on Gas Flow Shut-Off in Polyethylene Pipes Using Squeeze Tools

§192.321

GRI-96/0194 Service Effects of Hydrocarbons on Fusion and Mechanical Performance of Polyethylene Gas Distribution Piping

§192.123

PPI - Handbook of PE Pipe

Note: The following are available as individual chapters of the PPI Handbook of Polyethylene Pipe:

Chapter 8 – Above-Ground Applications for Polyethylene Pipe

§192.321

Chapter 12 – Horizontal Directional Drilling App. G-192-15B

PPI TN-13 General Guidelines for Butt, Saddle and Socket Fusion of Unlike Polyethylene Pipes and Fittings

§192.281 §192.283

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

§192.121

PPI TR-9 Recommended Design Factors and Design Coefficients for Thermoplastic Pressure Pipe

§192.123

PPI TR-22 Polyethylene Piping Distribution Systems for Components of Liquid Petroleum Gases

§192.121 §192.123

PPI TR-33 Generic Butt Fusion Joining Procedure for Polyethylene Gas Pipe

§192.281 §192.283

PPI TR-41 Generic Saddle Fusion Joining Procedure for Polyethylene Gas Piping

§192.123 §192.281 §192.283

PPI Tech. Comm. Project 141

Standard Practice for Electrofusion Joining Polyolefin Pipe and Fittings

§192.281

1.12 PRESSURE & FLOW DEVICES

API RP 520 P2 Sizing, Selection and Installation of Pressure-Relieving Devices in Refineries, Part 2 Installation

§192.201

API RP 525 Testing Procedure for Pressure-Relieving Devices Discharging Against Variable Back Pressure (Revised 1960; Discontinued)

§192.743

ASTM F1802 Test Method for Performance Testing of Excess Flow Valves

§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)

§192.201





1.13 STRUCTURAL STEEL & SUPPORTS

ASTM A36 Carbon Structural Steel

MSS SP-58 Pipe Hangers and Supports - Materials, Design and Manufacture

§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 [Available from GPTC Secretary at AGA.]

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

API RP 1166 Excavation Monitoring and Observation §192.614

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

App. G-192-15

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

§192.103

ASME B31.1 Power Piping §192.141

ASME B31.2 Fuel Gas Piping

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 B31Q Pipeline Personnel Qualification §192.805

ASME Guide SI-1 ASME Orientation and Guide for Use of SI (Metric) Units App. G-192-M





1.14 OTHER DOCUMENTS (Continued)

ASNT ILI-PQ In-line Inspection Personnel Qualification and Certification §192.915

ASTM D1586 Standard Test Method for Standard Penetration Test (SPT) and Split-Barrel Sampling of Soils

GMA G-192-15A

ASTM D2487 Standard Practice for Classification of Soils for Engineering Purposes (Unified Soil Classification System)

GMA G-192-15A

ASTM D6273 Standard Test Methods for Natural Gas Odor Intensity §192.625

ASTM E84 Test Method for Surface Burning Characteristics of Building Materials

§192.163

AWS A3.0 Standard Welding Terms and Definitions §192.3 §192.221

CGA “Best Practices” Guide §192.325 §192.361 §192.614

One Call Systems International (OCSI) Resource Guide §192.614

CoGDEM Gas Detection and Calibration Guide 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

App. G-192-15

GRI-91/0285.1 Executive Summary: Technical Summary and Database for Guidelines for Pipelines Crossing Railroads and Highways

App. G-192-15

GRI-95/0171 State-of-the-Art Review and Analysis of Guided Drilling Systems

App. G-192-15B

GRI-96/0368 Guidelines for the Application of Guided Horizontal Drilling to Install Gas Distribution Pipe

App. G-192-15B

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

IAPMO Uniform Plumbing Code §192.141

NCB Subsidence Engineers Handbook, National Coal Board Mining Department (U.K.), 1975

App. G-192-13

NFPA 10 Portable Fire Extinguishers





1.14 OTHER DOCUMENTS (Continued)

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

PRCI L51725 Drilling Fluids in Pipeline Installation by Horizontal Directional Drilling

App. G-192-15A App. G-192-15B

PRCI L51740 Evaluation of the Structural Integrity of Cold Field-Bent Pipe §192.313

PRCI L52290 Installation of Pipelines Using Horizontal Directional Drilling – An Engineering Design Guide

App. G-192-15A App. G-192-15B

PRCI PC-PISCES Personal Computer - Pipeline Soil Crossing Evaluation System (PC-PISCES), Version 2.0 (Related to API RP 1102)

App. G-192-15

UL 723 Test for Surface Burning Characteristics of Building Materials

§192.163




Addendum 1, May 2009 429

3 TECHNICAL PAPERS & PUBLICATIONS

3.1 EMERGENCY RELATED

"First at the Scene" by J.M. Lennon, Director of Claims, Philadelphia Electric Company; AGA Operating Section Proceedings – 1983

§192.617

"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

§192.617

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

§192.475

“Field Guide for Investigating Internal Corrosion of Pipelines,” Richard Eckert, NACE Press, 2003

§192.475

“Field Use Proves Program for Managing Internal Corrosion in Wet-Gas Systems,” Richard Eckert and Bruce Cookingham, Oil & Gas Journal, January 21, 2002

§192.475

“Internal Corrosion Direct Assessment,” Oliver Moghissi, Bruce Cookingham, Lee Norris, and Phil Dusek, Paper # 02087 presented at CORROSION/02 Denver, CO

§192.475

“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

§192.475

“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

§192.475

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

§192.123

"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

§192.613

"Effect of Elevated Ground Temperature (from Electric Cables) on the Pressure Rating of PE Pipe in Gas Piping Applications,” E.F. Palermo, Ph.D,, AGA Operations Conference, April 2007

§192.361

“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

§192.123

“Polyamide 11 Liners Withstand Hydrocarbons, High Temperature,” A. Berry, Pipeline & Gas Journal, December 1998, p. 81

§192.123

“Prediction of Organic Chemical Permeation through PVC Pipe,” A.R. Berens, Research Technology, November 1985, p. 57

§192.123

“Second Generation Skinned Pipes with Enhanced Fracture Resistance,” Jeremy Bowman, Uponor UK, Plastics Pipes XIII, 2006

App. G-192-15B

“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

§192.123





3.4 UNCASED PIPE AND DIRECTIONAL DRILLING RELATED

“Considerations for the Installation of Polyethylene Water Pipe by ‘Horizontal Directional Drilling,’ Larry Petroff, Performance Pipe, presented at Annual Conference and Exposition of AWWA, 2006

App. G-192-15B

“Directional Drilling Damage Prevention Guidelines for the Natural Gas Industry,” AGA Engineering Technical Note (no catalog number), 2004

App. G-192-15B

"Guidelines For A Successful Directional Crossing Bid Package," Directional Crossing Contractors Association, 1995

App. G-192-15A App. G-192-15B

“Horizontal Directional Drilling Good Practices Guidelines” - 2008 (3rd Edition), North American Society for Trenchless Technology (NASTT).

