AGA guia 6.pdf

GPTC GUIDE FOR GAS TRANSMISSION AND DISTRIBUTION PIPING SYSTEMS

2003 EDITON

ADDENDUM NO. 6, September 2006 The changes in this addendum are marked by wide vertical lines inserted to the left of modified text or by overwriting the left border of most tables. The Federal Regulations were changed by 1 amendment that affected 30 sections of the guide. Nine 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. While only significant editorial updates are marked, all affected pages carry the current addendum footnote. Editorial updates affected 24 sections of the guide (plus other sections impacted by page adjustments). The following table shows the affected sections, the pages to be removed, and their replacement pages.

1Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101

Not for Resale, 06/10/2007 17:12:53 MDTNo reproduction or networking permitted without license from IHS

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

Guide Section Reason For Change Pages to be Removed Replacement Pages Title Page EU i/ii thru ix/x i/ii thru ix/x Table of Contents EU Historical Reconstruction of Part 192

EU xxiii/xxiv, xxv/xxvi, xxix/xxx, xxx(a)/xxx(b)

xxiii/xxiv, xxv/xxvi, xxix/xxx, xxx(a)/xxx(b)

Historical Record of Amendments to Part 192

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

GPTC Membership EU Subpart A 192.3 EU (TR04-10 Previous) 19/20 19/20 192.7 Amdt. 192-103 21/22 thru 25/26 21/22 thru 25/26 Subpart C 192.115 EU 39/40 thru 47/48 39/40 thru 47/48 192.121 EU, Amdt. 192-103,

TR04-10

192.123 Amdt. 192-103 Subpart D 192.145 Amdt. 192-103, TR04-13 49/50 and 51/52 49/50 and 51/52 Subpart E 192.225 Amdt. 192-103 89/90 thru 93/94 89/90 thru 93/94 192.227 Amdt. 192-103 192.229 Amdt. 192-103 192.241 Amdt. 192-103 192.245 EU Subpart F 192.281 EU 99/100 thru 103/104 99/100 thru 103/104 192.283 EU, Amdt. 192-103 Subpart G 192.305 EU 109/110 109/110 192.319 EU 117/118 thru 121/122 117/118 thru 121/122 192.321 EU 192.323 TR05-04 Subpart I 192.453 TR02-28 143/144 143/144 thru

144(a)/144(b) 192.465 TR02-27 153/154 153/154 thru

154(a)/154(b) 192.479 EU 161/162 161/162 Subpart J 192.515 TR04-30 175/176 175/176 Subpart K 192.557 EU 183/184 183/184 Subpart L 192.615 TR05-11 207/208 and 211/211(a) 207/208 and 211/211(a) 192.616 Amdt. 192-103 192.619 Amdt. 192-103 213/214 and 215/216 213/214 and 215/216 Subpart M 192.745 EU 249/250 249/250 192.747 EU Heading before 192.761

Amdt. 192-103 255/(256, 257, & 258) 255/(256, 257, & 258)

Subpart O Heading Amdt. 192-103 262(i)/262(j) thru 262(ai)/262(aj)

262(i)/262(j) thru 262(au)/262(av)

192.901 TR04-32 192.903 Amdt. 192-103 192.907 Amdt. 192-103 192.911 Amdt. 192-103



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Guide Section Reason For Change Pages to be Removed Replacement Pages 192.913 Amdt. 192-103 192.915 TR04-39 192.917 Amdt. 192-103 192.921 Amdt. 192-103 192.923 Amdt. 192-103 192.925 Amdt. 192-103 192.927 Amdt. 192-103 192.929 Amdt. 192-103 192.931 Amdt. 192-103 192.933 Amdt. 192-103 192.935 Amdt. 192-103 192.937 Amdt. 192-103 192.939 Amdt. 192-103 192.945 Amdt. 192-103 192.947 EU Appendix B EU, Amdt. 192-103 265/266 and

266(a)/266(b) 265/266 and 266(a)/266(b)

GMA G-191-3 EU PHMSA instructions for Gas Distribution Annual Report 2004

PHSMA instructions for Gas Distribution Annual Report 2005

GMA G-191-5 EU PHMSA form (dated 12/03) and instructions for Transmission and Gathering Systems Annual Report 2004

PHMSA form (dated 12/05) and instructions for Transmission and Gathering Systems Annual Report 2005

GMA G-192-1 EU, TR04-13, TR04-30, TR04-39, TR05-04,

315/316 thru 326(c)/326(d)

315/316 thru 326(c)/326(d)

GMA G-192-1A EU 327/328 and 329/330 327/328 and 329/330 GMA G-192-15 TR05-04 397/398 and 399/400 397/398 and 399/400



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Blank Sheet

Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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Guide for Gas Transmission

and Distribution Piping

Systems

GPTC Z380.1 - 2003

Addendum No. 6 - 2006

September 2006

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) November 9, 2006

ANSI/GPTC Z380.1-2003

Catalog Number: X603066



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GPTC GUIDE FOR GAS TRANSMISSION AND DISTRIBUTION PIPING SYSTEMS: 2003 Edition

PLEASE NOTE

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

CAUTION

As part of subscription service, GPTC (using AGA as Secretariat) will try to keep subscribers informed on the current Federal Regulations as released by the Department of Transportation (DOT) This is done by periodically issuing addenda to update both the Federal Regulations and the guide material. However, the GPTC assumes no responsibility in the event the material that is automatically mailed to subscribers never reaches its destination, or is delivered late. Otherwise, the subscriber is reminded that the changes to the Regulations can be timely noted on the Federal Register's web site.

