Paul Cabot, C.G.E. GPTC Secretary (202) 824-7312 Fax (202) 824 … · 2019. 12. 19. · Paul Cabot, C.G.E. GPTC Secretary (202) 824-7312 Fax (202) 824-9122 [email protected] January

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

Fax (202) 824-9122 [email protected]

January 4, 2010 Dear Guide Purchaser, Enclosed is Addendum 2 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 "ANSI/GPTC Z380:2009 ...". Click here to purchase the full version from the ANSI store.

https://webstore.ansi.org/Standards/AGA/ANSIGPTCZ3802009Add?source=preview

B L A N K



GPTC GUIDE FOR GAS TRANSMISSION AND DISTRIBUTION PIPING SYSTEMS

2009 EDITON

ADDENDUM 2, September 2009

The changes in this addendum are marked by wide vertical lines inserted to the left of modified text, overwriting the left border of most tables, and use of a block symbol ( ▌) where needed. The Federal Regulations were updated by one amendment action that affected one section of the Guide, being §192.7. Seven (7) GPTC transactions affected 12 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 affected 12 sections of the guide. The following table shows the affected sections, the pages to be removed, and their replacement pages.



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

Guide Section Reason For Change Pages to be Removed Replacement Pages Title Page EU i/ii i/ii Table of Contents EU vii/viii, ix/x vii/viii, ix/x Historical Record of Amendments to Part 192

RIN 2137-AE42, DFR Confirmation

lv/lvi thru lxv/lxvi lv/lvi thru lxv/lxvi

Membership List EU Part 191 191.23 TR06-15 9/10 9/10 Subpart A 192.3 EU 17/18, 19/20 17/18, 19/20 192.7 EU, RIN 2137-AE42 27/28 27/28 SubpartB 192.53 EU (TR08-09) 41/42 41/42 192.55 GMUR (TR09-10) Subpart C 192.121 EU (TR09-05) 59/60, 61/62 59/60, 61/62 Subpart D 192.143 TR07-16 67/68 67/68 Subpart E 192.227 GMUR (TR09-11) 109/110 thru 113/114 109/110 thru 113/114 192.229 GMUR (TR09-11) 192.241 GMUR (TR09-11) Subpart I 192.476 TR07-16 189/190 thru 193/194 189/190 thru 193/194 Subpart L 192.614 EU 231/232 231/232 192.617 TR06-15 249/250 thru 253/254 249/250 thru 253/254 Subpart O 192.933 TR04-48 357/358 thru 361/362 357/358 thru 361/362 192.947 TR07-13 375/376, 377/378 375/376, 377/378 192.949 TR04-48 Guide G-192-1 Material Appendix

TR07-16 419/420 thru 423/424, 430(a)/430(b)

419/420 thru 423/424, 430(a)/430(b)

G-192-13 TR06-16 551/552, 553/554 551/552, 553/554 G-192-17 TR07-13 569/570 thru 573/574 569/570 thru

573(b)/574



i

Guide for Gas Transmission

and Distribution Piping

Systems

2009 Edition

Addendum 2, September 2009

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) December 2, 2009

ANSI/GPTC Z380.1-2009, Addendum No.2-2009

Catalog Number: Z3801092



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 2009 THE AMERICAN GAS ASSOCIATION

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

All Rights Reserved Printed in U.S.A.




Addendum 2, September 2009 vii

192.459 External corrosion control: Examination of buried pipeline when exposed ............ 173 192.461 External corrosion control: Protective coating ......................................................... 174 192.463 External corrosion control: Cathodic protection ...................................................... 175 192.465 External corrosion control: Monitoring ..................................................................... 176 192.467 External corrosion control: Electrical isolation ......................................................... 181 192.469 External corrosion control: Test stations ................................................................. 184 192.471 External corrosion control: Test leads ..................................................................... 184 192.473 External corrosion control: Interference currents .................................................... 185 192.475 Internal corrosion control: General .......................................................................... 186 192.476 Internal corrosion control: Design and construction of transmission line ............... 189 192.477 Internal corrosion control: Monitoring .................................................................. 190(d) 192.479 Atmospheric corrosion control: General .................................................................. 191 192.481 Atmospheric corrosion control: Monitoring .............................................................. 192 192.483 Remedial measures: General.................................................................................. 193 192.485 Remedial measures: Transmission lines ................................................................ 193 192.487 Remedial measures: Distribution lines other than cast iron or ductile iron lines .............................................................................................. 195 192.489 Remedial measures: Cast iron and ductile iron pipelines ....................................... 196 192.490 Direct assessment ................................................................................................... 197 192.491 Corrosion control records ........................................................................................ 197 SUBPART J -- TEST REQUIREMENTS .......................................................................................... 199 192.501 Scope ....................................................................................................................... 199 192.503 General requirements .............................................................................................. 199 192.505 Strength test requirements for steel pipeline to operate at a hoop stress of 30 percent or more of SMYS ................................................. 200 192.507 Test requirements for pipelines to operate at a hoop stress less than 30 percent of SMYS and at or above 100 p.s.i. (689 kPa) gage ................... 203 192.509 Test requirements for pipelines to operate below 100 p.s.i. (689 kPa) gage ......... 203 192.511 Test requirements for service lines ......................................................................... 204 192.513 Test requirements for plastic pipelines .................................................................... 204 192.515 Environmental protection and safety requirements................................................. 205 192.517 Records .................................................................................................................... 208 SUBPART K -- UPRATING .............................................................................................................. 209 192.551 Scope ....................................................................................................................... 209 192.553 General requirements .............................................................................................. 209 192.555 Uprating to a pressure that will produce a hoop stress of 30 percent or more of SMYS in steel pipelines .............................................. 211 192.557 Uprating: Steel pipelines to a pressure that will produce a hoop stress less than 30 percent of SMYS: plastic, cast iron, and ductile iron pipelines ......... 213 SUBPART L -- OPERATIONS .......................................................................................................... 217 192.601 Scope ....................................................................................................................... 217 192.603 General provisions ................................................................................................... 217 192.605 Procedural manual for operations, maintenance, and emergencies ...................... 218 192.607 (Removed and reserved) ......................................................................................... 226 192.609 Change in class location: Required study ............................................................... 226 192.611 Change in class location: Confirmation or revision of maximum allowable operating pressure ........................................................ 226




Addendum 1, May 2009 viii

192.612 Underwater inspection and re-burial of pipelines in the Gulf of Mexico and its inlets .................................................................................................... 228 192.613 Continuing surveillance ........................................................................................ 229(a) 192.614 Damage prevention program ................................................................................... 231 192.615 Emergency plans ..................................................................................................... 237 192.616 Public awareness ..................................................................................................... 247 192.617 Investigation of failures ............................................................................................ 250 192.619 Maximum allowable operating pressure: Steel or plastic pipelines ........................ 252 192.620 Alternative maximum allowable operating pressure for certain steel pipelines ...... 254 192.621 Maximum allowable operating pressure: High-pressure distribution systems ........................................................................................ 262 192.623 Maximum and minimum allowable operating pressure: Low-pressure distribution systems ........................................................................................ 263 192.625 Odorization of gas .................................................................................................... 263 192.627 Tapping pipelines under pressure ........................................................................... 266 192.629 Purging of pipelines ................................................................................................. 268 SUBPART M -- MAINTENANCE ....................................................................................................... 269 192.701 Scope ....................................................................................................................... 269 192.703 General .................................................................................................................... 269 192.705 Transmission lines: Patrolling .................................................................................. 273 192.706 Transmission lines: Leakage surveys ..................................................................... 274 192.707 Line markers for mains and transmission lines....................................................... 275 192.709 Transmission lines: Record keeping ....................................................................... 276 192.711 Transmission lines: General requirements for repair procedures .......................... 276 192.713 Transmission lines: Permanent field repair of imperfections and damages .......... 277 192.715 Transmission lines: Permanent field repair of welds .............................................. 279 192.717 Transmission lines: Permanent field repair of leaks ............................................... 280 192.719 Transmission lines: Testing of repairs ..................................................................... 280 192.721 Distribution systems: Patrolling................................................................................ 281 192.723 Distribution systems: Leakage surveys .................................................................. 282 192.725 Test requirements for reinstating service lines ....................................................... 284 192.727 Abandonment or deactivation of facilities ................................................................ 284 192.729 (Removed) ............................................................................................................... 288 192.731 Compressor stations: Inspection and testing of relief devices ................................ 288 192.733 (Removed) ............................................................................................................... 288 192.735 Compressor stations: Storage of combustible materials ........................................ 288 192.736 Compressor stations: Gas detection ....................................................................... 289 192.737 (Removed) ............................................................................................................... 289 192.739 Pressure limiting and regulating stations: Inspection and testing ........................... 289 192.741 Pressure limiting and regulating stations: Telemetering or recording gauges ....... 292 192.743 Pressure limiting and regulating stations: Capacity of relief devices ...................... 294 192.745 Valve maintenance: Transmission lines .................................................................. 295 192.747 Valve maintenance: Distribution systems ............................................................... 296 192.749 Vault maintenance ................................................................................................... 297 192.751 Prevention of accidental ignition .............................................................................. 299 192.753 Caulked bell and spigot joints .................................................................................. 302 192.755 Protecting cast-iron pipelines................................................................................... 303 192.761 (Removed) ............................................................................................................... 303




Addendum 2, September 2009 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)? ...................................................................................... 353 192.929 What are the requirements for using Direct Assessment for Stress Corrosion Cracking (SCCDA)? ...................................................................... 355 192.931 How may Confirmatory Direct Assessment (CDA) be used? ................................. 356 192.933 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? .................................................................... 377 192.951 Where does an operator file a report? .................................................................... 378 SUBPART P – GAS DISTRIBUTION PIPELINE INTEGRITY MANAGEMENT (IM) ..................... 379 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




Addendum 1, May 2009 x

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-191-4 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 Guide Material Appendix G-192-15 Design of uncased pipeline crossings of highways and railroads ....................................... 557 Guide Material Appendix G-192-15A Horizontal directional drilling (HDD) for steel pipelines ................................................ 561 Guide Material Appendix G-192-15B Horizontal directional drilling (HDD) for plastic pipe ................................................ 564(a) Guide Material Appendix G-192-16 Substructure damage prevention guidelines .............. 565 Guide Material Appendix G-192-17 Explicit requirements for reports, inspections, tests, written procedures, records and similar actions ............................................. 569 Guide Material Appendix G-192-18 Cast iron pipe .............................................................. 575




Addendum 2, September 2009 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.

[No Amdt No.]

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

[No Amdt No.]

Polyamide-11 (PA-11) Plastic Pipe Design Pressures

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

01/23/09 121, 123

[No Amdt No.]

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

[No Amdt No.]

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 2, September 2009 lvi

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.

[No Amdt No.]