App. G-192-15A App. G-192-15B

"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

App. G-192-15

“Proceedings of the International No-Dig Conferences,” sponsored by the International Society for Trenchless Technology (ISTT) and the North American Society for Trenchless Technology (NASTT), 1988, 1991-1996

App. G-192-15B

3.5 SAFETY AND INTEGRITY MANAGEMENT RELATED

"Pipeline Risk Management Manual," W. Kent Muhlbauer, Elsevier/Gulf Professional Publishing, ISBN: 0-7506-7579-9

§192.907





(b) Grade 2, a leak that is recognized as being non-hazardous at the time of detection, but, requires scheduled repair based on probable future hazard.

(c) Grade 3, a leak that is non-hazardous at the time of detection and can be reasonably expected to remain non-hazardous.

5.6 Leak classification and action criteria. Guidelines for leak classification and leakage control are provided in Tables 3a, 3b, and 3c. The

examples of leak conditions provided in the tables are presented as guidelines and are not exclusive. The judgment of the operator personnel at the scene is of primary importance in determining the grade assigned to a leak.

5.7 Follow-up inspection. The adequacy of leak repairs should be checked before backfilling. The perimeter of the leak area

should be checked with a CGI. Where there is residual gas in the ground after the repair of a Grade 1 leak, a follow-up inspection should be made as soon as practical after allowing the soil atmosphere to vent and stabilize, but, in no case later than one month following the repair. In the case of other leak repairs, the need for a follow-up inspection should be determined by qualified personnel.

5.8 Reevaluation of a leak. When a leak is to be reevaluated (see Tables 3b and 3c), it should be classified using the same criteria

as when the leak was first discovered. 6 RECORDS AND SELF-AUDIT GUIDELINES 6.1 Leak records. Historical gas leak records should be maintained. Sufficient data should be available to provide the

information needed to complete the Department of Transportation Leak Report Forms DOT F-7100.1, DOT F-7100.1-1, DOT F-7100.2 and DOT F-7100.2-1, and to demonstrate the adequacy of operator’s maintenance programs.

The following data should be recorded and maintained, but need not be in any specific format or

retained at one location. Time of day and environmental description records are required only for those leaks that are reported by an outside source or require reporting to a regulatory agency.

(a) Date discovered, time reported, time dispatched, time investigated and by whom. (b) Date(s) reevaluated before repair and by whom. (c) Date repaired, time repaired and by whom. (d) Date(s) rechecked after repair and by whom. (e) If a reportable leak, date and time of telephone report to regulatory authority and by whom. (f) Location of leak. (g) Leak grade. (h) Line use (distribution, transmission, etc.). (i) Method of leak detection (if reported by outside party, list name and address). (j) Part of system where leak occurred (main, service line, etc.). (k) Part of system that leaked (pipe, valve, fitting, compressor or regulator station, etc.). (l) Material which leaked (steel, plastic, cast iron, etc.). (m) Origin of leak. (n) Pipe description. (o) Type repair. (p) Leak cause. (q) Date pipe installed (if known). (r) Under cathodic protection? (Yes -- No). (s) Magnitude of CGI indication.





6.2 Leak survey records. For the current and immediately previous survey of an area, the following information should be

available. (a) Description of system and area surveyed. (This could include maps or leak survey logs or both.) (b) Survey results. (c) Survey method. (d) Names of those making survey. (e) Survey dates. (f) In addition to the above, the following records should be kept for a pressure drop test. (1) The name of the operator, the name of the operator's employee responsible for making the test,

and the name of any test company used. (2) Test medium used. (3) Test pressure. (4) Test duration. (5) Pressure recording charts, or other record of pressure readings. (6) Test results. 6.3 Self audits. In order that the effectiveness of the leak detection and repair program may be evaluated, self-audits

should be performed on the following. (a) Schedule of leak survey. The operator should ensure that the schedule is commensurate with

Subpart M of the Minimum Federal Safety Standards, and the general condition of the pipeline system.

(b) Survey effectiveness. The operator should evaluate leak survey results to ensure that, throughout the system, an effective leakage survey is being performed. The following are examples that may be considered for this evaluation.

(1) Leakage survey audits. Leakage survey audits may include a re-inspection of selected areas on a percentage basis (e.g., 10% of a given map area), by another survey technician, a supervisor, or a third-party using the same equipment. Audits should be concluded as soon as possible after the completion of the original survey to avoid variations in venting conditions. During an audit, classified leaks should be evaluated for the accuracy of classification according to the operator’s written procedures.

(2) Detected leaks versus mechanical failure or damage. Evaluate variations in leakage data in areas where there is a likelihood of failure from system components (e.g., mechanical couplings or tees, risers), historical third-party damage, or outside forces (e.g., settling or subsidence). Evaluate both aboveground and underground leaks.

(3) Detected leaks versus corrosion data. Consider plotting leakage data in conjunction with corrosion data on protected and unprotected piping systems. An increase in corrosion-related leaks from one survey cycle to the next might indicate a significant change in the cathodic protection system on a given pipeline. Conversely, a reduction in reported corrosion-related leaks from one survey cycle to the next might indicate an issue with the performance of the survey.

(4) Detected leaks by area, map, town, mile, or pipe segment. Evaluate historical leak history data monthly for unanticipated variations in total leak count.

(5) Detected leaks versus confirmed leak calls from the public. Establish a matrix to evaluate the frequency of confirmed underground leaks reported by the public versus leaks detected during normal survey operations. This evaluation should take into account changes in the weather, system demand, and any condition that would cause an artificial increase in leak calls. Data collected for this type of evaluation may span a period of several years or survey cycles. A variance in the ratio may indicate improved or reduced effectiveness of the leak survey program.