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

Copyright 2003 THE AMERICAN GAS ASSOCIATION

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

All Rights Reserved Printed in U.S.A.

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CONTENTS Page PREFACE ...........................................................................................................................................xi HISTORY.............................................................................................................................................xi FOREWORD.....................................................................................................................................xii LETTER TO GAS PIPING TECHNOLOGY COMMITTEE FROM THE U.S. DEPARTMENT OF TRANSPORTATION......................................................xiii AMERICAN GAS ASSOCIATION (AGA) NOTICE AND DISCLAIMER................... xiv EDITORIAL CONVENTIONS OF THE GUIDE .....................................................................xv EDITORIAL NOTES FOR THE HISTORICAL RECONSTRUCTION OF PARTS 191 AND 192 .................................................................................................................. xvii HISTORICAL RECONSTRUCTION OF PART 191.......................................................... xvii HISTORICAL RECORD OF AMENDMENTS TO PART 191 .........................................xix HISTORICAL RECONSTRUCTION OF PART 192......................................................... xxiii HISTORICAL RECORD OF AMENDMENTS TO PART 192 ....................................... xxxi GAS PIPING TECHNOLOGY COMMITTEE MEMBERSHIP LIST.................................li PART 191 -- ANNUAL REPORTS, INCIDENT REPORTS, AND SAFETY-RELATED CONDITION REPORTS ........................................................................................................... 1 191.1 Scope........................................................................................................................... 1 191.3 Definitions .................................................................................................................... 2 191.5 Telephonic notice of certain incidents......................................................................... 3 191.7 Addressee for written reports ..................................................................................4(a) 191.9 Distribution system: Incident report.........................................................................4(b) 191.11 Distribution system: Annual report .............................................................................. 5 191.13 Distribution systems reporting transmission pipelines; transmission or gathering systems reporting distribution pipelines............................................................. 5 191.15 Transmission and gathering systems: Incident report................................................ 6 191.17 Transmission and gathering systems: Annual report ................................................. 6 191.19 Report forms ................................................................................................................ 7 191.21 OMB control number assigned to information collection............................................ 7 191.23 Reporting safety-related conditions ............................................................................ 8 191.25 Filing safety-related condition reports ......................................................................... 9 191.27 Filing offshore pipeline condition reports .................................................................. 10

Addendum No. 5, May 2006 iiiCopyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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PART 192 -- MINIMUM FEDERAL SAFETY STANDARDS .......................................... 11 SUBPART A -- GENERAL.................................................................................................................. 11 192.1 What is the scope of this part?.................................................................................. 11 192.3 Definitions .................................................................................................................. 12 192.5 Class locations........................................................................................................... 20 192.7 What documents are incorporated by reference partly or wholly in this part? ....................................................................................................... 21 192.8 How are onshore gathering lines and regulated onshore gathering lines determined? ............................................................................................. 25 192.9 What requirements apply to gathering lines? ........................................................... 27 192.10 Outer continental shelf pipelines .......................................................................... 28 192.11 Petroleum gas systems.........................................................................................28(a) 192.12 (Removed) .............................................................................................................28(c) 192.13 What general requirements apply to pipelines regulated under this part? ..........28(c) 192.14 Conversion to service subject to this part .............................................................28(d) 192.15 Rules of regulatory construction............................................................................28(e) 192.16 Customer notification..............................................................................................28(f) 192.17 (Removed) .............................................................................................................28(g) SUBPART B -- MATERIALS .............................................................................................................. 29 192.51 Scope......................................................................................................................... 29 192.53 General ...................................................................................................................... 29 192.55 Steel pipe ................................................................................................................... 30 192.57 (Removed and reserved) .......................................................................................... 31 192.59 Plastic pipe................................................................................................................. 31 192.61 (Removed and reserved) .......................................................................................... 32 192.63 Marking of materials .................................................................................................. 32 192.65 Transportation of pipe................................................................................................ 33 SUBPART C -- PIPE DESIGN ............................................................................................................ 35 192.101 Scope......................................................................................................................... 35 192.103 General ...................................................................................................................... 35 192.105 Design formula for steel pipe..................................................................................... 36 192.107 Yield strength (S) for steel pipe................................................................................. 37 192.109 Nominal wall thickness (t) for steel pipe.................................................................... 38 192.111 Design factor (F) for steel pipe.................................................................................. 38 192.113 Longitudinal joint factor (E) for steel pipe.................................................................. 40 192.115 Temperature derating factor (T) for steel pipe.......................................................... 41 192.117 (Removed and reserved) .......................................................................................... 42 192.119 (Removed and reserved) .......................................................................................... 42 192.121 Design of plastic pipe ................................................................................................ 42 192.123 Design limitations for plastic pipe.............................................................................. 45 192.125 Design of copper pipe................................................................................................ 48 SUBPART D -- DESIGN OF PIPELINE COMPONENTS .................................................................. 49 192.141 Scope......................................................................................................................... 49 192.143 General requirements................................................................................................ 49 192.144 Qualifying metallic components ................................................................................ 50 192.145 Valves ........................................................................................................................ 50 192.147 Flanges and flange accessories ............................................................................... 52 192.149 Standard fittings......................................................................................................... 55 192.150 Passage of internal inspection devices..................................................................... 55 192.151 Tapping ...................................................................................................................... 57 192.153 Components fabricated by welding........................................................................... 58 192.155 Welded branch connections...................................................................................... 59