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

04/14/09 7

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




Addendum 2, September 2009 lvii

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 Operation and Maintenance: O&M

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

Affonso, Joaquin J. Consumers Energy, Jackson, MI X X X X X

Amick, Patrick M. Marathon Oil Co., Houston, TX X X

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

Ashcraft, Nicholas D. Mears Group, Columbus, OH X X

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

X

Beaver, Brett Advantica, Mechanicsburg, PA 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 2, September 2009 lviii

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

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

Booth, Lloyd E. Telemark Solutions, Coppell, TX X X X

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

Breaux, David A. BROEN, Inc., Birmingham, AL X X X

Brown, Charles E. NTH Consultants, Ltd., Lansing, MI X X X

Bryce, Wayne CINA Corporation, Mahwah, NJ X X X

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

Butler, John Equitable Resources, Charleston, WV X X X

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




Addendum 2, September 2009 lix



M

ain Body

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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 Energy Experts International, Neptune, NJ X X X

Carpenter, Robert Southern California Gas Co., San Diego, CA X X X

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

Clarke, Allan M. Spectra Energy Corp., Houston, TX X X X 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 2, September 2009 lx



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istribution

M

anufacturers

Transm

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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

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

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

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

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

Friend, Mary S. Columbia Gas Trmn. Corp., Charleston, WV X X X X

Fuller, William R., Jr. Xcel Energy Inc., Denver, CO X X X X

Galante, Julie CYCLA Corp., Oakton, VA X X

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




Addendum 2, September 2009 lxi



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istribution

M

anufacturers

Transm

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esign

D

P/ER

IM

P/Corrosion

O

&M

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Plastic Pipe

Editorial

Executive

Liaison

R

egulations

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

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

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

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

Hazelden, Glyn Hazelden Group, Oak Park, IL X X X

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

1ST V Chair Chair

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

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




Addendum 2, September 2009 lxii



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istribution

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Transm

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esign

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P/ER

IM

P/Corrosion

O

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/OQ

Plastic Pipe

Editorial

Executive

Liaison

R

egulations

Koym, Brent L. CenterPoint Energy, Pearl, MS X X X

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

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

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

Lomax, George S. Heath Consultants Inc., Houston, TX X X X X

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

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

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

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

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




Addendum 2, September 2009 lxiii



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esign

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P/ER

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P/Corrosion

O

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Plastic Pipe

Editorial

Executive

Liaison

R

egulations

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

Modha, Kirit S. Iroquois Gas Transmission System, Shelton, CT X X

Myers, Clyde A. DOT-PHMSA, Washington, DC X X

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

Nichols, Danny Energy Transfer Company, Houston, TX 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 X X X

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

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

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




Addendum 2, September 2009 lxiv



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esign

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P/ER

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Plastic Pipe

Editorial

Executive

Liaison

R

egulations

Quezada, Leticia Nicor Gas, Naperville, IL X X X X X Chair

Reynolds, Donald Lee NiSource Corporate Services, Columbus, OH X X Chair X X

Schmidt, Robert A. Hackney Ladish Inc., Russellville, AR X Chair X X

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

Schrunk, Rex Wilbros Engineers, Inc., Kansas City, MO X X X

Seamands, Patrick A. Laclede Gas Co., Saint Louis, MO X X X X

Sher, Philip Philip Sher Consultants, Cheshire, CT

2nd V Chair X

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

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

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




Addendum 2, September 2009 lxv



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esign

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P/ER

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O

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Plastic Pipe

Editorial

Executive

Liaison

R

egulations

Themig, Jerome S. Ameren Illinois Utilities, Pawnee, IL X X 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 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. Consultant Engineer, Barnstable, MA X X X X X

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

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

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




Addendum 2, September 2009 lxvi



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esign

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P/ER

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P/Corrosion

O

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Plastic Pipe

Editorial

Executive

Liaison

R

egulations

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

X X X

Yehle, Steve Excel Energy, St. Paul, MN X X



GPTC GUIDE FOR GAS TRANSMISSION AND §191.23 DISTRIBUTION SYSTEMS: 2009 Edition

Addendum 2, September 2009

9

directly or indirectly by remedial action of the operator), for purposes other than abandonment, a 20 percent or more reduction in operating pressure or shutdown of operation of a pipeline or an LNG facility that contains or processes gas or LNG. (b) A report is not required for any safety-related condition that- (1) Exists on a master meter system or a customer-owned service line; (2) Is an incident or results in an incident before the deadline for filing the safety-related condition report; (3) Exists on a pipeline (other than an LNG facility) that is more than 220 yards (200 meters) from any building intended for human occupancy or outdoor place of assembly, except that reports are required for conditions within the right-of-way of an active railroad, paved road, street, or highway; or (4) Is corrected by repair or replacement in accordance with applicable safety standards before the deadline for filing the safety-related condition report, except that reports are required for conditions under paragraph (a)(1) of this section other than localized corrosion pitting on an effectively coated and cathodically protected pipeline. [Issued by Amdt. 191-6, 53 FR 24942, July 1, 1988 with Amdt. 191-6 Correction, 53 FR 26560, July 13, 1988; Amdt. 191-14, 63 FR 37500, July 13, 1998]

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

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

(b) See Guide Material Appendix G-191-6 for a chart useful in determining if reports must be filed. (c) See guide material under §192.617 for failure investigation, when applicable.

§191.25 Filing safety-related condition reports.

[Effective Date: 04/26/96]

(a) Each report of a safety-related condition under §191.23(a) must be filed (received by the Associate Administrator, OPS) in writing within five working days (not including Saturday, Sunday, or Federal holidays) after the day a representative of the operator first determines that the condition exists, but not later than 10 working days after the day a representative of the operator discovers the condition. Separate conditions may be described in a single report if they are closely related. Reports may be transmitted by facsimile at (202) 366-7128. (b) The report must be headed "Safety-Related Condition Report" and provide the following information: (1) Name and principal address of operator. (2) Date of report. (3) Name, job title, and business telephone number of person submitting the report. (4) Name, job title, and business telephone number of person who determined that the condition exists. (5) Date condition was discovered and date condition was first determined to exist. (6) Location of condition, with reference to the state (and town, city, or county) or offshore site, and as appropriate, nearest street address, offshore platform, survey station number, milepost, landmark, or name of pipeline. (7) Description of the condition, including circumstances leading to its discovery, any significant effects of the condition on safety, and the name of the commodity transported or stored.



GPTC GUIDE FOR GAS TRANSMISSION AND §191.25 DISTRIBUTION SYSTEMS: 2009 Edition

10

(8) The corrective action taken (including reduction of pressure or shutdown) before the report is submitted and the planned follow-up or future corrective action, including the anticipated schedule for starting and concluding such action. [Issued by Amdt. 191-6, 53 FR 24942, July 1, 1988 with Amdt. 191-6 Correction, 53 FR 26560, July 13, 1988 and Amdt. 191-6 Correction, 53 FR 29800, Aug. 8, 1988; Amdt. 191-7, 54 FR 32342, Aug. 7, 1989; Amdt. 191-8, 54 FR 40878, Oct. 4, 1989; Amdt. 191-10, 61 FR 18512, Apr. 26, 1996]

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

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

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

(b) See Guide Material Appendix G-191-7 for a form useful for reporting a safety-related condition. (c) Additional state requirements may exist for intrastate facilities.

§191.27 Filing offshore pipeline condition reports.

▌[Effective Date: 02/17/09]

(a) Each operator shall, within 60 days after completion of the inspection of all its underwater pipelines subject to §192.612(a), report the following information: (1) Name and principal address of operator. (2) Date of report. (3) Name, job title, and business telephone number of person submitting the report. (4) Total length of pipeline inspected. (5) Length and date of installation of each exposed pipeline segment, and location, including, if available, the location according to the Minerals Management Service or state offshore area and block number tract. (6) Length and date of installation of each pipeline segment, if different from a pipeline segment identified under paragraph (a)(5) of this section, that is a hazard to navigation, and the location, including, if available, the location according to the Minerals Management Service or state offshore area and block number tract. (b) The report shall be mailed to Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, Department of Transportation, Information Resources Manager, PHP-10, 1200 New Jersey Avenue SE, Washington, DC 20590-0001. [Issued by Amdt. 191-9, 56 FR 63764, Dec. 5, 1991; Amdt. 191-14, 63 FR 37500, July 13, 1998; RIN 2137-AD77, 70 FR 11135, Mar. 8, 2005; RIN 2137-AE29, 73 FR 16562, Mar. 28, 2008; RIN 2137-AE29 (#2), 74 FR 2889, Jan. 16, 2009]



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

Addendum 1, May 2009 17

GUIDE MATERIAL

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

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

maintained under Part 192. Abandonment is the process of abandoning a pipeline. Adhesive joint is a joint made in thermosetting plastic piping by the use of an adhesive substance that forms

a bond between the mating surfaces without dissolving either one of them. Ambient temperature is the temperature of the surrounding medium, usually used to refer to the temperature

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

Bell-welded pipe is furnace-welded pipe that has a longitudinal butt joint that is forge-welded by the mechanical pressure developed in drawing the furnace-heated skelp through a cone-shaped die. The die, commonly known as a "welding bell," serves as a combined forming and welding die. This type of pipe is produced in individual lengths from cut-length skelp. Typical specifications: ASTM A53, API Spec 5L. See also Furnace-butt-welded pipe and Pipe manufacturing processes.

Bottle is a gastight structure which is (1) completely fabricated by the manufacturer from pipe with integral drawn, forged, or spun end closures; and (2) tested in the manufacturer's plant. See also Bottle-type holder.

Bottle-type holder is any bottle or group of interconnected bottles installed in one location, and used for the sole purpose of storing gas. See also Bottle.

Carbon steel. By common custom, steel is considered to be carbon steel where (i) no minimum content is specified or required for aluminum, boron, chromium, cobalt, columbium, molybdenum, nickel, titanium, tungsten, vanadium, zirconium, or any other element added to obtain a desired alloying effect; (ii) the specified minimum content for copper does not exceed 0.40 percent; or (iii) the specified maximum content does not exceed 1.65 percent for manganese, 0.60 percent for silicon or 0.60 percent for copper.

All carbon steels may contain small quantities of unspecified residual elements unavoidably retained from raw materials. These elements (copper, nickel, molybdenum, chromium, etc.) are considered incidental and are not normally determined or reported.

Cast iron. The unqualified term cast iron applies to gray-cast iron that is a cast ferrous material in which a major part of the carbon content occurs as free carbon in the form of flakes interspersed through the metal.

Cold-expanded pipe is seamless or welded pipe which is formed and then, expanded in the pipe mill while cold, so that the circumference is permanently increased by at least 0.50 percent.

Continuous-welded pipe is furnace-welded pipe which has a longitudinal butt joint that is forge-welded by the mechanical pressure developed in rolling the hot-formed skelp through a set of round pass welding rolls. It is produced in continuous lengths from coiled skelp and subsequently cut into individual lengths. Typical specifications: ASTM A53, API Spec 5L. See also Furnace-butt-welded pipe and Pipe manufacturing processes.