(6) Recheck program (e.g., 2 or 3 days). This can be used on leaks found during the survey to ensure that found leaks are being classified properly.

(7) GPS tracking. Real-time GPS tracking of leak survey progress and completion can be plotted on system maps.





(8) Tagging. Although tagging may not specifically evaluate the effectiveness of a leakage survey, it will help in documenting the coverage in a given survey area. Using a two-part, numbered tag, place tags on selected meter sets in the survey area ahead of the scheduled leakage survey. Meter tags should be dated when placed. Survey technicians would then be required to return collected tags at the conclusion of the survey day.

(c) Repair scheduling. The operator should ensure that repairs are made within the time specified. (d) Repair effectiveness. The operator should ensure that leak repairs are effective. (e) Leak records. The operator should ensure that adequate records are being maintained. 7 PINPOINTING 7.1 Scope. Pinpointing is the process of tracing a detected gas leak to its source. It should follow an orderly

systematic process that uses one or more of the following procedures to minimize excavation. The objective is to prevent unnecessary excavation which is more time consuming and costly than time spent pinpointing a leak.

7.2 Procedure. (a) The migration of gas should be determined by establishing the outer boundaries of the indications.

This will define the area in which the leak will normally be located. These tests should be made with a CGI without expending excessive effort providing sample points.

(b) In an urban environment, sampling is recommended at available openings (e.g., manholes, valve boxes) in the area. Testing such structures provides advantages in determining migration when pinpointing a leak, such as the following.

(1) Identifying the spread through efficient use of existing structures, thus minimizing barholes. (2) Reducing the risk of damaging other utilities during the investigation. (3) Expediting the investigation. (c) All gas lines should be located to narrow the area of search. Particular attention should be paid to

the location of valves, fittings, tees, stubs, and connections, the latter having a relatively high probability of leakage. Caution should be exercised to prevent damage to other underground structures during barring or excavating.

(d) Foreign facilities in the area of search should be identified. The operator should look for evidence of recent construction activities that could have contributed to the leakage. Gas may also migrate and vent along a trench or bore hole provided for other facilities. Leaks could occur at the intersection of the foreign facility and the gas pipeline. Particular attention should be given to these intersections.

(e) Evenly spaced bar or test holes should be used over the gas line suspected to be leaking. All barholes should be of equal depth and diameter (and down to the pipe depth where necessary) and all CGI readings should be taken at an equal depth in order to obtain consistent and worthwhile readings. Using only the highest sustained readings, the gas can be traced to its source by identifying the test holes with the highest readings.

(f) Frequently, high readings are found in more than one barhole and additional techniques are necessary to determine which reading is closest to the probable source. Many of the barhole readings will normally decline over a period of time but it may be desirable to dissipate excess gas from the underground locations to hasten this process. Evaluation methods should be used with caution to avoid distorting the venting patterns.

(g) Once underground leakage has been identified, additional holes and deeper holes should be probed to more closely bracket the area. For example, test holes may be spaced six feet apart initially and then the six foot spacing between the two highest test holes might be probed with additional test holes, with spacing as close as twelve inches.

(h) Additional tests include taking CGI readings at the top of a barhole or using manometer or bubble forming solution to determine which barhole has the greatest positive flow. Other indications are dust particles blowing from the barholes, the sound of gas coming from the barhole or the feel of gas flow on a sensitive skin surface. On occasion, sunlight diffraction can be observed as the gas vents to the atmosphere.





(i) Testing at available openings may be used to isolate the source in addition to the techniques previously mentioned. Many times the leak is found at the intersection of the foreign conduit and a gas line. Particular attention should be given to these locations.

(j) Pinpointing a leak entering an underground conduit, sewer, or drain may require the investigation to extend to the first subsurface structure, in each direction, which has no readings. See 5.3(i) above.

(k) When the pattern of the CGI readings has stabilized, the barhole with the highest reading will usually pinpoint the gas leak.

(l) The operator should test with bubble forming solution where piping has been exposed, particularly to locate smaller leaks.

7.3 Precautions. (a) When placing barholes for testing, consideration should be given to barhole placement and depth to

minimize the potential for damage to other underground facilities and possible injury to personnel conducting the investigation.

(b) Unusual situations may complicate these techniques on some occasions. They are unlikely, but possible. For example, multiple leakage can be occurring which gives confusing data. The area should be rechecked after repairs are completed to eliminate this potential. Gas may occasionally pocket and give a strong indication until the cavity has been vented. Foreign gases, such as gas from decomposed material, can occasionally be encountered. This is characterized by fairly constant CGI readings between 15 percent and 30 percent gas throughout the area. Indications of gas detected in sewer systems should be considered migrating gas leakage until proven otherwise by test or analysis.

(c) When pinpointing leakage where the gas is heavier than air (LP gas), the gas will normally stay low near the pipe level, but may flow downhill. LP gases usually do not diffuse or migrate widely so the leak is generally close to the indication. If the gas is venting into a duct or sewer system, it can travel considerable distance.





TABLE 2 – AVAILABLE METHANE DETECTION TECHNOLOGIES

The following technologies are currently commercialized for use in methane leak detection. The information in the table depicts typical or nominal values/properties/characteristics contained in current manufacturers’ literature. Operators should consult instrument manufacturers for appropriate application and limitations of available instrument technologies.

Technology Typical Application

Sensitivitya Rangea Sampling Method

Advantages Limitations

Catalytic (Pellistor)

1 50 ppm 0.1-1% LEL 1% VOL

0.1-100% LEL

Vacuum pump Hand aspiration

Multi-gas options for confined space entry.

Sensors may be damaged by shock or vibration.

Loss of sensitivity when exposed to paint, lacquer, or varnish vapors.

Thermal Conductivity

1 2.5% VOL 0-100% VOL Vacuum pump Hand aspiration

Multi-gas Capability.

Exposure to high concentrations may saturate the sensor.

Amplified Thermal Conductivity

1 5 ppm 5-1,000 ppm Vacuum pump Fast response. Zero stability dependent on temperature and moisture.

Temperature change, dust, and moisture may cause false detection.

Semiconductor 2 1-100 ppmb 0-1,000 ppm Diffusion Fast response. Zero stability dependent on temperature and moisture.

Can be damaged by water.