Addendum No.6, September 2006 ivCopyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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192.157 Extruded outlets......................................................................................................... 61 192.159 Flexibility .................................................................................................................... 63 192.161 Supports and anchors ............................................................................................... 66 192.163 Compressor stations: Design and construction........................................................ 67 192.165 Compressor stations: Liquid removal ....................................................................... 69 192.167 Compressor stations: Emergency shutdown............................................................ 69 192.169 Compressor stations: Pressure limiting devices....................................................... 70 192.171 Compressor stations: Additional safety equipment .................................................. 71 192.173 Compressor stations: Ventilation .............................................................................. 72 192.175 Pipe-type and bottle-type holders ............................................................................. 73 192.177 Additional provisions for bottle-type holders ............................................................. 74 192.179 Transmission line valves ........................................................................................... 74 192.181 Distribution line valves............................................................................................... 76 192.183 Vaults: Structural design requirements..................................................................... 77 192.185 Vaults: Accessibility ................................................................................................... 78 192.187 Vaults: Sealing, venting, and ventilation ................................................................... 78 192.189 Vaults: Drainage and waterproofing.......................................................................... 79 192.191 Design pressure of plastic fittings ............................................................................. 79 192.193 Valve installation in plastic pipe................................................................................. 80 192.195 Protection against accidental overpressuring........................................................... 81 192.197 Control of the pressure of gas delivered from high-pressure distribution systems.......................................................................................... 83 192.199 Requirements for design of pressure relief and limiting devices ............................. 84 192.201 Required capacity of pressure relieving and limiting stations .................................. 86 192.203 Instrument, control, and sampling pipe and components ........................................ 87 SUBPART E -- WELDING OF STEEL IN PIPELINES ...................................................................... 89 192.221 Scope......................................................................................................................... 89 192.223 (Removed) ................................................................................................................. 89 192.225 Welding – General..................................................................................................... 89 192.227 Qualification of welders ............................................................................................. 90 192.229 Limitations on welders............................................................................................... 90 192.231 Protection from weather ............................................................................................ 91 192.233 Miter joints.................................................................................................................. 92 192.235 Preparation for welding.............................................................................................. 92 192.237 (Removed) ................................................................................................................. 93 192.239 (Removed) ................................................................................................................. 93 192.241 Inspection and test of welds...................................................................................... 93 192.243 Nondestructive testing............................................................................................... 94

192.245 Repair or removal of defects ..................................................................................... 95 SUBPART F -- JOINING OF MATERIALS OTHER THAN BY WELDING ...................................... 97 192.271 Scope......................................................................................................................... 97 192.273 General ...................................................................................................................... 97 192.275 Cast iron pipe............................................................................................................. 98 192.277 Ductile iron pipe ......................................................................................................... 98 192.279 Copper pipe ............................................................................................................... 99 192.281 Plastic pipe................................................................................................................. 99 192.283 Plastic pipe: Qualifying joining procedures ............................................................. 103 192.285 Plastic pipe: Qualifying persons to make joints ...................................................... 106 192.287 Plastic pipe: Inspection of joints ............................................................................. 107

Addendum No. 1, September 2004 vCopyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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SUBPART G -- GENERAL CONSTRUCTION REQUIREMENTS FOR TRANSMISSION LINES AND MAINS ................................................................................................................... 109 192.301 Scope....................................................................................................................... 109 192.303 Compliance with specifications or standards.......................................................... 109 192.305 Inspection: General ................................................................................................. 109 192.307 Inspection of materials ............................................................................................ 110 192.309 Repair of steel pipe.................................................................................................. 110 192.311 Repair of plastic pipe ............................................................................................... 111 192.313 Bends and elbows ................................................................................................... 112 192.315 Wrinkle bends in steel pipe ..................................................................................... 113 192.317 Protection from hazards .......................................................................................... 113 192.319 Installation of pipe in a ditch .................................................................................... 115 192.321 Installation of plastic pipe ........................................................................................ 117 192.323 Casing...................................................................................................................... 121 192.325 Underground clearance........................................................................................... 122 192.327 Cover........................................................................................................................ 123 SUBPART H -- CUSTOMER METERS, SERVICE REGULATORS, AND SERVICE LINES ....... 125 192.351 Scope....................................................................................................................... 125 192.353 Customer meters and regulators: Location ............................................................ 125 192.355 Customer meters and regulators: Protection from damage................................... 127 192.357 Customer meters and regulators: Installation......................................................... 129 192.359 Customer meter installations: Operating pressure................................................. 130 192.361 Service lines: Installation......................................................................................... 130 192.363 Service lines: Valve requirements........................................................................... 132 192.365 Service lines: Location of valves ............................................................................. 132 192.367 Service lines: General requirements for connections to main piping ................................................................................................. 133 192.369 Service lines: Connections to cast iron or ductile iron mains................................. 134 192.371 Service lines: Steel ..............................................................................................134(a) 192.373 Service lines: Cast iron and ductile iron..............................................................134(b) 192.375 Service lines: Plastic............................................................................................134(b) 192.377 Service lines: Copper ............................................................................................. 135 192.379 New service lines not in use.................................................................................... 135 192.381 Service lines: Excess flow valve performance standards ...................................... 136 192.383 Excess flow valve customer notification ................................................................. 139 SUBPART I -- REQUIREMENTS FOR CORROSION CONTROL ................................................. 143 192.451 Scope....................................................................................................................... 143 192.452 How does this subpart apply to converted pipelines and regulated onshore gathering lines?................................................................................ 144 192.453 General ................................................................................................................144(a) 192.455 External corrosion control: Buried or submerged pipelines installed after July 31, 1971 .......................................................................144(b) 192.457 External corrosion control: Buried or submerged pipelines installed before August 1, 1971 ..................................................................... 145 192.459 External corrosion control: Examination of buried pipeline when exposed................................................................................... 149 192.461 External corrosion control: Protective coating ........................................................ 150 192.463 External corrosion control: Cathodic protection...................................................... 151 192.465 External corrosion control: Monitoring .................................................................... 152 192.467 External corrosion control: Electrical isolation ....................................................154(a) 192.469 External corrosion control: Test stations................................................................. 156 192.471 External corrosion control: Test leads..................................................................... 156