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

Curb valve is a type of service-line valve installed for the purpose of shutting off gas supply. It is typically installed below grade at or near the property line.

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




Addendum 2, September 2009 18

District regulator station or district pressure regulating station is a pressure regulating station that controls pressure to a high- or low-pressure distribution main. It does not include pressure regulation whose sole function is to control pressure to a manifold serving multiple customers.

Double submerged-arc-welded pipe is a pipe having longitudinal or spiral butt joints. The joints are produced by at least two passes, including at least one each on the inside and on the outside of the pipe. Coalescence is produced by heating with an electric arc or arcs between the bare metal electrode or electrodes and the work. The welding is shielded by a blanket or granular, fusible material on the work. Pressure is not used and filler metal for the inside and outside welds is obtained from the electrode or electrodes. Typical specifications: ASTM A381, API Spec 5L. See also Pipe manufacturing processes.

Ductile iron (sometimes called nodular iron) is a cast ferrous material in which the free graphite present is in a spheroidal form rather than a flake form. The desirable properties of ductile iron are achieved by means of chemistry and a ferritizing heat treatment of the castings.

Electric-flash-welded pipe is pipe having a longitudinal butt joint wherein coalescence is produced, simultaneously over the entire area of abutting surfaces, by the heat obtained from resistance to the flow of electric current between the two surfaces, and by the application of pressure after heating is substantially completed. Flashing and upsetting are accompanied by the expulsion of metal from the joint. Typical specification: API Spec 5L. See also Pipe manufacturing processes.

Electric-fusion-welded pipe is pipe having a longitudinal butt joint wherein coalescence is produced in the preformed tube by manual or automatic electric-arc welding. The weld may be single or double and may be made with or without the use of filler metal. Typical specifications: ASTM A134, ASTM A139: Single or double weld is permitted with or without the use of filler metal. ASTM A671, ASTM A672, ASTM A691, and API Spec 5L: Requires both inside and outside welds and use of filler metal.

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

or a lock-seam joint. Typical specifications: ASTM A134, ASTM A139, and API Spec 5L: Butt joint. ASTM A211: Butt joint, lap joint, or lock-seam joint. See also Pipe manufacturing processes.

Electric-resistance-welded (ERW) pipe is pipe, which has a longitudinal butt joint wherein coalescence, is produced by the application of pressure and by the heat obtained from the resistance of the pipe to the flow of an electric current in a circuit of which the pipe is a part. It is produced in individual lengths or in continuous lengths from coiled skelp and subsequently cut into individual lengths. Typical specifications: ASTM A53, ASTM A135, and API Spec 5L. See also Pipe manufacturing processes.

Excess Flow Valve (EFV) is a device installed in a gas pipeline to automatically restrict or shut off the gas flow through the line when the flow exceeds a predetermined limit.

Excess Flow Valve-Bypass (EFVB) is an EFV that is designed to limit the flow of gas upon closure to a small, predetermined level. EFVBs reset automatically once the line downstream is made gastight and pressure is equalized across the valve.

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

Furnace-butt-welded pipe. There are two such types of pipe defined in this glossary: Bell-welded pipe and Continuous-welded pipe. See also Pipe manufacturing processes.

Furnace-lap-welded pipe is pipe that has a longitudinal lap joint that is produced by the forge welding process. In this process, coalescence is produced by heating a preformed tube to welding temperature and then passing it over a mandrel. The mandrel is located between the two welding rolls that compress and weld the overlapping edges. Typical specification: API Spec 5L. The manufacture of this type of pipe was discontinued, and the process was deleted from API Spec 5L in 1962. See also Pipe manufacturing processes.

Gas control is a person or persons who acquire and maintain data to remotely monitor and direct the flow of gas to meet design and contractual obligations, and to assist in detecting pipeline emergencies and initiating response.

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

Heat-fusion joint is a joint made in thermoplastic piping by heating the parts sufficiently to permit fusion of the materials when the parts are pressed together.

Holiday is a coating imperfection that exposes the pipe surface to the environment.





Holiday detection is testing of a coating for holidays using an instrument that applies a voltage between the external surface of the coating and the pipe.

Hoop stress is the stress in a pipe wall, acting circumferentially in a plane perpendicular to the longitudinal axis of the pipe, produced by the pressure of the fluid in the pipe. In this Guide, hoop stress in steel pipe is calculated by the formula:

Where: Sh = hoop stress, psi P = internal pressure, psig D = nominal outside diameter of pipe, inches t = nominal wall thickness, inches See also Maximum allowable hoop stress. Hot taps are connections made to transmission lines, mains, or other facilities while they are in operation.

The connecting and tapping is done while the facility is under gas pressure. Hydrostatic Design Basis (HDB) is one of a series of established stress values specified in ASTM D2837,

"Standard Test Method for Obtaining Hydrostatic Design Basis for Thermoplastic Pipe Materials or Pressure Design Basis for Thermoplastic Pipe Products," for a plastic compound, obtained by categorizing the long-term hydrostatic strength as determined in accordance with ASTM D2837.

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

Instrument piping is pipe, valves, and fittings used to connect instruments to main piping, to other instruments and apparatus, or to measuring equipment.

Iron. See Cast iron, Ductile iron, and Malleable iron. Jeeping is a method of Holiday detection. Joint. See Length. Lateral line (transmission). See guide material under §192.625. Leakage surveys are systematic inspections made for the purpose of finding leaks in a gas piping system.

The types of inspections commonly made are described in Guide Material Appendix G-192-11 "Gas Leakage Control Guidelines for Natural Gas Systems" and Guide Material Appendix G-192-11A "Gas Leakage Control Guidelines for Petroleum Gas Systems."

Length is a piece of pipe as delivered from the mill. Each piece is called a length regardless of its actual longitudinal dimension. While this is sometimes called a "joint," the term "length" is preferred.

Light surface oxide is a non-damaging form of corrosion. Long-term hydrostatic strength (LTHS) of plastic pipe is the estimated hoop stress, in psi, that would result in

a failure of the pipe if the pipe were subjected to 100,000 hours of hydrostatic pressure. Lower Explosive Limit (LEL) is the lower limit of flammability for a gas expressed as a percent, by volume, of

gas in air. Malleable iron is a mixture of iron and carbon, including small amounts of silicon, manganese, phosphorous

and sulfur which, after being cast, is converted structurally by heat treatment into primarily a matrix of ferrite containing nodules of tempered carbon.

Maximum allowable hoop stress is the maximum hoop stress permitted for the design of a piping system. It depends upon the material used, the class location of the pipe, and the operating conditions. See also Hoop stress.

Maximum allowable test pressure is the maximum internal fluid pressure permitted for testing, for the materials and class location involved.

Meters. See Customer meter and Meter set assembly. Meter set assembly is that exposed portion of the service line extending from the service line riser valve to

the connection of the customer’s fuel line, including the meter, and (if present) the regulator and relief vent line. In the absence of a service line riser valve, the meter set assembly starts at the first exposed fitting. The meter set assembly does not include the customer’s buried or exposed fuel line.

hS =PD2t




20

Monitoring regulator is a pressure regulator, set in series with another pressure regulator, for the purpose of providing automatic overpressure protection in the event of a malfunction of the primary regulator.

Nodular iron. See Ductile iron. Nominal outside diameter (D) is the outside diameter, in inches, as listed in Table 192.105i for nominal pipe

size 12 inches and less, and is the same as the nominal pipe size greater than 12 inches. It is used in the design formula for steel pipe in §192.105 and the calculation for hoop stress.

Nominal wall thickness (t) is the wall thickness, in inches, computed by, or used in, the design formula for steel pipe in §192.105. Pipe may be ordered to this computed wall thickness without adding an allowance to compensate for the under-thickness tolerances permitted in approved specifications.

Operating stress is the stress in a pipe or structural member under normal operating conditions. Overpressure protection is the use of a device or equipment installed for the purpose of preventing pressure

in a pipe system or other facility from exceeding a predetermined limit. See also Pressure limiting station, Pressure regulating station, Pressure relief station, and Service regulator.

Parallel encroachment pertains to that portion of the route of a transmission line or main that lies within, runs in a generally parallel direction to, and does not necessarily cross, the rights-of-way of a road, street, highway, or railroad.

Pipe. See Bell-welded pipe, Cold-expanded pipe, Continuous-welded pipe, Control piping, Double-submerged-arc-welded pipe, Electric-flash-welded pipe, Electric-fusion-welded pipe, Electric- resistance-welded pipe, Furnace-butt-welded pipe, Furnace-lap-welded pipe, Instrument piping, Length, Pipe-container, Pipe manufacturing processes, Pipe-type holder, Sample piping, and Seamless pipe.

Pipe-container is a gastight structure assembled from pipe and end closures. See also Pipe-type holder. Pipe manufacturing processes. A reference is ASME I00396 “History of Line Pipe Manufacturing in North

America.” Types and names of welded joints are used herein as defined in the American Welding Society (AWS) Publication A3.0 "Standard Welding Terms and Definitions" except for the following terms which are defined in this glossary.

Bell-welded pipe Continuous-welded pipe Double-submerged-arc-welded pipe Electric-flash-welded pipe Electric-fusion-welded pipe Electric-resistance-welded pipe Furnace-butt-welded pipe Furnace-lap-welded pipe Seamless pipe Pipe-type holder is any pipe-container or group of interconnected pipe-containers installed at one location for

the sole purpose of storing gas. See also Pipe-container. Plastic (noun) is a material that contains one or more organic polymeric substances of high molecular weight

as an essential ingredient, is solid in its finished state, and can be shaped by flow at some stage of its manufacture or processing into finished articles. The two general types of plastic referred to in this Guide are thermoplastic and thermosetting. See also Thermoplastic and Thermosetting plastic.

Plastic pipe joints. See Adhesive joint, Heat-fusion joint, and Solvent cement joint. Pressure (expressed in pounds per square inch above atmospheric pressure, i.e., gauge pressure

(abbreviation: psig), unless otherwise stated). See also Maximum allowable test pressure, Overpressure protection, Pressure limiting station, Pressure regulating station, Pressure relief station, and Standup pressure test.

Pressure limiting station consists of apparatus which, under abnormal conditions, will act to reduce, restrict or shut off the supply of gas flowing into a transmission line, main, holder, pressure vessel or compressor station piping in order to prevent the gas pressure from exceeding a predetermined limit. While normal pressure conditions prevail, the pressure limiting station may exercise some degree of control of the flow of gas or may remain in the wide-open position. Included in the station are any enclosures and ventilating equipment, and any piping and auxiliary equipment, such as valves, control instruments, or control lines.




27

Source and name of referenced material (Continued) 49 CFR reference (Continued)

(5) ASME B31.8S-2004 ‘‘Supplement to B31.8 on Managing System Integrity of Gas Pipelines.’’