TABLE 2 – AVAILABLE METHANE DETECTION TECHNOLOGIES (Continued)




Flame Ionization 2, 3

1 ppm 0-10,000 ppm Vacuum pump Fast response. Vacuum pump system will draw residual gas from soil surface or cavity.

Venturi draw systems are slower responding.

Will detect all volatile organic compounds (VOCs) unless special filters are used.

Requires external hydrogen fuel. Calibration affected by

temperature and humidity. High concentration gas will cause

sensor flame out. Requires warm-up time to become

stable.

Open Path IR TDLAS

2, 3c, 4 5 ppm-meter

0-100,000 ppm-meter

Atmospheric open path laser scanning of up to 100 ft.

Remote detection of low leak levels, faster survey, improved operator safety, methane specific detection. Scanning of confined space without entry.

Low flowing leaks may not produce a detectable plume.

Closed Path Bifringent IR

1d, 2, 3 1 ppm 0-2,500 ppm 0-100% VOLb

Vacuum pump with sample cell

Low level leak detection, methane specific, no fuel gas, extended measurement range, very fast response.

Requires warm-up time to reach full sensitivity.





TABLE 2 – AVAILABLE METHANE DETECTION TECHNOLOGIES (Continued)




Closed Path Bifringent IR (Continued)

3 1 ppm 0-250 ppm Atmospheric closed path

Low level leak detection, methane specific, no fuel gas, fast mobile survey speed.

Weather related conditions may affect detector (e.g., snow, sloppy road conditions).

Requires warm-up time to reach full sensitivity.

Closed Path IR Laser

1, 2, 3 1-100 ppmb 0-1,000 ppm 0-100% VOL

Vacuum pump with sample cell

Low level leak detection, methane specific, no fuel gas, extended measurement range.

Dust contamination in sample cell will severely affect sensitivity.

Response rate and sensitivity vary by sample cell path length and flow design.

Slower response.

Open Path Passive IR Imaging

4

Unknown N/A Atmospheric open path

IR image of venting gas.

Effective for moderate to large size leaks, difficult to image under certain ambient conditions.

Notes: (a) Specifications represent typical performance levels of the technology and implementation approach. Actual instrument specifications and performance may vary by manufacturer and product. (b) Varies widely by manufacturer. (c) Systems are currently under development. Currently in use on transmission line survey (d) Systems are currently under development.





Applications Key 1. Leak investigation and classification. Typical instrument requirements are to measure percent gas or LEL to classify the severity of a leak.

Instruments are typically rated “Intrinsically Safe.” Typical measurement may be taken within a barhole or in the air of an area with a known leak.

2. Walking leak survey. Typical instrument requirements are to measure very low concentration levels with fast responding sensors. Typical measurements are taken while walking and searching with the instrument.

3. Mobile leak survey. Typical instrument requirements are to measure very low concentration levels with fast responding sensors. Typical measurements are taken while driving in a vehicle or ATV and searching with the instrument.

4. Gas gathering and production facilities, compressor station leak survey. Typical instrument requirements are to measure moderate to high concentrations from a remote distance.

Definitions

Open Path: IR light passes through a naturally venting gas plume. Closed Path: IR light passes through sample chamber into which a vacuum pump draws gas. Active IR: IR beam is projected via a laser or other IR radiation source (e.g., LED, halogen lamp). Passive IR: IR light source is naturally occurring from sunlight or heat radiation. Mid IR: IR wavelengths in the 3-5µm (µm is micro-meter). Near IR: IR wavelengths in the 0.8-2µm. Catalytic:

Catalytic works on the basis that gas molecules will combust when coming into contact with a heated platinum wire (coated with a catalytic material). The catalytic material will accelerate the oxidation reaction, thus raising the temperature of the platinum wire. As the platinum wire heats up, the change in resistance is measured. The amount of resistance change is proportional to the gas concentration. Typically, two sensor beads are used (sample and reference).

Thermal Conductivity: Thermal conductivity works on the basis of passing a sample of gas over a heated thermistor. The thermistor will change resistance relative to the thermal conductivity of the gas. A reference thermistor is normally used to generate a relative comparison. The resistance change is proportional to the gas concentration.

Amplified Thermal Conductivity:

Amplified thermal conductivity is the same principle as “Thermal Conductivity” but with additional electronic amplification to increase the response signal.





Semiconductor:

Semiconductor sensors work on the basis that a tin dioxide (SnO2) material (when heated to a specific temperature (e.g., at 400°C) for hydrocarbon detection) will change resistance as it interacts with the gas. The resistance change is non-proportional to gas concentration.

Flame Ionization:

Flame ionization works on the basis that gas molecules are positively charged by burning in a high temperature hydrogen flame. The ions are then collected on an electrode. The rate of charged particles collected is proportional to the gas concentration.

Open Path IR TDLAS (Tunable Diode Laser Absorption Spectroscopy): Open path IR TDLAS works on the basis of an IR laser (~1.6µm for methane) sweeping through a naturally venting gas plume from a remote distance. As the IR laser passes through the plume, the gas will absorb a portion of the light. Absorption spectroscopy is used to measure the amount of absorption. The amount of absorption is proportional to the gas concentration and the path length through the gas.

Closed Path Bifringent IR: Bifringent IR works on the basis that gas molecules absorb infrared light at specific wavelengths (~3.3µm for methane). A gas sample is passed through the light path in which a portion of the IR light is absorbed. Optical processing by a bifringent (Etalon) crystal is used to measure the amount of absorption. The amount of absorption is proportional to the gas concentration and the path length through the gas.

Closed Path IR Laser: Closed path IR lasers work on the basis of passing a near IR laser tuned to a specific gas absorption wavelength (~1.6µm) through a gas sample cell. The amount of absorption is proportional to the gas concentration and the path length through the gas. In order to increase the sensitivity, multiple passes through the cell are used to increase the path length. There are a number of laser, gas sample cell design, and signal processing approaches.

Open Path Passive IR Imaging: IR Imaging works on the basis that gas molecules absorb infrared light at specific wavelengths (3-5µm). A gas imager uses a specialized set of lenses, IR filters, and photo detector array to measure the reduction of IR light relative to the background. A video image is then displayed. In some systems, additional post signal processing is used to enhance the contrast or to color the image.





TABLE 3a – LEAK CLASSIFICATION AND ACTION CRITERIA – GRADE 1

Grade Definition Action Criteria Examples

1 A leak that represents an existing or probable hazard to persons or property, and requires immediate repair or continuous action until the conditions are no longer hazardous. See §192.703(c).