Addendum No. 6, September 2006 viCopyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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192.473 External corrosion control: Interference currents.................................................... 157 192.475 Internal corrosion control: General.......................................................................... 158 192.477 Internal corrosion control: Monitoring...................................................................... 160 192.479 Atmospheric corrosion control: General ................................................................. 161 192.481 Atmospheric corrosion control: Monitoring ............................................................. 162 192.483 Remedial measures: General ................................................................................. 163 192.485 Remedial measures: Transmission lines................................................................ 163 192.487 Remedial measures: Distribution lines other than cast iron or ductile iron lines .................................................................................. 165 192.489 Remedial measures: Cast iron and ductile iron pipelines ...................................... 166 192.490 Direct Assessment................................................................................................... 166 192.491 Corrosion control records....................................................................................166(a) SUBPART J -- TEST REQUIREMENTS .......................................................................................... 167 192.501 Scope....................................................................................................................... 167 192.503 General requirements.............................................................................................. 167 192.505 Strength test requirements for steel pipeline to operate at a hoop stress of 30 percent or more of SMYS ............................ 168 192.507 Test requirements for pipelines to operate at a hoop stress less than 30 percent of SMYS and at or above 100 p.s.i.g................ 171 192.509 Test requirements for pipelines to operate below 100 p.s.i.g. ............................... 171 192.511 Test requirements for service lines ......................................................................... 172 192.513 Test requirements for plastic pipelines ................................................................... 172 192.515 Environmental protection and safety requirements................................................ 173 192.517 Records.................................................................................................................... 176 SUBPART K -- UPRATING .............................................................................................................. 177 192.551 Scope....................................................................................................................... 177 192.553 General requirements.............................................................................................. 177 192.555 Uprating to a pressure that will produce a hoop stress of 30 percent or more of SMYS in steel pipelines ......................................... 179 192.557 Uprating: Steel pipelines to a pressure that will produce a hoop stress less than 30 percent of SMYS: plastic, cast iron, and ductile iron pipelines........ 181 SUBPART L -- OPERATIONS.......................................................................................................... 185 192.601 Scope....................................................................................................................... 185 192.603 General provisions................................................................................................... 185 192.605 Procedural manual for operations, maintenance, and emergencies ..................... 186 192.607 (Removed and reserved) ........................................................................................ 193 192.609 Change in class location: Required study............................................................... 194 192.611 Change in class location: Confirmation or revision of maximum allowable operating pressure........................................................ 194 192.612 Underwater inspection and re-burial of pipelines in the Gulf of Mexico and its inlets ................................................................. 195 192.613 Continuing surveillance ........................................................................................... 196 192.614 Damage prevention program ..............................................................................197(b) 192.615 Emergency plans..................................................................................................... 203 192.616 Public awareness .................................................................................................... 211 192.617 Investigation of failures............................................................................................ 212 192.619 What is the maximum allowable operating pressure for steel or plastic pipelines?........................................................................................ 214 192.621 Maximum allowable operating pressure: High-pressure distribution systems........................................................................................ 215 192.623 Maximum and minimum allowable operating pressure: Low-pressure distribution systems........................................................................................ 216 Addendum No. 6, September 2006 vii