§§192.903(c); 192.907(b); 192.911, Introductory text; 192.911(i); 192.911(k); 192.911(l); 192.911(m); 192.913(a) Introductory text; 192.913(b)(1); 192.917(a) Introductory text; 192.917(b); 192.917(c); 192.917(e)(1); 192.917(e)(4); 192.921(a)(1); 192.923(b)(2); 192.923(b)(3); 192.925(b) Introductory text; 192.925(b)(1); 192.925(b)(2); 192.925(b)(3); 192.925(b)(4); 192.927(b); 192.927(c)(1)(i); 192.929(b)(1); 192.929(b)(2); 192.933(a); 192.933(d)(1); 192.933(d)(1)(i); 192.935(a); 192.935(b)(1)(iv); 192.937(c)(1); 192.939(a)(1)(i); 192.939(a)(1)(ii); 192.939(a)(3); 192.945(a).

(6) ASME Boiler and Pressure Vessel Code, Section I, “Rules for Construction of Power Boilers,” (2004 edition, including addenda through July 1, 2005).

§192.153(a).

(7) ASME Boiler and Pressure Vessel Code, Section VIII, Division 1, ‘‘Rules for Construction of Pressure Vessels,’’ (2004 edition, including addenda through July 1, 2005).

§§192.153(a); 192.153(b); 192.153(d); 192.165(b)(3).

(8) ASME Boiler and Pressure Vessel Code, Section VIII, Division 2, ‘‘Rules for Construction of Pressure Vessels - Alternative Rules,’’ (2004 edition, including addenda through July 1, 2005).

§§192.153(b); 192.165(b)(3).

(9) ASME Boiler and Pressure Vessel Code, Section IX, ‘‘Welding and Brazing Qualifications,’’ (2004 edition, including addenda through July 1, 2005).

§§192.227(a); Item II, Appendix B.

E. Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS):

(1) MSS SP44–1996 (Reaffirmed; 2001) ‘‘Steel Pipe Line Flanges.’’

§192.147(a).

(2) [Reserved]. F. National Fire Protection Association (NFPA): (1) NFPA 30 (2003) ‘‘Flammable and Combustible Liquids Code.’’

§192.735(b).

(2) NFPA 58 (2004) ‘‘Liquefied Petroleum Gas Code (LP–Gas Code).’’

§§192.11(a); 192.11(b); 192.11(c).

(3) NFPA 59 (2004) ‘‘Utility LP-Gas Plant Code.” §§192.11(a); 192.11(b); 192.11(c). (4) NFPA 70 (2005) ‘‘National Electrical Code.’’ §§192.163(e); 192.189(c).





Source and name of referenced material (Continued) 49 CFR reference (Continued)

G. Plastics Pipe Institute, Inc. (PPI): (1) PPI TR–3/2004 (2004) ‘‘Policies and Procedures for Developing Hydrostatic Design Basis (HDB), Pressure Design Basis (PDB), Strength Design Basis (SDB), and Minimum Required Strength (MRS) Ratings for Thermoplastic Piping Materials or Pipe.”

§192.121.

H. NACE International (NACE): (1) NACE Standard RP0502–2002 ‘‘Pipeline External Corrosion Direct Assessment Methodology.’’

§§192.923(b)(1); 192.925(b) Introductory text; 192.925(b)(1); 192.925(b)(1)(ii); 192.925(b)(2) Introductory text; 192.925(b)(3) Introductory text; 192.925(b)(3)(ii); 192.925(b)(iv); 192.925(b)(4) Introductory text; 192.925(b)(4)(ii); 192.931(d); 192.935(b)(1)(iv); 192.939(a)(2).

I. Gas Technology Institute (GTI): (1) GRI 02/0057 (2002) ‘‘Internal Corrosion Direct Assessment of Gas Transmission Pipelines—Methodology.’’

§192.927(c)(2).

[Amdt. 192-37, 46 FR 10157, Feb. 2, 1981; Amdt. 192-51, 51 FR 15333, Apr. 23, 1986; Amdt. 192-68, 58 FR 14519, Mar. 18, 1993; Amdt. 192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996; Amdt. 192-94, 69 FR 32886, June 14, 2004 with Amdt. 192-94 Correction, 69 FR 54591, Sept. 9, 2004; RIN 2137-AD77, 70 FR 11135, Mar. 8, 2005; Amdt. 192-99, 70 FR 28833, May 19, 2005 with Amdt. 192-99 Correction, 70 FR 35041, June 16, 2005; Amdt. 192-102, 71 FR 13289, Mar.15, 2006; Amdt. 192-103, 71 FR 33402, June 9, 2006; Amdt. 192-103, 72 FR 4655, Feb. 1, 2007; RIN 2137-AE29, 73 FR 16562, Mar. 28, 2008; RIN 2137-AE25, 73 FR 62148, Oct. 17, 2008; RIN 2137-AE29 (#2), 74 FR 2889, Jan. 16, 2009; RIN 2137-AE42, 74 FR 17099, April 14, 2009 with RIN 2137-AE42 DFR Confirmation, 74 FR 30476, June 26, 2009]

GUIDE MATERIAL Additional standards and specifications recommended for use under this Guide, and the names and addresses of the sponsoring organizations, are shown in Guide Material Appendix G-192-1. See Guide Material Appendix G-192-1A for documents previously incorporated by reference in the Regulations.



GPTC GUIDE FOR GAS TRANSMISSION AND §192.51 DISTRIBUTION PIPING SYSTEMS: 2009 Edition SUBPART B


SUBPART B MATERIALS

§192.51 Scope.


This subpart prescribes minimum requirements for the selection and qualification of pipe and components for use in pipelines.

GUIDE MATERIAL

No guide material necessary.

§192.53 General.


Materials for pipe and components must be -- (a) Able to maintain the structural integrity of the pipeline under temperature and other environmental conditions that may be anticipated; (b) Chemically compatible with any gas that they transport and with any other material in the pipeline with which they are in contact; and (c) Qualified in accordance with the applicable requirements of this subpart.

GUIDE MATERIAL 1 FRACTURE TOUGHNESS REQUIREMENTS (a) Seam-welded steel pipe, 20 inches and larger in diameter and with SMYS of 52,000 psi or higher to

be installed in transmission lines to operate at 40 percent or more of SMYS and at operating pipe temperature less than 60 oF, should exhibit sufficient notch ductility at the operating pipe temperature. Compliance with either the Charpy impact or drop weight test criteria specified in SR5 or SR6 of API Spec 5L is sufficient evidence of such ductility when impact tests are made at or below the design pipe temperature.

(b) For special installations (e.g., compressor station piping and small replacement sections), the notch ductility should be determined by appropriate criteria, which may include those specified in SR5 or SR6.

(c) Notch ductility tests are not necessary on pipe for small special installations (e.g., new highway crossings and extensions of compressor station headers) where pipe to be installed (i) is on hand from earlier purchases to specifications at least equal to those applicable at the time of the original installation, or (ii) is a short portion of a larger order that exhibited adequate notch ductility.



GPTC GUIDE FOR GAS TRANSMISSION AND §192.53 DISTRIBUTION PIPING SYSTEMS: 2009 Edition SUBPART B


2 SOUR GAS COMPATIBILITY (a) See guide material under §192.475 for internal corrosion considerations. (b) NACE MR0175 contains guidelines for selecting materials for valves used in sour gas service. The

use of controlled hardness techniques and the use of alternate materials, as described in NACE MR0175, may be effective for other components in controlling sulfide stress cracking. The use of controlled hardness techniques should not be considered a solution to other problems involving H2S.

§192.55 Steel pipe.


(a) New steel pipe is qualified for use under this part if -- (1) It was manufactured in accordance with a listed specification; (2) It meets the requirements of -- (i) Section II of Appendix B to this part; or (ii) If it was manufactured before November 12, 1970, either section II or III of Appendix B to this part; or (3) It is used in accordance with paragraph (c) or (d) of this section. (b) Used steel pipe is qualified for use under this part if -- (1) It was manufactured in accordance with a listed specification and it meets the requirements of paragraph II-C of Appendix B to this part; (2) It meets the requirements of -- (i) Section II of Appendix B to this part; or (ii) If it was manufactured before November 12, 1970, either section II or III of Appendix B to this part; (3) It has been used in an existing line of the same or higher pressure and meets the requirements of paragraph II-C of Appendix B to this part; or (4) It is used in accordance with paragraph (c) of this section. (c) New or used steel pipe may be used at a pressure resulting in a hoop stress of less than 6,000 p.s.i. (41 MPa) where no close coiling or close bending is to be done, if visual examination indicates that the pipe is in good condition and that it is free of split seams and other defects that would cause leakage. If it is to be welded, steel pipe that has not been manufactured to a listed specification must also pass the weldability tests prescribed in paragraph II-B of Appendix B to this part. (d) Steel pipe that has not been previously used may be used as replacement pipe in a segment of pipeline if it has been manufactured prior to November 12, 1970, in accordance with the same specification as the pipe used in constructing that segment of pipeline. (e) New steel pipe that has been cold expanded must comply with the mandatory provisions of API Specification 5L. [Amdt. 192-3, 35 FR 17659, Nov. 17, 1970; Amdt. 192-12, 38 FR 4760, Feb. 22, 1973; Amdt. 192-51, 51 FR 15333, Apr. 23, 1986; Amdt. 192-68, 58 FR 14519, Mar. 18, 1993; Amdt. 192-85, 63 FR 37500, July 13, 1998]

GUIDE MATERIAL

This guide material is under review following Regulations update to §192.7 by RIN 2137-AE42. Listed specifications are shown in Section I of Appendix B. The user is cautioned that there may be more recent editions of some of these specifications than those approved and listed in Section I of Appendix B.



GPTC GUIDE FOR GAS TRANSMISSION AND 192.121 DISTRIBUTION PIPING SYSTEMS: 2009 Edition SUBPART C


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

S = For thermoplastic pipe, the HDB is determined in accordance with the listed specification at a temperature equal to 73 oF (23 oC), 100 oF (38 oC), 120 oF (49 oC), or 140 oF (60 oC). In the absence of an HDB established at the specified temperature, the HDB of a higher temperature may be used in determining a design pressure rating at the specified temperature by arithmetic interpolation using the procedure in Part D.2 of PPI TR-3/2004, HDB/PDB/SDB/MRS Policies (incorporated by reference, see §192.7). For reinforced thermosetting plastic pipe, 11,000 psig (75,842 kPa). [Note: Arithmetic interpolation is not allowed for PA-11 pipe.]

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

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

DF = 0.32 or = 0.40 for nominal pipe size (IPS or CTS) 4-inch or less, SDR-11 or greater (i.e., thicker pipe

wall), PA-11 pipe produced after January 23, 2009. [Amdt. 192-31, 43 FR 13880, Apr. 3, 1978 with Amdt. 192-31 Correction, 43 FR 43308, Sept. 25, 1978; Amdt. 192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-94, 69 FR 32886, June 14, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006; RIN 2137-AE26, 73 FR 79002, Dec. 24, 2008]

GUIDE MATERIAL 1 NATURAL GAS

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

(b) ASTM D2513 requires elevated temperature HDB listings for plastic piping materials used at temperatures above 73 °F. PPI publishes elevated temperature HDB values for PE and PA materials in TR-4.