Requires prompt action* to protect life and property, and continuous action until the conditions are no longer hazardous.

*The prompt action in some instances may require one or more of the following.

a. Implementation of emergency plan (§192.615).

b. Evacuating premises.

c. Blocking off an area.

d. Rerouting traffic.

e. Eliminating sources of ignition.

f. Venting the area by removing manhole covers, barholing, installing vent holes, or other means.

g. Stopping the flow of gas by closing valves or other means.

h. Notifying police and fire departments.

1. Any leak which, in the judgment of operating personnel at the scene, is regarded as an immediate hazard.

2. Escaping gas that has ignited.

3. Any indication of gas which has migrated into or under a building, or into a tunnel.

4. Any reading at the outside wall of a building, or where gas would likely migrate to an outside wall of a building.

5. Any reading of 80% LEL, or greater, in a confined space.

6. Any reading of 80% LEL, or greater in small substructures (other than gas associated substructures) from which gas would likely migrate to the outside wall of a building.

7. Any leak that can be seen, heard, or felt, and which is in a location that may endanger the general public or property.





TABLE 3b - LEAK CLASSIFICATION AND ACTION CRITERIA - GRADE 2


2 A leak that is recognized as being non-hazardous at the time of detection, but justifies scheduled repair based on probable future hazard.

Leaks should be repaired or cleared within one calendar year, but no later than 15 months from the date the leak was reported. In determining the repair priority, criteria such as the following should be considered. a. Amount and migration of gas. b. Proximity of gas to buildings and subsurface structures. c. Extent of pavement. d. Soil type, and soil conditions, such as frost cap, moisture and natural venting. Grade 2 leaks should be reevaluated at least once every six months until cleared. The frequency of reevaluation should be determined by the location and magnitude of the leakage condition. Grade 2 leaks may vary greatly in degree of potential hazard. Some Grade 2 leaks, when evaluated by the above criteria, may justify scheduled repair within the next 5 working days. Others will justify repair within 30 days. During the working day on which the leak is discovered, these situations should be brought to the attention of the individual responsible for scheduling leak repair. On the other hand, many Grade 2 leaks, because of their location and magnitude, can be scheduled for repair on a normal routine basis with periodic reinspection as necessary.

A. Leaks Requiring Action Ahead of Ground Freezing or Other Adverse Changes in Venting Conditions. Any leak which, under frozen or other adverse soil conditions, would likely migrate to the outside wall of a building. B. Leaks Requiring Action Within Six Months 1. Any reading of 40% LEL, or greater, under a sidewalk in a wall-to-wall paved area that does not qualify as a Grade 1 leak. 2. Any reading of 100% LEL, or greater, under a street in a wall-to-wall paved area that has significant gas migration and does not qualify as a Grade 1 leak. 3. Any reading less than 80% LEL in small substructures (other than gas associated substructures) from which gas would likely migrate creating a probable future hazard. 4. Any reading between 20% LEL and 80% LEL in a confined space. 5. Any reading on a pipeline operating at 30 percent SMYS, or greater, in a class 3 or 4 location, which does not qualify as a Grade 1 leak. 6. Any reading of 80% LEL, or greater, in gas associated substructures. 7. Any leak which, in the judgment of operating personnel at the scene, is of sufficient magnitude to justify scheduled repair.





TABLE 3c - LEAK CLASSIFICATION AND ACTION CRITERIA - GRADE 3


3 A leak that is non-hazardous at the time of detection and can be reasonably expected to remain non-hazardous.

These leaks should be reevaluated during the next scheduled survey, or within 15 months of the date reported, whichever occurs first, until the leak is regraded or no longer results in a reading.

Leaks Requiring Reevaluation at Periodic Intervals 1. Any reading of less than 80% LEL in small gas associated substructures. 2. Any reading under a street in areas without wall-to-wall paving where it is unlikely the gas could migrate to the outside wall of a building. 3. Any reading of less than 20% LEL in a confined space.



GPTC GUIDE FOR GAS TRANSMISSION AND Guide Material Appendix G-192-11A DISTRIBUTION PIPING SYSTEMS: 2009 Edition


(a) Grade 1, a leak that represents an existing or probable hazard to persons or property and requires immediate repair or continuous action until the conditions are no longer hazardous. See §192.703(c).

(b) Grade 2, a leak that is recognized as being non-hazardous at the time of detection, but, requires scheduled repair based on probable future hazard.

(c) Grade 3, a leak that is non-hazardous at the time of detection and can be reasonably expected to remain non-hazardous. Because petroleum gas is heavier than air and will collect in low areas instead of dissipating, few leaks can safely be classified as Grade 3.

5.6 Leak classification and action criteria. Guidelines for leak classification and leakage control are provided in Tables 3a, 3b, and 3c. The

examples of leak conditions provided in the tables are presented as guidelines and are not exclusive. The judgment of the operator personnel at the scene is of primary importance in determining the grade assigned to a leak.

5.7 Follow-up inspection. The adequacy of leak repairs should be checked before backfilling. The perimeter of the leak area

should be checked with the CGI. Where there is residual gas in the ground after the repair of a Grade 1 leak, follow-up inspections should be made as soon as practical after allowing the soil atmosphere to vent and stabilize, but in no case later than one month following the repair. Since petroleum gases are heavier than air, it is usually necessary to purge or mechanically vent an area one or more times to ensure that a hazardous condition no longer exists. In the case of other repairs, the need for a follow-up inspection should be determined by qualified personnel and when a follow-up inspection is needed, it should be made as soon as practical, but in no case later than three months.

5.8 Reevaluation of a leak. When a leak is to be reevaluated (see Tables 3b and 3c), it should be classified using the same criteria

as when the leak was first discovered. 6 RECORDS AND SELF-AUDIT GUIDELINES 6.1 Leak records. Historical gas leak records should be maintained. Sufficient data should be available to provide the

information needed to complete the Department of Transportation Leak Report Forms DOT F-7100.1, DOT F-7100.1-1, DOT F-7100.2, and DOT F-7100.2.1 and to demonstrate the adequacy of the operator’s maintenance programs.

The following data should be recorded and maintained, but need not be in any specific format or

retained at one location. Time of day and environmental description records are required only for those leaks that are reported by an outside source or require reporting to a regulatory agency.