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192.625 Odorization of gas.................................................................................................... 217 192.627 Tapping pipelines under pressure........................................................................... 219 192.629 Purging of pipelines ................................................................................................. 221 SUBPART M -- MAINTENANCE ...................................................................................................... 223 192.701 Scope....................................................................................................................... 223 192.703 General .................................................................................................................... 223 192.705 Transmission lines: Patrolling ................................................................................. 226 192.706 Transmission lines: Leakage surveys..................................................................... 228 192.707 Line markers for mains and transmission lines ...................................................... 229 192.709 Transmission lines: Record keeping....................................................................... 230 192.711 Transmission lines: General requirements for repair procedures.......................... 230 192.713 Transmission lines: Permanent field repair of imperfections and damages.................................................................................................. 231 192.715 Transmission lines: Permanent field repair of welds.............................................. 233 192.717 Transmission lines: Permanent field repair of leaks............................................... 233 192.719 Transmission lines: Testing of repairs .................................................................... 234 192.721 Distribution systems: Patrolling ............................................................................... 234 192.723 Distribution systems: Leakage surveys ................................................................. 236 192.725 Test requirements for reinstating service lines ....................................................... 238 192.727 Abandonment or deactivation of facilities ............................................................... 238 192.729 (Removed) ............................................................................................................... 241 192.731 Compressor stations: Inspection and testing of relief devices ............................... 241 192.733 (Removed) ............................................................................................................... 241 192.735 Compressor stations: Storage of combustible materials........................................ 242 192.736 Compressor stations: Gas detection....................................................................... 242 192.737 (Removed) ............................................................................................................... 243 192.739 Pressure limiting and regulating stations: Inspection and testing .......................... 243 192.741 Pressure limiting and regulating stations: Telemetering or recording gauges............................................................................................ 245 192.743 Pressure limiting and regulating stations: Testing of relief devices................................................................................................... 247 192.745 Valve maintenance: Transmission lines ................................................................. 248 192.747 Valve maintenance: Distribution systems............................................................... 249 192.749 Vault maintenance................................................................................................... 250 192.751 Prevention of accidental ignition ............................................................................. 252 192.753 Caulked bell and spigot joints ................................................................................. 255 192.755 Protecting cast-iron pipelines .................................................................................. 256 192.761 (Removed) ............................................................................................................... 256 SUBPART N -- QUALIFICATION OF PIPELINE PERSONNEL..................................................... 259 192.801 Scope....................................................................................................................... 259 192.803 Definitions ................................................................................................................ 260 192.805 Qualification program ..........................................................................................262(a) 192.807 Recordkeeping......................................................................................................262(f) 192.809 General ................................................................................................................262(g) SUBPART O -- PIPELINE INTEGRITY MANAGEMENT .............................................................262(i) 192.901 What do the regulations in this subpart cover? ...................................................262(i) 192.903 What definitions apply to this subpart? ................................................................ 262(ij 192.905 How does an operator identify a high consequence area?.................................262(l) 192.907 What must an operator do to implement this subpart? .....................................262(m) 192.909 How can an operator change its integrity management program?....................262(p)

Addendum No. 6, September 2006 viiiCopyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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192.911 What are the elements of an integrity management program?..........................262(q) 192.913 When may an operator deviate its program from certain requirements of this subpart? .....................................................................262(r) 192.915 What knowledge and training must personnel have to carry out an integrity management program?................................................................262(s) 192.917 How does an operator identify potential threats to pipeline integrity and use the threat identification in its integrity program?..........................262(u) 192.919 What must be in the baseline assessment plan?..............................................262(w) 192.921 How is the baseline assessment to be conducted? .......................................... 262(w) 192.923 How is direct assessment used and for what threats?.......................................262(y) 192.925 What are the requirements for using External Corrosion Direct Assessment (ECDA)? ................................................................................262(z) 192.927 What are the requirements for using Internal Corrosion Direct Assessment (ICDA)?................................................................................262(aa) 192.929 What are the requirements for using Direct Assessment for Stress Corrosion Cracking (SCCDA)?................................................................262(ac) 192.931 How may Confirmatory Direct Assessment (CDA) be used? ..........................262(ad) 192.933 What actions must be taken to address integrity issues? ................................262(ae) 192.935 What additional preventive and mitigative measures must an operator take? ...........................................................................................262(af) 192.937 What is a continual process of evaluation and assessment to maintain a pipeline’s integrity?..................................................................262(al) 192.939 What are the required reassessment intervals?..............................................262(am) 192.941 What is a low stress reassessment? ................................................................262(ao) 192.943 When can an operator deviate from these reassessment intervals?...............262(ap) 192.945 What methods must an operator use to measure program effectiveness?...........................................................................................262(aq) 192.947 What records must an operator keep? ............................................................. 262(ar) 192.949 How does an operator notify OPS? ...................................................................262(at) 192.951 Where does an operator file a report? ..............................................................262(au) APPENDICES TO PART 192 Appendix A (Removed and reserved)................................................................................... 263 Appendix B Qualification of Pipe ........................................................................................... 265 Appendix C Qualification of Welders for Low Stress Level Pipe.......................................... 267 Appendix D Criteria for Cathodic Protection and Determination of Measurements ............ 271 Appendix E Guidance on Determining High Consequence Areas and on Carrying out Requirements in the Integrity Management Rule ...............272(a) GUIDE MATERIAL APPENDICES Guide Material Appendix G-191-1 Telephonic notice worksheet...................................... 273 Guide Material Appendix G-191-2 Distribution system incident report ............................. 275 Guide Material Appendix G-191-3 Distribution system annual report............................... 283 Guide Material Appendix G-191-4 Transmission and gathering systems incident report..................................................... 289 Guide Material Appendix G-191-5 Transmission and gathering systems annual report ...................................................... 303 Guide Material Appendix G-191-6 Determination of reporting requirements for safety-related conditions .............................. 309 Guide Material Appendix G-191-7 Safety-related condition report to United States Department of Transportation............................ 311