(c) Magnetically-filled PE (reference ASTM D2513, Annex A.6) is considered as either PE 2406 or PE 3408 material.

(d) Long-term hydrostatic strength (LTHS) for reinforced thermosetting plastic covered by ASTM D2517 is 11,000 psi.

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

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





Pipe Material HDB @ 73 °F, psi

PA 32312 (PA 11) 2500

PE 2406 1250

PE 3408 1600

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

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

* Editions of ASTM D2513 issued after 2001 no longer permit use of PVC piping for new gas piping installations, but do specify that it may be used for repair and maintenance of existing PVC gas piping. The Regulations may continue to reference an edition of ASTM D2513 earlier than 2001. The operator is advised to check §192.7.

TABLE 192.121i

2 PETROLEUM GASES

PE and PA materials listed in ASTM D2513 may be used for liquid petroleum gas (LPG) piping applications. NFPA 58 (referenced by §192.7) prescribes the following:

(a) PA may be used in liquid or vapor LPG systems up to the design pressure of the piping material. PPI recommends a chemical derating factor of 1.0 (no derating) for PA 11 piping.

(b) PE, when recommended by the manufacturer, may be used in vapor-only LPG systems up to 30 psig pressure. PPI recommends a 0.5 chemical derating factor for the use of PE piping.

(c) PVC is not permitted.

Some information on the strengths of polyethylenes with propane is given in PPI TR-22, “Polyethylene Piping Distribution Systems for Components of Liquid Petroleum Gases.” See guide material under §192.123.

3 MINIMUM REQUIRED WALL THICKNESS The minimum wall thickness (tm) for a given design pressure is determined from the formula below. Also,

see §192.123(c) and (d) plus 3 of the guide material under §192.123. tm = PD (P + 0.64 S) Where: P = Design pressure, gauge, psi (kPa) D = Specified outside diameter, in. (mm) S = The long-term hydrostatic strength, for thermoplastic pipe, kPa (psi) determined at 73 oF

(23 oC), 100 oF (38 oC), 120 oF (49 oC), or 140 oF (60 oC); for reinforced thermosetting pipe, 11,000 psi (75,800 kPa)

4 INTERPOLATION OF HYDROSTATIC DESIGN BASIS (HDB) VALUES (a) For thermoplastic pipe that is to be installed at a service temperature greater than 73 ºF and less

than that at which the next HDB has been established, the HDB at the anticipated service temperature can be determined by interpolation. The pipe manufacturer should be consulted for assistance in determining an interpolated HDB.




61

)1 1(

)1 1)((

HL

TLHL

LT

TT

TTSS

SS−

−−−=

(b) The interpolation formula as prescribed in §192.121 is published in PPI TR-3 as follows. Where: ST = Interpolated LTHS for the anticipated service temperature (psi) SL = LTHS established at a temperature below the anticipated service temperature (psi) SH = LTHS established at a temperature above the anticipated service temperature (psi) TL = Temperature at which the lower LTHS (SL) was established (K) TT = Anticipated service temperature (K) TH = Temperature at which the higher LTHS (SH) was established (K) (c) Section 192.121 requires that the interpolation be made between the LTHS values at the lower and

higher temperatures. The resulting interpolated LTHS is categorized into an HDB. This interpolated HDB is then used to determine the design pressure under §192.121.

(d) Example:An operator is installing SDR 11 PE pipe where the anticipated service temperature is 78 ºF. HDB values are established and published in PPI TR-4 at 73 ºF (296 K) and 140 ºF (333 K). Thus, the operator has the option of establishing an interpolated HDB at the anticipated service temperature,

78 °F (299 K), or using the 140 °F HDB of 800 psi. (1) In order to calculate the HDB for the anticipated service temperature, the operator must obtain

the actual LTHS values established for the material at the nearest temperature above and below the temperature for which the interpolated value is to be determined. These values are typically available from the pipe supplier. If these LTHS values are not available, the lowest LTHS for the HDB category in Table 192.121ii may be used as a conservative estimate.

(2) Once the LTHS values are obtained, the interpolation calculation input is as follows. SL(73 °F) = 1567 psi SH(140 °F) = 845 psi TL = 73 ºF (295.93 K) TT = 78 ºF (298.71 K) TH = 140 ºF (333.15 K) Hence, the interpolation calculation determines that ST = 1506.86 psi or 1507 psi. (3) To determine the HDB at 78 ºF, the interpolated LTHS value is categorized using Table 1 from

ASTM Standard D 2837-04, a selection of which is shown in Table 192.121ii.

Range of Calculated LTHS Values Hydrostatic Design Basis (HDB) Psi (MPa) Psi (MPa)

600 to <760 (4.14 to <5.24) 630 (4.34)

760 to <960 (5.24 to <6.62) 800 (5.52)

960 to <1200 (6.62 to <8.27) 1000 (6.89)

1200 to <1530 (8.27 to <10.55) 1250 (8.62)

1530 to <1920 (10.55 to <13.24) 1600 (11.03)

TABLE 192.121ii





(4) Based upon an interpolated LTHS value of 1510 psi, the HDB to be used in the design formula for this example is 1250 psi.

For this SDR 11 PE pipe with an anticipated service temperature of 78 °F, the design pressure

is calculated in accordance with §192.121 using the interpolated HDB of 1250 psi as follows.

psigpsiSDR

SP 80)32(.)111(

)1250(2)32(.)1(

2=

−=

−=

5 REFERENCES (a) 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."

(b) PPI TR-22, "Polyethylene Piping Distribution Systems for Components of Liquid Petroleum Gases."

§192.123 Design limitations for plastic pipe.


(a) Except as provided in paragraph (e) and paragraph (f) of this section, the design pressure may not exceed a gauge pressure of 100 psig (689 kPa) for plastic pipe used in: (1) Distribution systems; or (2) Classes 3 and 4 locations. (b) Plastic pipe may not be used where operating temperatures of the pipe will be: (1) Below –20 oF (–29 oC), or –40 oF (–40 oC) if all pipe and pipeline components whose operating temperature will be below –20 oF (–29 oC) have a temperature rating by the manufacturer 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);



GPTC GUIDE FOR GAS TRANSMISSION AND §192.141 DISTRIBUTION PIPING SYSTEMS: 2009 Edition SUBPART D

67

SUBPART D DESIGN OF PIPELINE COMPONENTS

§192.141 Scope.


This subpart prescribes minimum requirements for the design and installation of pipeline components and facilities. In addition, it prescribes requirements relating to protection against accidental overpressuring.

GUIDE MATERIAL Useful industry references for design and construction of auxiliary piping for compressor stations or other similar installations (other than gas piping) are listed in Table 192.141i. Federal, state, and local requirements may also apply.

Piping System Fluid Design Code

Power piping (boiler external piping)

Air, steam, water, oil, gas, steam condensate

ASME B31.1

Power piping (non-boiler external piping)

Air, steam, water, oil, gas, steam condensate

ASME B31.3

Utility, auxiliary, process, air injection

Air, steam, water, oil, steam condensate, glycol, natural gas liquids

ASME B31.3

Process Hydrocarbons, chemicals ASME B31.3

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

Fire protection Water NFPA 14 and 24

Drinking and domestic supply Water AWWA Standards; Uniform Plumbing Code

Plumbing and drains Sanitary and waste water Uniform Plumbing Code

TABLE 192.141i

§192.143 General requirements.


(a) Each component of a pipeline must be able to withstand operating pressures and other anticipated loadings without impairment of its serviceability with unit stresses equivalent to those allowed for comparable material in pipe in the same location and kind of service. However, if design based upon unit stresses is impractical for a particular component, design may be based upon a



GPTC GUIDE FOR GAS TRANSMISSION AND §192.143 DISTRIBUTION PIPING SYSTEMS: 2009 Edition SUBPART D


pressure rating established by the manufacturer by pressure testing that component or a prototype of the component. (b) The design and installation of pipeline components and facilities must meet applicable requirements for corrosion control found in subpart I of this part. [Amdt. 192-48, 49 FR 19823, May 10, 1984; RIN 2137-AE09, 72 FR 20055, April 23, 2007]

GUIDE MATERIAL 1 GENERAL

The designer should select components that will withstand the field test pressure to which they will be subjected without failure or leakage and without impairment to their serviceability. Consideration should also be given to pulsation-induced vibrations that could produce excessive cyclic stresses.

See Guide Material Appendices G-192-9 and G-192-10. 2 CORROSION CONTROL

See guide material under §§192.453, 192.455, 192.461, 192.467, 192.469, 192.471, 192.473, 192.475, 192.476, 192.479, and 192.491.

§192.144 Qualifying Metallic Components.


Notwithstanding any requirement of this subpart which incorporates by reference an edition of a document listed in §192.7 or Appendix B of this part, a metallic component manufactured in accordance with any other edition of that document is qualified for use under this part if -- (a) It can be shown through visual inspection of the cleaned component that no defect exists which might impair the strength or tightness of the component; and (b) The edition of the document under which the component was manufactured has equal or more stringent requirements for the following as an edition of that document currently or previously listed in §192.7 or appendix B of this part: (1) Pressure testing; (2) Materials; and (3) Pressure and temperature ratings. [Issued by Amdt. 192-45, 48 FR 30637, July 5, 1983; Amdt. 192-94, 69 FR 32886, June 14, 2004]

GUIDE MATERIAL See Guide Material Appendix G-192-1A for documents previously incorporated by reference in the Regulations. Current documents incorporated by reference that were listed in Appendix A prior to Amendment 192-94, published June 14, 2004, are now found in §192.7. If the edition of the document under which the component was manufactured was neither previously listed nor currently listed in §192.7, and was not previously listed in Appendix A, then requirements under §192.144(b) should be reviewed to determine if the metallic component is qualified for use under Part 192.



GPTC GUIDE FOR GAS TRANSMISSION AND §192.221 DISTRIBUTION PIPING SYSTEMS: 2009 Edition Subpart E

109

SUBPART E WELDING OF STEEL IN PIPELINES

§192.221 Scope.


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

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

§192.223 (Removed.)


§192.225 Welding procedures.


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

GUIDE MATERIAL

Additional references for welding procedures include the following. (a) ASME B31.8, "Gas Transmission and Distribution Piping Systems."





(b) API Std 1104, "Welding of Pipelines and Related Facilities," Appendix B, "In-Service Welding.” Information on preheating and stress relieving of welded connections can be found in the above references. Preheating and stress relieving should be performed in accordance with the qualified welding procedure being used.

§192.227 Qualification of welders.


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

GUIDE MATERIAL

This guide material is under review following Regulations update to §192.7 by RIN 2137-AE42. It is the operator's responsibility to ensure that all welding is performed by qualified welders. The ability of welders to make sound welds should be determined by test welds using previously qualified welding procedures. The evaluation of test welds may be conducted by qualified operator personnel or testing laboratories.

§192.229 Limitations on welders.