(a) Date discovered, time reported, time dispatched, time investigated and by whom. (b) Date(s) reevaluated before repair and by whom. (c) Date repaired, time repaired and by whom. (d) Date(s) rechecked after repair and by whom. (e) If a reportable leak, date and time of telephone report to regulatory authority and by whom. (f) Location of leak. (g) Leak grade. (h) Line use (distribution, transmission, etc.). (i) Method of leak detection (if reported by outside party, list name and address). (j) Part of system where leak occurred (main, service line, etc.). (k) Part of system that leaked (pipe, valve, fitting, compressor or regulator station, etc.). (l) Material which leaked (steel, plastic, cast iron, etc.). (m) Origin of leak. (n) Pipe description.





(o) Type repair. (p) Leak cause. (q) Date pipe installed (if known). (r) Under cathodic protection? (Yes -- No). (s) Magnitude of CGI indication. 6.2 Leak survey records. For the current and immediately previous survey of an area, the following information should be

available. (a) Description of system and area surveyed. (This could include maps or leak survey logs or both.) (b) Survey results. (c) Survey method. (d) Names of those making survey. (e) Survey dates. (f) In addition to the above, the following records should be kept for a pressure drop test. (1) The name of the operator, the name of the operator's employee responsible for making the test,

and the name of any test company used. (2) Test medium used. (3) Test pressure. (4) Test duration. (5) Pressure recording charts, or other record of pressure readings. (6) Test results. 6.3 Self audits. In order that the effectiveness of the leak detection and repair program may be evaluated, self-audits

should be performed on the following. (a) Schedule of leak survey. The operator should ensure that the schedule is commensurate with

Subpart M of the Minimum Federal Safety Standards and the general condition of the pipeline system.

(b) Survey effectiveness. The operator should evaluate leak survey results to ensure that, throughout the system, an effective leakage survey is being performed. The following are examples that may be considered for this evaluation.

(1) Leakage survey audits. Leakage survey audits may include a re-inspection of selected areas on a percentage basis (e.g., 10% of a given map area), by another survey technician, a supervisor, or a third-party using the same equipment. Audits should be concluded as soon as possible after the completion of the original survey to avoid variations in venting conditions. During an audit, classified leaks should be evaluated for the accuracy of classification according to the operator’s written procedures.

(2) Detected leaks versus mechanical failure or damage. Evaluate variations in leakage data in areas where there is a likelihood of failure from system components (e.g., mechanical couplings or tees, risers), historical third-party damage, or outside forces (e.g., settling or subsidence). Evaluate both aboveground and underground leaks.

(3) Detected leaks versus corrosion data. Consider plotting leakage data in conjunction with corrosion data on protected and unprotected piping systems. An increase in corrosion-related leaks from one survey cycle to the next might indicate a significant change in the cathodic protection system on a given pipeline. Conversely, a reduction in reported corrosion-related leaks from one survey cycle to the next might indicate an issue with the performance of the survey.

(4) Detected leaks by area, map, town, mile, or pipe segment. Evaluate historical leak history data monthly for unanticipated variations in total leak count.

(5) Detected leaks versus confirmed leak calls from the public. Establish a matrix to evaluate the frequency of confirmed underground leaks reported by the public versus leaks detected during normal survey operations. This evaluation should take into account changes in the weather, system demand, and any condition that would cause an artificial increase in leak calls. Data collected for this type of evaluation may span a period of several years or survey cycles. A variance in the ratio may indicate improved or reduced effectiveness of the leak survey program.





(6) Recheck program (e.g., 2 or 3 days). This can be used on leaks found during the survey to ensure that found leaks are being classified properly.

(7) GPS tracking. Real-time GPS tracking of leak survey progress and completion can be plotted on system maps.

(8) Tagging. Although tagging may not specifically evaluate the effectiveness of a leakage survey, it will help in documenting the coverage in a given survey area. Using a two-part, numbered tag, place tags on selected meter sets in the survey area ahead of the scheduled leakage survey. Meter tags should be dated when placed. Survey technicians would then be required to return collected tags at the conclusion of the survey day.

(c) Repair scheduling. The operator should ensure that repairs are made within the time specified. (d) Repair effectiveness. The operator should ensure that leak repairs are effective. (e) Leak records. The operator should ensure that adequate records are being maintained. 7 PINPOINTING 7.1 Scope. Pinpointing is the process of tracing a detected gas leak to its source. It should follow an orderly

systematic process that uses one or more of the following procedures to minimize excavation. The objective is to prevent unnecessary excavation which is more time consuming and costly than time spent pinpointing a leak.

7.2 Procedure. (a) The migration of gas should be determined by establishing the outer boundaries of the indications.

This will define the area in which the leak will normally be located. These tests should be made with a CGI without expending excessive effort providing sample points.

(b) In an urban environment, sampling is recommended at available openings (e.g., manholes, valve boxes) in the area. Testing such structures provides advantages in determining migration when pinpointing a leak, such as the following.

(1) Identifying the spread through efficient use of existing structures, thus minimizing barholes. (2) Reducing the risk of damaging other utilities during the investigation. (3) Expediting the investigation. (c) All gas lines should be located to narrow the area of search. Particular attention should be paid to

the location of valves, fittings, tees, stubs, and connections, the latter having a relatively high probability of leakage. Caution should be exercised to prevent damage to other underground structures during barring or excavating.

(d) Foreign facilities in the area of search should be identified. The operator should look for evidence of recent construction activities that could have contributed to the leakage. Gas may also migrate and vent along a trench or bore hole provided for other facilities. Leaks could occur at the intersection of the foreign facility and the gas pipeline. Particular attention should be given to these intersections.

(e) Evenly spaced bar or test holes should be used over the gas line suspected to be leaking. All barholes should be of equal depth and diameter (and down to the pipe depth where necessary) and all CGI readings should be taken at an equal depth in order to obtain consistent and worthwhile readings. Using only the highest sustained readings, the gas can be traced to its source by identifying the test holes with the highest readings.

(f) Frequently, high readings are found in more than one barhole and additional techniques are necessary to determine which reading is closest to the probable source. Many of the barhole readings will normally decline over a period of time but it may be desirable to dissipate excess gas from the underground locations to hasten this process. Evaluation methods should be used with caution to avoid distorting the venting patterns.