Addendum No. 6, September 2006 ixCopyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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Guide Material Appendix G-192-1 Summary of references and related sources............. 313 Guide Material Appendix G-192-1A Editions of material specifications, codes and standards previously incorporated by reference in the Regulations ....................................................... 327 Guide Material Appendix G-192-2 Specified minimum yield strengths............................. 331 Guide Material Appendix G-192-3 Flexibility factor k and stress intensification factor i ......................................... 333 Guide Material Appendix G-192-4 Rules for reinforcement of welded branch connections ........................................................ 337 Guide Material Appendix G-192-5 Pipe end preparation................................................... 347 Guide Material Appendix G-192-6 Substructure damage prevention guidelines for directional drilling and other trenchless technologies ....................................................... 353 Guide Material Appendix G-192-7 [Reserved]................................................................... 355 Guide Material Appendix G-192-8 [Reserved]................................................................... 355 Guide Material Appendix G-192-9 Test conditions for pipelines other than service lines ............................................... 357 Guide Material Appendix G-192-10 Test conditions for service lines ................................. 359 Guide Material Appendix G-192-11 Gas leakage control guidelines for natural gas systems...................................... 361 Guide Material Appendix G-192-11A Gas leakage control guidelines for petroleum gas systems................................. 373 Guide Material Appendix G-192-12 Planned shutdown ...................................................... 387 Guide Material Appendix G-192-13 Considerations to minimize damage by outside forces.................................................................. 391 Guide Material Appendix G-192-14 [Reserved]................................................................... 395 Guide Material Appendix G-192-15 Design of uncased pipeline crossings of highways and railroads ...................................... 397 Guide Material Appendix G-192-15A Horizontal directional drilling for steel pipelines ......... 401 Guide Material Appendix G-192-16 Substructure damage prevention guidelines ............. 405 Guide Material Appendix G-192-17 Explicit requirements for reports, inspections, tests, written procedures, records and similar actions ............................................ 409 Guide Material Appendix G-192-18 Cast iron pipe .............................................................. 413 Guide Material Appendix G-192-19 Memorandum of understanding between the Department of Transportation and the Department of the Interior regarding outer continental shelf pipelines...................... 417 Guide Material Appendix G-192-20 Fusion equipment maintenance/repair inspection form..................................................................... 421 Guide Material Appendix G-192-21 Plastic pipe for bridge crossings................................. 423 Guide Material Appendix G-192-M SI (metric) units ........................................................... 425 INDEX............................................................................................................................................... 429

Addendum No. 3, September 2005 xCopyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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HISTORICAL RECONSTRUCTION OF PART 192 (Complete through Amendment 192-103)

Part 192 Subpart

Part 192 Section

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

Amendments (if any)

SUBPART A – GENERAL

192.1 192.3 192.5 192.7 192.8 192.9 192.10 192.11 [192.12] 192.13 192.14 192.15 192.16 [192.17]

04/14/06 03/19/98 11/13/72 12/30/77 09/13/95 01/01/71

192-27, 192-67, 192-78, 192-81 192-92, RIN 2137-AD77, 192-102 192-13, 192-27, 192-58, 192-67, 192-72 + Ext., 192-78, 192-81, 192-85, 192-89, RIN 2137-AD43 192-93, 192-94, 192-98, RIN 2137-AD77 192-27, 192-56, 192-78, 192-85 192-37, 192-51, 192-68, 192-78 192-94, RIN 2137-AD77, 192-99 192-102, 192-103 192-102 192-72 + Ext., 192-95 Corr., 192-102 192-81, RIN 2137-AD77 192-68, 192-75, 192-78 192-10, 192-36 (removed) 192-27, 192-30, 192-102 192-30 192-74, 192-74A, 192-84 192-1, 192-27A Ext., 192-38 (removed)

SUBPART B – MATERIALS

192.51 192.53 192.55 192.57 192.59 192.61 192.63 192.65

192-3, 192-12, 192-51, 192-68, 192-85 192-62 (removed and reserved) 192-19, 192-58 192-62 (removed and reserved) 192-3, 192-31, 192-31A, 192-61, 192-61A, 192-62, 192-68, 192-76 192-12, 192-17, 192-68

Addendum No. 6, September 2006 xxiii Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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HISTORICAL RECONSTRUCTION OF PART 192 (Continued)

Part 192 Subpart

Part 192 Section


Amendments (if any)

SUBPART C - PIPE DESIGN

192.101 192.103 192.105 192.107 192.109 192.111 192.113 192.115 192.117 192.119 192.121 192.123 192.125

192-47, 192-85 192-78, 192-84, 192-85 192-85 192-27 192-37, 192-51, 192-62, 192-68, 192-85, 192-94 192-85 192-37, 192-62 (removed and reserved) 192-62 (removed and reserved) 192-31, 192-78, 192-85, 192-94, 192-103 192-31, 192-78, 192-85, 192-93 192-94, 192-103 192-62, 192-85

Addendum No. 6, September 2006 xxiv Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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Part 192 Subpart

Part 192 Section


Amendments (if any)

SUBPART D – DESIGN OF PIPELINE COMPONENTS

192.141 192.143 192.144 192.145 192.147 192.149 192.150 192.151 192.153 192.155 192.157 192.159 192.161 192.163 192.165 192.167 192.169 192.171 192.173 192.175 192.177 192.179 192.181 192.183 192.185 192.187 192.189 192.191 192.193 192.195 192.197 192.199 192.201 192.203