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





weld tested and found acceptable under the sections 6 or 9 of API Standard 1104 (incorporated by reference, see §192.7). Alternatively, welders may maintain an ongoing qualification status by performing welds tested and found acceptable under the above acceptance criteria at least twice each calendar year, but at intervals not exceeding 7½ months. A welder qualified under an earlier edition of a standard listed in §192.7 of this part may weld but may not requalify under that earlier edition; and (2) May not weld on pipe to be operated at a pressure that produces a hoop stress of less than 20 percent of SMYS unless the welder is tested in accordance with paragraph (c)(1) of this section or requalifies under paragraph (d)(1) or (d)(2) of this section. (d) A welder qualified under §192.227(b) may not weld unless -- (1) Within the preceding 15 calendar months, but at least once each calendar year, the welder has requalified under §192.227(b); or (2) Within the preceding 7½ calendar months, but at least twice each calendar year, the welder has had -- (i) A production weld cut out, tested, and found acceptable in accordance with the qualifying test; or (ii) For welders who work only on service lines 2 inches (51 millimeters) or smaller in diameter, two sample welds tested and found acceptable in accordance with the test in section III of Appendix C of this part. [Amdt. 192-18, 40 FR 10181, Mar. 5, 1975 with Amdt. 192-18A, 40 FR 27222, June 27, 1975; Amdt. 192-37, 46 FR 10157, Feb. 2, 1981; Amdt. 192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-94, 69 FR 32886, June 14, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006]

GUIDE MATERIAL

This guide material is under review following Regulations update to §192.7 by RIN 2137-AE42. A welding "process" is one element of a welding "procedure." Processes commonly used in pipeline welding procedures include the following: (a) Shielded metal-arc. (b) Submerged arc. (c) Gas tungsten-arc. (d) Gas metal-arc. (e) Flux-cored arc. (f) Oxyacetylene. (g) Flash.

§192.231 Protection from weather.


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

GUIDE MATERIAL





112

§192.233 Miter joints.


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

GUIDE MATERIAL


§192.235 Preparation for welding.


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

GUIDE MATERIAL 1 BUTT WELDS Some acceptable end preparations are shown in Figures 192.235A and 192.235B of Guide Material

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

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

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

strength of the joint.




113

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

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

§192.237 (Removed.)


§192.239 (Removed.)


§192.241 Inspection and test of welds.


(a) Visual inspection of welding must be conducted by an individual qualified by appropriate training and experience to ensure that: (1) The welding is performed in accordance with the welding procedure; and (2) The weld is acceptable under paragraph (c) of this section. (b) The welds on a pipeline to be operated at a pressure that produces a hoop stress of 20 percent or more of SMYS must be nondestructively tested in accordance with §192.243, except that welds that are visually inspected and approved by a qualified welding inspector need not be nondestructively tested if -- (1) The pipe has a nominal diameter of less than 6 inches (152 millimeters); or (2) The pipeline is to be operated at a pressure that produces a hoop stress of less than 40 percent of SMYS and the welds are so limited in number that nondestructive testing is impractical. (c) The acceptability of a weld that is nondestructively tested or visually inspected is determined according to the standards in Section 9 of API Standard 1104 (incorporated by reference, see §192.7). However, if a girth weld is unacceptable under those standards for a reason other than a crack, and if Appendix A to API 1104 applies to the weld, the acceptability of the weld may be further determined under that appendix. [Amdt. 192-18, 40 FR 10181, Mar. 5, 1975 with Amdt. 192-18A, 40 FR 27222, June 27, 1975; Amdt. 192-37, 46 FR 10157, Feb. 2, 1981; Amdt. 192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-94, 69 FR 32886, June 14, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006]





GUIDE MATERIAL

This guide material is under review following Regulations update to §192.7 by RIN 2137-AE42. 1 VISUAL INSPECTION

The measures listed below should be performed at sufficient intervals to ensure good quality workmanship. Consideration should be given to nondestructively testing, repairing, or cutting out any weld with questionable acceptability under Section 9 of API Std 1104.

(a) Inspect the fit-up of a joint before the weld is made. (b) Visually inspect the stringer bead before subsequent beads are applied. Each bead inspected

should be examined for defects that may make the weld unacceptable, such as: (1) Incomplete fusion. (2) Slag inclusion. (3) Porosity. (4) Cracks. (c) Inspect the completed weld before coating. 2 INSPECTOR QUALIFICATIONS (a) In determining whether an individual has appropriate training and experience, consideration should

be given to the individual’s qualification examination results, if any, and welding education. (b) The documentation of inspector qualifications should be retained.

§192.243 Nondestructive testing.


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

(2) By persons who have been trained and qualified in the established procedures and with the equipment employed in testing.

(c) Procedures must be established for the proper interpretation of each nondestructive test of a weld to ensure the acceptability of the weld under §192.241(c). (d) When nondestructive testing is required under §192.241(b), the following percentages of each day's field butt welds, selected at random by the operator, must be nondestructively tested over their entire circumference: (1) In Class 1 locations, except offshore, at least 10 percent. (2) In Class 2 locations, at least 15 percent. (3) In Class 3 and Class 4 locations, at crossing of major or navigable rivers, offshore, and within railroad or public highway rights-of way, including tunnels, bridges, and overhead road crossings, 100 percent unless impracticable, in which case at least 90 percent. Nondestructive testing must be impracticable for each girth weld not tested. (4) At pipeline tie-ins, including tie-ins of replacement sections, 100 percent. (e) Except for a welder whose work is isolated from the principal welding activity, a sample of each welder's work for each day must be nondestructively tested, when nondestructive testing is required under §192.241(b). (f) When nondestructive testing is required under §192.241(b), each operator must retain, for the life of the pipeline, a record showing by milepost, engineering station, or by geographic feature, the number of girth welds made, the number nondestructively tested, the number rejected, and the disposition of the rejects.



GPTC GUIDE FOR GAS TRANSMISSION AND §192.475 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART I

189

(2) Treatments should be compatible with the following. (i) Gas being transported. (ii) Downstream gas utilization and processing equipment. (iii) Any other treatments. 6 REFERENCES (a) See 2 of the guide material under §192.53. (b) GRI-02/0057, “Internal Corrosion Direct Assessment of Gas Transmission Pipelines --

Methodology,” Oliver Moghissi, Bruce Cookingham, Lee Norris, Narasi Sridhar, and Phil Dusek. (c) NACE MR0175, “Materials for Use in H2S-Containing Environments in Oil and Gas Production.” (d) NACE RP0175, “Control of Internal Corrosion in Steel Pipelines and Piping Systems” (Revised

1975; Discontinued). (e) NACE RP0192, “Monitoring Corrosion in Oil and Gas Production with Iron Counts.” (f) NACE RP0775, “Preparation, Installation, Analysis, and Interpretation of Corrosion Coupons in

Oilfield Operations.” (g) NACE TM0194, “Field Monitoring of Bacterial Growth in Oilfield Systems.” (h) NACE 3D170, Technical Committee Report, “Electrical and Electrochemical Methods for

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

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

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

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

(m) “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.

(n) “Microscopic Differentiation of Internal Corrosion Initiation Mechanisms in a Natural Gas System,” Richard Eckert, Henry Aldrich, and Chris Edwards, Bruce Cookingham, Paper # 03544 presented at CORROSION/03 San Diego, CA.

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


(a) Design and construction. Except as provided in paragraph (b) of this section, each new transmission line and each replacement of line pipe, valve, fitting, or other line component in a transmission line must have features incorporated into its design and construction to reduce the risk of internal corrosion. At a minimum, unless it is impracticable or unnecessary to do so, each new transmission line or replacement of line pipe, valve, fitting, or other line component in a transmission line must: (1) Be configured to reduce the risk that liquids will collect in the line; (2) Have effective liquid removal features whenever the configuration would allow liquids to collect; and (3) Allow use of devices for monitoring internal corrosion at locations with significant potential for internal corrosion. (b) Exceptions to applicability. The design and construction requirements of paragraph (a) of





this section do not apply to the following: (1) Offshore pipeline; and (2) Pipeline installed or line pipe, valve, fitting or other line component replaced before May 23, 2007. (c) Change to existing transmission line. When an operator changes the configuration of a transmission line, the operator must evaluate the impact of the change on internal corrosion risk to the downstream portion of an existing onshore transmission line and provide for removal of liquids and monitoring of internal corrosion as appropriate. (d) Records. An operator must maintain records demonstrating compliance with this section. Provided the records show why incorporating design features addressing paragraph (a)(1), (a)(2), or (a)(3) of this section is impracticable or unnecessary, an operator may fulfill this requirement through written procedures supported by as-built drawings or other construction records. [Issued by RIN 2137-AE09, 72 FR 20055, Apr. 23, 2007]

Guide Material PIPELINES TRANSPORTING NORMALLY WET GAS

No guide material available at present. PIPELINES TRANSPORTING NORMALLY DRY GAS 1 GENERAL (a) In accordance with NACE SP0206, “Internal Corrosion Direct Assessment Methodology for

Pipelines Carrying Normally Dry Natural Gas (DG-ICDA),” the term “dry gas” is defined as gas above its dew point and without condensed liquids.

(b) In accordance with NACE SP0106, “Control of Internal Corrosion in Steel Pipelines and Piping Systems,” if liquid water is not present in the steel pipeline, corrosion will not occur. Section 192.476 uses the term “liquids” when the concern of internal corrosion pertains only to liquids that act as an electrolyte (liquid water). The regulation does not apply to other liquids, such as hydrocarbon drip or compressor oils that do not contain liquid water. The term “liquid water” will be used in the guide material.

(c) NACE SP0106 states that because of the complex nature and interaction between constituents (e.g., carbon dioxide, hydrogen sulfide) that are found in gas or liquid water, certain combinations of these impurities transported in the pipeline might affect whether a corrosion condition exists. Appendix A (non-mandatory) of this standard provides an example of a typical gas quality specification.

(d) The term “significant potential for internal corrosion” as used in §192.476(a)(3) means that the risk of internal corrosion is known to exist in like situations to the degree that the serviceability or the design life of the pipeline segment might be negatively affected.

2 DETERMINATION OF WHAT CONSTITUTES IMPRACTICABLE AND UNNECESSARY 2.1 Impracticable.

Examples of conditions that may make it impracticable to design and construct features to reduce the risk of internal corrosion include the following. For most of these examples, the operator should consider installing liquid water removal or monitoring devices at an upstream location feasible for installation.

(a) A low spot or angle created when a pipeline segment is bored in and where liquid water is expected to accumulate.

(b) Pipeline segments installed in casings in such a configuration that liquid water is expected to accumulate.

(c) Water crossings or where pipeline segments are installed in marshes.




Addendum 2, September 2009 190(a)

(d) Very deep pipelines or pipelines in extremely congested rights-of-way installed in a configuration where liquid water is expected to accumulate.

(e) Changes to compressor, meter, and regulator station facilities where there is limited space and access.