(g) Once underground leakage has been identified, additional holes and deeper holes should be probed to more closely bracket the area. For example, test holes may be spaced six feet apart initially and then the six foot spacing between the two highest test holes might be probed with additional test holes, with spacing as close as twelve inches.





(h) Additional tests include taking CGI readings at the top of a barhole or using manometer or bubble forming solutions to determine which barhole has the greatest positive flow. Other indications are dust particles blowing from the barholes, the sound of gas coming from the barhole or the feel of gas flow on a sensitive skin surface. On occasion, sunlight diffraction can be observed as the gas vents to the atmosphere.

(i) Testing at available openings may be used to isolate the source in addition to the techniques previously mentioned. Many times the leak is found at the intersection of the foreign conduit and the gas line. Particular attention should be given to these locations.

(j) Pinpointing a leak entering an underground conduit, sewer, or drain may require the investigation to extend to the first subsurface structure, in each direction, which has no readings. See 5.3(i) above.

(k) When the pattern of the CGI readings has stabilized, the barhole with the highest reading will usually pinpoint the gas leak.

(l) The operator should test with bubble forming solution where piping has been exposed, particularly to locate smaller leaks.

7.3 Precautions. (a) When placing barholes for testing, consideration should be given to barhole placement and depth to

minimize the potential for damage to other underground facilities and possible injury to personnel conducting the investigation.

(b) Unusual situations may complicate these techniques on some occasions. They are unlikely, but possible. For example, multiple leakage can be occurring which gives confusing data. The area should be rechecked after repairs are completed to eliminate this potential. Gas may occasionally pocket and give a strong indication until the cavity has been vented. Foreign gases, such as gas from decomposed material, can occasionally be encountered. This is characterized by fairly constant CGI readings between 15 percent and 30 percent gas throughout the area. Indications of gas detected in sewer systems should be considered migrating gas leakage until proven otherwise by test or analysis.

(c) When pinpointing leakage where the gas is heavier than air (LP gas), the gas will normally stay low near the pipe level but may flow downhill. LP gases usually do not diffuse or migrate widely so the leak is generally close to the indication. If the gas is venting into a duct or sewer system, it can travel considerable distance.





TABLE 2 – AVAILABLE PROPANE GAS DETECTION TECHNOLOGIES

The following technologies are currently commercialized for use in propane leak detection. The information in the table depicts typical or nominal values/properties/characteristics contained in current manufacturers’ literature. Operators should consult instrument manufacturers for appropriate application and limitations of available instrument technologies.


Sensitivitya Rangea Sampling Method Advantages Limitations

Catalytic (Pellistor)

1 50 ppm 0.1-1% LEL 1% VOL

0.1-100% LEL

Vacuum pump Hand aspiration

Multi-gas options for confined space entry.

Sensors may be damaged by shock or vibration.

Loss of sensitivity when exposed to paint, lacquer, or varnish vapors.

Thermal Conductivity

1 2.5% VOL 0-100% VOL Vacuum pump Hand aspiration

Multi-gas capability.

Exposure to high concentrations may saturate the sensor.

Amplified Thermal Conductivity

1 5 ppm 5-1,000 ppm Vacuum pump Fast response. Zero stability dependent on temperature and moisture.

Temperature change, dust, moisture may cause false detection.

Semiconductor 2 1-100 ppmb 0-1,000 ppm Diffusion Fast response. Zero stability dependent on temperature and moisture.

Can be damaged by water.





TABLE 2 – AVAILABLE PROPANE GAS DETECTION TECHNOLOGIES (Continued)


Sensitivitya Rangea Sampling Method Advantages Limitations

Flame Ionization 2 1 ppm 0-10,000 ppm Vacuum pump Fast response. Vacuum pump system will draw residual gas from soil surface or cavity.

Venturi draw systems are slower responding.

Will detect all volatile organic compounds (VOCs) unless special filters are used.

Requires external hydrogen fuel.

Calibration affected by temperature and humidity.

High concentration gas will cause sensor flame out.

Requires warm-up time to become stable.

Should be used in conjunction with a barhole device and a soil sample probe.

Notes: (a) Specifications represent typical performance levels of the technology and implementation approach. Actual instrument specifications and performance may vary by manufacturer and product. (b) Varies widely by manufacturer.





Applications Key

1. Leak investigation and classification. Typical instrument requirements are to measure percent gas or LEL to classify the severity of a leak. Instruments are typically rated “Intrinsically Safe.” Typical measurement may be taken within a barhole or in the air of an area with a known leak.

2. Barhole leak survey. Typical instruments are to measure very low concentration levels with fast responding sensors. Typical measurements are taken while using a barhole device and soil sample probe along the main or services.

Definitions

Catalytic: Catalytic works on the basis that gas molecules will combust when coming into contact with a heated platinum wire (coated with a catalytic material). The catalytic material will accelerate the oxidation reaction, thus raising the temperature of the platinum wire. As the platinum wire heats up, the change in resistance is measured. The amount of resistance change is proportional to the gas concentration. Typically, two sensor beads are used (sample and reference).

Thermal Conductivity:

Thermal conductivity works on the basis of passing a sample of gas over a heated thermistor. The thermistor will change resistance relative to the thermal conductivity of the gas. A reference thermistor is normally used to generate a relative comparison. The resistance change is proportional to the gas concentration.

Amplified Thermal Conductivity: Amplified thermal conductivity is the same principle as Thermal Conductivity, but with additional electronic amplification to increase the response signal.

Semiconductor: Semiconductor sensors work on the basis that a tin dioxide (SnO2) material (when heated to a specific temperature (e.g., at 400°C) for hydrocarbon detection) will change resistance as it interacts with the gas. The resistance change is non-proportional to gas concentration.

Flame Ionization: Flame ionization works on the basis that gas molecules are positively charged by burning in a high temperature hydrogen flame. The ions are then collected on an electrode. The rate of charged particles collected is proportional to the gas concentration.





TABLE 3a -- LEAK CLASSIFICATION AND ACTION CRITERIA - GRADE 1


1 A leak that represents an existing or probable hazard to persons or property, and requires immediate repair or continuous action until the conditions are no longer hazardous. See §192.703(c).