08/04/83 05/12/94

192-48 192-45, 192-94 192-3, 192-22, 192-37, 192-62, 192-85, 192-94, 192-103 192-62, 192-68 192-72 + Ext., 192-85, 192-97 192-85 192-3, 192-68, 192-85 192-27, 192-58 192-27, 192-37, 192-68, 192-85 192-27, 192-85 192-85 192-58, 192-62, 192-68, 192-85 192-27, 192-78, 192-85 192-85 192-85 192-76 192-3, 192-58 192-85, 192-93 192-3 192-9, 192-85 192-78, 192-85

Addendum No. 6, September 2006 xxv Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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Part 192 Subpart

Part 192 Section


Amendments (if any)

SUBPART E – WELDING OF STEEL IN PIPELINES

192.221 [192.223] 192.225 192.227 192.229 192.231 192.233 192.235 [192.237] [192.239] 192.241 192.243 192.245

192-52 (removed) 192-18, 192-22, 192-37, 192-52, 192-94, 192-103 192-18, 192-18A, 192-22, 192-37, 192-43, 192-52, 192-75, 192-78, 192-94, 192-103 192-18, 192-18A, 192-37, 192-78, 192-85, 192-94, 192-103 192-37, 192-52 (removed) 192-37, 192-52 (removed) 192-18, 192-18A, 192-37, 192-78, 192-85, 192-94, 192-103 192-27, 192-50, 192-78 192-27, 192-46

SUBPART F – JOINING OF MATERIALS OTHER THAN BY WELDING

192.271 192.273 192.275 192.277 192.279 192.281 192.283 192.285 192.287

07/01/80 07/01/80 07/01/80

192-62 192-62 192-62, 192-68 192-34, 192-58, 192-61, 192-68, 192-78 192-34 + Ext., 192-34A, 192-34B, 192-68, 192-78, 192-85, 192-94 192-103 192-34 + Ext., 192-34A, 192-34B 192-93, 192-94 192-34 + Ext., 192-94

Addendum No. 6, September 2006 xxvi Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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Part 192 Subpart

Part 192 Section


Amendments (if any)

SUBPART J - TEST REQUIREMENTS

192.501 192.503 192.505 192.507 192.509 192.511 192.513 192.515 192.517

192-58, 192-60, 192-60A 192-85, 192-94 192-58, 192-85 192-58, 192-85 192-75, 192-85 192-77, 192-85 192-93

SUBPART K - UPRATING

192.551 192.553 192.555 192.557

192-78, 192-93 192-37, 192-62, 192-85

SUBPART L - OPERATIONS

192.601 192.603 192.605 192.607 192.609 192.611 192.612 192.613 192.614 192.615 192.616 192.617 192.619 192.621 192.623 192.625 192.627 192.629

01/06/92 04/01/83 02/11/95

192-27A Ext., 192-66, 192-71, 192-75 192-27A Ext., 192-59, 192-71, 192-71A, 192-93 192-5, 192-78 (removed and reserved) 192-5, 192-53, 192-63, 192-78, 192-94 192-67, 192-85, 192-98 192-40, 192-57, 192-73, 192-78, 192-82, 192-84 + DFR Removal 192-24, 192-71 192-71, 192-99, 192-103 192-3, 192-27, 192-27A, 192-30, 192-78, 192-85, 192-102, 192-103 192-85 192-75 192-2, 192-6, 192-7, 192-14, 192-15, 192-16, 192-21, 192-58 192-76, 192-78, 192-93

Addendum No. 6, September 2006 xxix Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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Part 192 Subpart

Part 192 Section


Amendments (if any)

SUBPART M - MAINTENANCE

192.701 192.703 102.705 192.706 192.707 192.709 192.711 192.713 192.715 192.717 192.719 192.721 192.723 192.725 192.727 [192.729] 192.731 [192.733] 192.735 192.736 [192.737] 192.739 192.741 192.743 192.745 192.747 192.749 192.751 192.753 192.755 Header [192.761]

06/04/75 10/18/93 06/01/76

192-21, 192-43, 192-78 192-21, 192-43, 192-71 192-20, 192-20A, 192-27, 192-40, 192-44, 192-73, 192-85 192-78 192-27B, 192-88 192-27, 192-88 192-85 192-11, 192-27, 192-85, 192-88 192-54 192-43, 192-78 192-43, 192-70, 192-71, 192-94 192-8, 192-27, 192-71, 192-89, RIN 2137-AD77 192-71 (removed) 192-43 192-71 (removed) 192-69, 192-85 192-71 (removed) 192-43, 192-93, 192-96 192-43, 192-55, 192-93, 192-96 192-43, 192-93 192-43, 192-93 192-43, 192-85 192-25, 192-85, 192-93 192-23 192-103 (removed) 192-91, 192-95 (removed)

SUBPART N - QUALIFICATION OF PIPELINE PERSONNEL

192.801 192.803 192.805 192.807 192.809

10/26/99 10/26/99 10/26/99 10/26/99 10/26/99

192-86 192-86, 192-90 192-86, 192-100 192-86 192-86, 192-90, 192-100

Addendum No. 6, September 2006 xxx Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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Part 192 Subpart

Part 192 Section


Amendments (if any)