2.2 Unnecessary.

Examples of conditions that may make it unnecessary to design and construct features to reduce the risk of internal corrosion include the following.

(a) The operator transports: (1) Gasified LNG where no other source of supply or interconnect exists. This gas is very dry and

not capable of producing internal corrosion. (2) Gas that meets the typical gas quality specification in NACE SP0106, Appendix A. (3) Gas with a velocity such that impurities are kept suspended in the gas stream, minimizing the

accumulation of corrosive liquid. (b) The operator uses: (1) Chemicals (e.g., corrosion inhibitors, biocides) to mitigate the occurrence of internal

corrosion. (2) Moisture analyzers or liquid water removal devices upstream of the pipeline segment to

monitor for liquid water. (3) Gas quality monitoring upstream, provided that short-term upsets would be detected and

managed. (c) The operator installs: (1) In-kind replacement of pipe, valve, fitting, or other line components with no known internal

corrosion with like size and like configuration. For example, replacement of a small section of 24-inch pipe with 24-inch pipe, or replacement of a full-port ball valve with a full-port ball valve.

(2) Additions to meter stations or regulating stations, such as an additional meter run or addition of a relief valve.

(3) Pipe with no inclination angles exceeding the critical angle. See NACE SP0206. (4) Pipeline for a temporary operating period of service not to exceed 5 years beyond installation,

provided that the corrosion rate would not achieve a predicted failure pressure (PFP) below operating pressure in that time period.

(5) Pipeline in a normally dry gas system where short-term upsets would blend with a sufficient volume of dry gas to make the risk of internal corrosion negligible (e.g., buried below the frost line and away from large temperature differentials).

(6) Pipeline with no in-line pressure reducing devices that would precipitate the fall-out of liquid water into the pipe segment.

3 DESIGN CONSIDERATIONS 3.1 General. (a) The incorporation of design features to address internal corrosion improves the ability of the

operator to prevent internal corrosion and to perform maintenance activities to control internal corrosion. There are many design features that an operator can incorporate to address the risk of internal corrosion. See guide material under §192.475.

(b) To address the design requirements of reducing the risk of internal corrosion, an operator should address design features in the order of (1) configuration, (2) liquid removal, and then (3) monitoring.

(c) If the configuration of the pipeline is such that the risk that liquid water will collect is nonexistent or minimal, the operator may not need to design for liquid water removal or monitoring.

(d) If the configuration would allow liquid water to collect, the operator would be required to design for effective liquid water removal. Installation of these features would satisfy the requirements of the regulation and monitoring would not be required, provided a program for liquid water removal is instituted. Examples where liquid water could accumulate include the following.

(1) Sags. (2) Bases of inclines. (3) Valves.




Addendum 2, September 2009 190(b)

(4) Manifolds. (5) Dead-legs. (6) Traps. (e) Where liquid water is likely to collect, and the liquid water removal system is not provided or does

not effectively remove liquid water and there is significant potential for internal corrosion, devices for monitoring are required (see §192.476(a)(2)).

3.2 Configuration design. Examples of ways to reduce the risk that liquids will collect in a line include the following. (a) Minimize dead ends, such as pipe stubs downstream of stopple fittings, and low areas. (b) Minimize aerial crossings, since these can result in variation of temperature. (c) Design for turbulent flow, in which the velocity at a given point varies erratically in magnitude and

direction, to decrease the chance of liquid water separating from the flow stream and accumulating.

(d) Minimize the entry of water and corrosive gases at receipt locations. For example, liquid water removal devices (e.g., separators) at the inlet to compressor, meter, and regulator stations can protect station piping from the entry of liquid water.

(e) Provide slam valves to isolate systems when corrosive gas is expected. A “slam valve” is a shut-off valve that stops the flow of gas in the event that a predetermined criteria is met.

(f) Apply coatings to interior walls to inhibit internal corrosion. (g) Design for pigging. (h) Design for the injection of corrosion inhibitors. (i) Design with no inclination angles exceeding the critical angle at normal operating conditions (see

NACE SP0206) so that liquid water will not accumulate, because the gas velocity will carry the liquid water through the pipeline.

(j) On new pipelines with new receipt meters, design the configuration to accommodate equipment to monitor moisture and gas quality with control systems, such as slam valves or secondary liquid separation or dehydration equipment.

(k) Maintain a flow velocity sufficient to prevent corrosive liquids from dropping out of the gas stream. (l) Evaluate the seasonal nature of delivery and capacity patterns and design to avoid no-flow or

low-flow conditions. (m) Include equipment to evaluate gas quality characteristics (e.g., water, carbon dioxide, H2S,

oxygen). (n) Provide for blending, such that liquid water will be reabsorbed into the gas stream where there is

potential for liquid water to enter the line during upset conditions. (o) See NACE SP0106, Sections 3, 5, and 7 for internal corrosion design considerations. 3.3 Liquid removal. (a) Install equipment to allow liquid water sampling at key areas, such as pig traps, isolated sections

with no flow, dead ends, and river and road crossings. (b) Implement a pigging or sweeping program for cleaning of the pipeline so that if liquid water does

collect for a short period of time, the liquid water can be removed through pigging or sweeping at necessary intervals. “Sweeping” is a process in which the gas stream has a velocity high enough to move liquids downstream to a collection point.

(c) Install drips or other liquid water removal facilities along the pipeline where liquid water is expected to accumulate and implement a drip management program to blow drips and sample liquid water.

(d) See NACE SP0106, Sections 3, 5, and 7 for internal corrosion control methods. 3.4 Monitoring for internal corrosion. (a) Identify critical low spots and instrument the pipeline to monitor relevant operating conditions

(e.g., temperature, pressure, velocity, dew point) and implement a program to detect and manage short-term upsets.

(b) Install direct corrosion monitoring at points on the pipeline with significant potential for internal corrosion and implement a program for scheduled monitoring and analysis. For monitoring guidelines, see NACE 3T199, “Techniques for Monitoring Corrosion and Related Parameters in Field Applications.”




Addendum 2, September 2009 190(c)

(c) Implement a liquid water sampling and analysis program, and other indirect monitoring, to determine if there is a significant potential for internal corrosion. If liquid water is present in the system, analysis for CO2, H2S, bacteria (MIC), acids, and other corrosion constituents should be made. See NACE SP0106 and NACE 3T199 for monitoring guidelines.

(d) Use in-line inspection tools with a frequency based on corrosion rates and remaining wall thickness, similar to the requirements of an operator’s IMP. See NACE RP0102, “In-Line Inspection of Pipelines,” regarding design considerations for in-line inspection.

(e) See NACE SP0106, Sections 4, 6, and 7 for operating and maintenance of internal control systems.

4 CHANGE IN CONFIGURATION (a) The preamble to the regulation states that the “change in configuration” means changes in the

physical features of a pipeline. (b) The following are examples of changes to configuration. (1) A physical change that would compromise the effectiveness of liquid water removal features

downstream, such as the following. (i) Reversing flow. (ii) Removal of drips, launchers, receivers, or associated piping, valves, or vessels. (iii) Diameter changes. (iv) Installation of sharp radius bends, or other changes that would make a piggable line no

longer piggable. (v) Bypassing drips, slug catchers, or filters. (2) Adding potential sources of liquid water to the system that would change existing downstream

monitoring locations. (3) Abandonment or inactivation of a segment of pipeline. (4) Changes that would affect existing downstream internal corrosion mitigation systems by

changing volume or flow characteristics (e.g., extending the length of a pipeline, changing the diameter over a significant length).

(5) Changes of material (e.g., replacement of steel pipe with stainless steel pipe). (6) Other physical changes that would indicate a change in monitoring or internal corrosion

mitigation in downstream facilities. (c) If a configuration change occurs that increases the risk of internal corrosion, see 3.1 through 3.3. 5 RECORDS 5.1 Design features. (a) Documentation that the pipeline design features have addressed the impact of internal corrosion

may be provided in the operator’s project scope, design specifications, standards, or other documents deemed appropriate by the operator.

(b) Documentation that construction of these design features may be provided in the as-built records, which show that the project scope, design specifications, standards, or other applicable documents were followed.

(c) Records may be maintained electronically, as paper copies, or in any other appropriate format. 5.2 Configuration.

Where the operator has determined that the designed pipeline configuration is such that the risk of liquid water collecting is minimal (e.g., internal corrosion is unlikely to occur), the operator is required to document this determination and that the configuration was constructed as designed (see §192.476(d)). For example, if the pipeline diameter was designed so that the gas velocity is such that liquid water will not fall out of the gas stream, documents showing the determination that liquid water will not fall out and the designed pipe diameter was actually installed are necessary.




Addendum 2, September 2009 190(d)

5.3 Liquid removal features. Where the operator has determined that liquid water removal features are necessary, the operator will need to document this determination and that the features were installed (see §192.476(d)). For example, if the use of drips is determined to be necessary, the operator needs to document that determination and the related installation. The operator should document the location of each drip installed and the maintenance program for each drip.

5.4 Monitoring devices.

Where the operator has determined that monitoring is necessary at locations with significant potential for internal corrosion, the operator will need to document this determination and that the devices were installed (see §192.476(d)). The operator should also document the following.

(a) Location of equipment. (b) Sampling protocols. (c) Procedures for managing upsets. (d) Calibration process and intervals. 5.5 Documenting impracticable or unnecessary.

The operator is required to document when a design feature is impracticable or unnecessary (see §192.476(d)). The documentation would discuss reasons why it was impracticable or unnecessary to meet the specified design or construction requirements. This documentation may be filed in the operator’s design or as-built record system.

5.6 Changes to configuration.

When changing the configuration of a transmission line, the operator is required to document the impact of the change on internal corrosion risk to the downstream portion of an existing onshore transmission line (see §192.476(d)). This documentation may be filed in the operator’s design or as-built record system. See 5.3 and 5.4 above.

5.7 Retention. Records should be kept as long as the pipeline remains in service. 6 REFERENCES (a) NACE RP0102, “In-Line Inspection of Pipelines.” (b) NACE SP0106, “Control of Internal Corrosion in Steel Pipelines and Piping Systems.” (c) NACE SP0206, “Internal Corrosion Direct Assessment Methodology for Pipelines Carrying

Normally Dry Natural Gas (DG-ICDA).” (d) NACE 3T199, “Techniques for Monitoring Corrosion and Related Parameters in Field

Applications.”

§192.477 Internal corrosion control: Monitoring.


If corrosive gas is being transported, coupons or other suitable means must be used to determine the effectiveness of the steps taken to minimize internal corrosion. Each coupon or other means of monitoring internal corrosion must be checked two times each calendar year, but with intervals not exceeding 7½ months. [Issued by Amdt. 192-4, 36 FR 12297, June 30, 1971; Amdt. 192-33, 43 FR 39389, Sept. 5, 1978]





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

measures include hydrogen probes, corrosion probes, corrosion coupons, test spools, and nondestructive testing equipment capable of indicating loss in wall thickness.