Requires prompt action* to protect life and property, and continuous action until the conditions are no longer hazardous. *The prompt action in some instances may require one or more of the following. a. Implementation of emergency plan (§192.615). b. Evacuating premises. c. Blocking off an area. d. Rerouting traffic. e. Eliminating sources of ignition. f. Venting the area. g. Stopping the flow of gas by closing valves or other means. h. Notifying police and fire departments.

1. Any leak which, in the judgment of operating personnel at the scene, is regarded as an immediate hazard. 2. Escaping gas that has ignited. 3. Any indication of gas which has migrated into or under a building, or into a tunnel. 4. Any reading at the outside wall of a building, or where gas would likely migrate to an outside wall of a building. 5. Any reading of 60% LEL, or greater, in a confined space. 6. Any reading of 60% LEL, or greater in small substructures (other than gas associated substructures) from which gas would likely migrate to the outside wall of a building. 7. Any leak that can be seen, heard, or felt, and which is in a location that may endanger the general public or property.





TABLE 3b - LEAK CLASSIFICATION AND ACTION CRITERIA - GRADE 2


2 A leak that is recognized as being non-hazardous at the time of detection, but justifies scheduled repair based on probable future hazard.

Leaks should be repaired or cleared within one calendar year, but no later than 15 months from the date the leak was reported. In determining the repair priority, criteria such as the following should be considered. a. Amount and migration of gas. b. Proximity of gas to buildings and subsurface structures. c. Extent of pavement. d. Soil type, and soil conditions, such as frost cap, moisture and natural venting. Grade 2 leaks may vary greatly in degree of potential hazard. Some Grade 2 leaks, when evaluated by the above criteria, may justify scheduled repair within the next 5 working days. During the working day on which the leak is discovered, these situations should be brought to the attention of the individual responsible for scheduling leak repair. On the other hand, many Grade 2 leaks, because of their location and magnitude, can be scheduled for repair on a normal routine basis with periodic reinspection as necessary. Grade 2 leaks should be reevaluated at least once every 3 months until cleared. The frequency of reevaluation should be determined by the location and magnitude of the leakage condition.

A. Leaks Requiring Action Ahead of Ground Freezing or Other Adverse Changes in Venting Conditions. Any leak which, under frozen or other adverse soil conditions, would likely migrate to the outside wall of a building. B. Leaks Requiring Action Within Six Months. 1. Any reading of 40% LEL, or greater, under a sidewalk in a wall-to-wall paved area that does not qualify as a Grade 1 leak. 2. Any reading of 100% LEL, or greater, under a street in a wall-to-wall paved area that has significant gas migration and does not qualify as a Grade 1 leak. 3. Any reading less than 60% LEL in small substructures (other than gas associated substructures) from which gas would likely migrate creating a probable future hazard. 4. Any reading less than 60% LEL in a confined space. 5. Any reading on a pipeline operating at 30 percent SMYS, or greater, in a class 3 or 4 location, which does not qualify as a Grade 1 leak. 6. Any reading of 80% LEL, or greater, in gas associated substructures. 7. Any leak which, in the judgment of operating personnel at the scene, is of sufficient magnitude to justify scheduled repair.





TABLE 3c - LEAK CLASSIFICATION AND ACTION CRITERIA - GRADE 3


3 A leak that is non-hazardous at the time of detection and can be reasonably expected to remain non-hazardous. Because petroleum gas is heavier than air and will collect in low areas instead of dissipating, few leaks can safely be classified as Grade 3.

These leaks should be rechecked within 3 months of date reported to substantiate the grading. Thereafter, these leaks should be reevaluated during the next scheduled survey, or within 15 months of the date reported, whichever occurs first, until the leak is regraded or no longer results in a reading.

Leaks Requiring Reevaluation at Periodic Intervals 1. Any reading of less than 80% LEL in small gas associated substructures. 2. Any reading under a street in areas without wall-to-wall paving where it is unlikely the gas could migrate to the outside wall of a building.





GUIDE MATERIAL APPENDIX G-192-15A (See guide material under §§192.319 and 192.361)

HORIZONTAL DIRECTIONAL DRILLING (HDD) FOR STEEL PIPELINES

Note: Guide material for HDD using plastic pipe is in Guide Material Appendix G-192-15B. 1 SCOPE

This guide material provides information for planning, design, and installation where using horizontal directional drilling (HDD) for both transmission and distribution steel pipelines. It is general in nature and contains references to recommended or standard practices. Specific stress calculations and other technical information are not included.

2 INTRODUCTION 2.1 Overview and background.

HDD has become the preferred method of many pipeline operators for the crossing of major rivers, roadways, and other construction obstacles. The benefits derived from HDD, and not opening a trench, include reduced environmental impact, minimal interference to surface traffic during construction, and pipeline protection in high surface-traffic areas after construction. Additional benefits are also realized in applications where surface and subsurface restoration costs are high.

2.2 Description of HDD.

The method typically uses a small diameter non-rotating drill stem to thrust-bore or jet-out a pilot hole that conforms to a crossing geometry. Next, back reaming is performed through the pilot hole (possibly, several passes may be required) to establish a diameter sufficient for the carrier pipe installation. The reamed hole should be somewhat in excess of the carrier pipe diameter. Drilling fluids are used to carry out spoil tailings, cool the drilling head, and help maintain the hole during drilling operations. The assembled and pre-tested pipe string is then pulled in to complete the operation.

3 PROJECT PLANNING 3.1 Rights-of-way.

To ensure adequate workspace and access, consideration should be given to the following. (a) Temporary work areas for the rig-side (drilling side) and pipe-side (pipe fabrication and testing

side) work areas. (b) Ingress and egress to site. (c) Title survey to determine previous land uses.

3.2 Design criteria.

Essential planning considerations are as follows. (a) Develop an accurate cross-sectional profile of the proposed site to determine the lowest

elevation for the pipeline to be installed. The profile should extend at least 300 feet beyond the proposed entry and exit points.

(b) Determine the type of sub-soil to be encountered in the installation. If there is insufficient soil information available for the site, soil borings or seismic studies are recommended. Numerous soil borings may be necessary if gravel, boulders, or rocks are encountered. A minimum of two bores should be made at each side of a creek or waterway crossing.

(c) Perform a hydrographic survey to determine the bottom profile of the waterway.



Documents

American National Standards InstitutePaul Cabot, C.G.E. GPTC Secretary (202) 824-7312 Fax (202) 824-9122 [email protected] October 20, 2011 Dear Guide Purchaser, Enclosed is Addendum