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

device to on-stream monitoring. It is desirable to incorporate a retractable feature in the monitoring station to avoid facility shutdowns during periodic inspections, such as weight loss measurements, and for on-stream pigging of the facility.

(c) A written procedure should be established to determine that the monitoring device is operating properly. (d) See guide material under §192.475 if internal corrosion is discovered or is not under mitigation.

§192.479 Atmospheric corrosion control: General.


(a) Each operator must clean and coat each pipeline or portion of pipeline that is exposed to the atmosphere, except pipelines under paragraph (c) of this section. (b) Coating material must be suitable for the prevention of atmospheric corrosion. (c) Except portions of pipelines in offshore splash zones or soil-to-air interfaces, the operator need not protect from atmospheric corrosion any pipeline for which the operator demonstrates by test, investigation, or experience appropriate to the environment of the pipeline that corrosion will-- (1) Only be a light surface oxide; or (2) Not affect the safe operation of the pipeline before the next scheduled inspection. [Issued by Amdt. 192-4, 36 FR 12297, June 30, 1971; Amdt. 192-33, 43 FR 39389, Sept. 5, 1978; Amdt. 192-93, 68 FR 53895, Sept. 15, 2003]

GUIDE MATERIAL 1 GENERAL (a) The need for coating can be determined by experience in the same or essentially identical

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

procedures must be selected to achieve the desired coating system life span. A reference is the SSPC Painting Manual ("Good Painting Practice" - Volume 1; and "Systems and Specifications" - Volume 2), which is published by the Steel Structures Painting Council.

(c) See guide material under §192.481 for determining areas of atmospheric corrosion. 2 EXPOSED PIPING AND RELATED FACILITIES The following methods should be considered for exposed piping and related facilities. (a) Use of coating. See 1 above. (b) Selection of corrosion resistant materials. (c) Avoidance of areas where prevailing winds or other conditions will deposit corrosive materials (such

as salt, moisture, or industrial effluent). Protection in these areas can be provided by selecting a more appropriate meter and regulator location or by using a protective housing.





(d) Use of materials or coatings or both suitable for the environment may be required for facilities installed in pits, vaults, or casings and that may be periodically submerged or exposed to excessive condensation.

(e) Protection of regulator vent lines from plugging by corrosion products. Where practical, the vent line should be installed in a self-drain position and, where necessary, extended above possible flood level.

(f) Use of material for vent tubing that is compatible with the environment encountered. For example, some kinds of plastic tubing should not be exposed to direct sunlight, and certain aluminum alloys should not be submerged or placed in contact with concrete.

§192.481 Atmospheric corrosion control: Monitoring.


(a) Each operator must inspect each pipeline or portion of pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion, as follows:

If the pipeline is located:

Then the frequency of inspection is:

Onshore ................................

At least once every 3 calendar years, but with intervals not exceeding 39 months

Offshore ................................

At least once each calendar year, but with intervals not exceeding 15 months

(b) During inspections the operator must give particular attention to pipe at soil-to-air interfaces, under thermal insulation, under disbonded coatings, at pipe supports, in splash zones, at deck penetrations, and in spans over water. (c) If atmospheric corrosion is found during an inspection, the operator must provide protection against the corrosion as required by §192.479. [Issued by Amdt. 192-4, 36 FR 12297, June 30, 1971; Amdt. 192-27, 41 FR 34598, Aug. 16, 1976; Amdt. 192-33, 43 FR 39389, Sept. 5, 1978; Amdt. 192-93, 68 FR 53895, Sept. 15, 2003]

GUIDE MATERIAL DETERMINING AREAS OF ATMOSPHERIC CORROSION (a) The presence of atmospheric corrosion can be detected best by visual inspection. (1) This may require ladders, scaffolds, hoists, or other suitable means of permitting inspector

access to the structure being inspected. In addition to the locations listed in §192.481(b), attention should be given to locations such as clamps, rest plates, and sleeved openings.

(2) Piping that is thermally or acoustically insulated (jacketed) should be inspected wherever practical. To minimize damage to the insulation, a visual inspection of the pipe may be performed by cutting windows into the insulation.





(b) Exposure test racks can be used to evaluate coatings and materials in local environments such as industrial, coastal, and offshore locations. Many standard procedures or test methods for evaluating materials and coatings are available from the ASTM International.

(c) Evidence of atmospheric corrosion on meters and regulators may also be determined by inspection

by operator employees such as meter readers and leak survey personnel.

§192.483 Remedial measures: General.


(a) Each segment of metallic pipe that replaces pipe removed from a buried or submerged pipeline because of external corrosion must have a properly prepared surface and must be provided with an external protective coating that meets the requirements of §192.461. (b) Each segment of metallic pipe that replaces pipe removed from a buried or submerged pipeline because of external corrosion must be cathodically protected in accordance with this subpart. (c) Except for cast iron or ductile iron pipe, each segment of buried or submerged pipe that is required to be repaired because of external corrosion must be cathodically protected in accordance with this subpart. [Issued by Amdt. 192-4, 36 FR 12297, June 30, 1971]

GUIDE MATERIAL


§192.485 Remedial measures: Transmission lines.


(a) General corrosion. Each segment of transmission line pipe with general corrosion and with a remaining wall thickness less than that required for the MAOP of the pipeline must be replaced or the operating pressure reduced commensurate with the strength of the pipe based on actual remaining wall thickness. However, corroded pipe may be repaired by a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe. Corrosion pitting so closely grouped as to affect the overall strength of the pipe is considered general corrosion for the purpose of this paragraph. (b) Localized corrosion pitting. Each segment of transmission line pipe with localized corrosion pitting to a degree where leakage might result must be replaced or repaired, or the operating pressure must be reduced commensurate with the strength of the pipe, based on the actual remaining wall thickness in the pits. (c) Under paragraphs (a) and (b) of this section, the strength of pipe based on actual remaining wall thickness may be determined by the procedure in ASME/ANSI B31G or the procedure in AGA Pipeline Research Committee Project PR 3-805 (with RSTRENG disk). Both procedures apply to corroded regions that do not penetrate the pipe wall, subject to the limitations prescribed in the procedures.





[Issued by Amdt. 192-4, 36 FR 12297, June 30, 1971; Amdt. 192-33, 43 FR 39389, Sept. 5, 1978; Amdt. 192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996; Amdt. 192-88, 64 FR 69660, Dec. 14, 1999]

GUIDE MATERIAL 1 EVALUATION 1.1 Introduction. The evaluation of the pressure strength of a corroded region in a transmission pipeline to determine

its suitability for continued service can be made by an analytical method, by pressure testing, or by an alternate method.

1.2 Pressure testing. The pipe containing the corroded region may be pressure tested to confirm the established MAOP, or

to determine a lower MAOP. The pressure test should be in accordance with the general requirements of Subpart J (in particular §192.503), and the pressure should be held for at least 8 hours. The established MAOP may be confirmed by testing to a pressure at least equal to the MAOP times the appropriate factor in Table 192.485i or ii below. A lower MAOP may be established by dividing the successful test pressure by the appropriate factor.

(a) For pipeline segments that have not been confirmed for operation in the next higher class location, see §192.611:

CLASS LOCATION FACTOR

Class 1 locations No buildings for human occupancy within 300 feet With buildings for human occupancy within 300 feet

1.10 1.25

Class 2 locations 1.25

Class 3 & 4 locations and Meter & Compressor Station piping in Class 1 & 2 locations

1.5

TABLE 192.485i (b) For pipeline segments that are required to be qualified for an existing class location, see

§192.611:

CLASS LOCATION FACTOR

Class 2 Class 3 Class 4

1.25 1.50 1.80

TABLE 192.485ii



GPTC GUIDE FOR GAS TRANSMISSION AND §192.613 DISTRIBUTION PIPING SYSTEMS: 2009 Edition SUBPART L

Addendum 1, May 2009 231

6 MINING ACTIVITIES For pipelines affected by mining activities, see Guide Material Appendix G-192-13.

§192.614 Damage prevention program.


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



GPTC GUIDE FOR GAS TRANSMISSION AND §192.614 DISTRIBUTION PIPING SYSTEMS: 2009 Edition SUBPART L


(i) The inspection must be done as frequently as necessary during and after the activities to verify the integrity of the pipeline; and (ii) In the case of blasting, any inspection must include leakage surveys. (d) A damage prevention program under this section is not required for the following pipelines: (1) Pipelines located offshore. (2) Pipelines, other than those located offshore, in Class 1 or 2 locations until September 20, 1995. (3) Pipelines to which access is physically controlled by the operator. (e) Pipelines operated by persons other than municipalities (including operators of master meters) whose primary activity does not include the transportation of gas need not comply with the following: (1) The requirement of paragraph (a) of this section that the damage prevention program be written; and (2) The requirements of paragraphs (c)(1) and (c)(2) of this section. [Issued by Amdt. 192-40, 47 FR 13818, Apr. 1, 1982; Amdt. 192-57, 52 FR 32798, Aug. 31, 1987; Amdt. 192-73, 60 FR 14646, Mar. 20, 1995; Amdt. 192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996; Amdt. 192-82, 62 FR 61695, Nov. 19, 1997; Amdt. 192-84, 63 FR 7721, Feb. 17, 1998 with Amdt. 192-84 Removal, 63 FR 38757, July 20, 1998 and Amdt. 192-84 Correction, 63 FR 38758, July 20, 1998]

GUIDE MATERIAL 1 SCOPE

This guide material covers damage prevention programs for buried pipelines, excluding pipelines specified under §192.614(d) that are exempt from these requirements.

2 WRITTEN PROGRAM Written procedures, when required, should state the purpose and objectives of the damage prevention

program and provide methods to achieve them. For program content, operators should review applicable state and local one-call requirements. A reference for state requirements is the One Call Systems International (OCSI) Resource Guide, which provides a summary of the damage prevention laws in each state. In addition, operators should review the Common Ground Alliance’s “Best Practices” Guide. These references are available at www.commongroundalliance.com. The procedures should include the following.

2.1 Definition of excavation activities. In defining excavation activities to be covered by the damage prevention program, the operator should

review the definition in §192.614(a) and applicable state and local requirements. 2.2 One-call systems. (a) A one-call system may exist that does not meet the qualification requirements of §192.614(b)(1)

or (b)(2). If the operator participates in a non-qualified one-call system, either because a qualified one-call system does not cover the area or for any other reason, the operator should consider working with that one-call system to make it qualified.

(b) If a one-call system covering the operator’s facilities does not exist, the operator should consider establishing a qualified one-call system with other underground facility operators.

(c) The operator is cautioned that satisfying the requirements of §192.614 may require more than participation in a one-call system. The operator should evaluate the services being provided by the one-call system to determine what additional measures may need to be taken to satisfy the requirements of §192.614.



Documents

Paul Cabot, C.G.E. GPTC Secretary (202) 824-7312 Fax (202) 824 … · 2019. 12. 19. · Paul Cabot, C.G.E. GPTC Secretary (202) 824-7312 Fax (202) 824-9122 [email protected] January