SUBPART O – PIPELINE INTEGRITY MANAGEMENT

Header 192.901 192.903 192.905 192.907 192.909 192.911 192.913 192.915 192.917 192.919 192.921 192.923 192.925 192.927 192.929 192.931 192.933 192.935 192.937 192.939 192.941 192.943 192.945 192.947 192.949 192.951

2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04 2/14/04

192-95, 192-103 192-95 192-95, 192-103 192-95 192-95, 192-103 192-95 192-95, 192-103 192-95, 192-103 192-95 192-95, 192-103 192-95 192-95, 192-103 192-95, 192-103 192-95, 192-103 192-95, 192-103 192-95, 192-103 192-95, 192-103 192-95, 192-103 192-95, 192-103 192-95, 192-103 192-95, 192-103 192-95 192-95 192-95, 192-103 192-95 192-95, RIN 2137-AD77 192-95, RIN 2137-AD77

Addendum No. 6, September 2006 xxx(a) Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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GDISTRIBUTION PIPING SY

Addendum No. 6, September 2006

PTC GUIDE FOR GAS TRANSMISSION AND STEMS: 2003 Edition

xxx(b)


Part 192 Subpart

Part 192 Section


Amendments (if any)

FEDERAL APPENDICES

[App. A]

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

App. B

192-3, 192-12, 192-19, 192-22, 192-32, 192-37, 192-41, 192-51, 192-61, 192-62, 192-65, 192-68, 192-76, 192-85, 192-94, 192-103

App. C

192-85, 192-94

App. D 08/01/71 192-4

App E

12/15/03 192-95



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xlix

HISTORICAL RECORD OF AMENDMENTS TO PART 192

(Continued)

Amdt 192-

Subject Vol FR Pg# Published Date

Docket No.

Effective Date

Affected Sections 192.

102 Gas Gathering Line Definition

71 FR 13289 03/15/06 RIN 2137-AB15

04/14/06 1, 7, 8, 9, 13, 452, 619

103 Update of Regulatory References to Technical Standards

71 FR 33402 06/09/06 RIN 2138-AD68

07/10/06 7, 121, 123, 145, 225, 227, 229, 241,

283, 616, 619, Header before 761, Subpart O Header, 903, 907, 911, 913, 917, 921, 923, 925, 927, 929, 931, 933, 935, 937, 939, 945,

App. B

* Issued as a Direct Final Rule (DFR).



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Addendum No. 5, May


2006 l

Reserved



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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

R

egulations

Editorial

Executive

Liaison

Abraham, Richard A. New England Gas Co., Providence, RI

X X X X

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

X X X X

Alexander, Thomas D. Willbros Engr., Inc., Tulsa, OK

X X X

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

X Chair X X X X X

Barkei, David E. We Engeries, Milwaukee, WI

X X X

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

X X X X

Beaver, Brett Advantica, Carlise, PA

X X X

Becken, Robert C. Energy Experts Int. Pleasant Hill, CA

X X X X X

Bennett, Frank M. PPL Gas Utilities Corp., Lancaster, PA

X X X

Bezner, William A. CSR PolyPipe, Inc., Gainesville, TX

X X

Addendum No. 6, September 2006 li

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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

R

egulations

Editorial

Executive

Liaison

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

X X X X X

Blanton, Glynn TN Regulatory Authority, Nashville, TN

X X X

Booth, Lloyd E. Southern Cross Corp., Coppell, TX

X X X

Boros, Stephen Plastics Pipe Institute, Washington, DC

X X

Borski, Lawrence W. Williams Gas Pipeline-Transco, Houston, TX

X X

Bull, David E. ViaData LP, Tobyhanna, PA

X X SEC X

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

SEC C SE

Cadorin, Robert J. Great Lakes Gas Trmn. Co., Troy, MI

X X X

Carey, Willard S. Public Service Elec. & Gas Co., Newark, NJ

X X X Chair X

Chin, John S. El Paso Corp., Farmington Hills, MI

X X X X Chair X X

Addendum No. 6, September 2006 lii

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M

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istribution

M

anufacturers

Transm

ission

D

esign

D

P/ER

IM

P/Corrosion

O

&M

/OQ

Plastic Pipe

R

egulations

Editorial

Executive

Liaison

Clarke, Allan M. Duke Energy Corp., Houston, TX

Sec X X X

Cody, Leo T. KeySpan Corp., Waltham, MA

X X X

Craig, Jim M. McElroy Mfg., Inc., Tulsa, OK

X X X

De Leon, Cesar PanAm P/L Technology, Inc., San Antonio, TX

X X X

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

X X

DeVore, James C. Consultant, Green Valley, AZ

X X X X X

Dockweiler, Kenneth D. Kinder Morgan, Inc., Casper, WY

X X X X

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

X X

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

X X X X

Frantz, John H. PECO Energy, Philadelphia, PA

X X air Ch

Addendum No. 6, September 2006 liii

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IHS

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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

R

egulations

Editorial

Executive

Liaison

Frederick, Victor M., III Utility Line Services, Conshohocken, PA

X X X

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

X X X X X

Groeber, Steve A. Philadelphia Gas Works, Philadelphia, PA

X X X X X

Gunther, Karl M. NTSB, Washington, DC

X X X

Hansen, Jim Perfection Corp., Madison, OH

X X

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

X X X

Hazelden, Glyn Gas Technology Institute, Des Plaines, IL

X X X

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

X X X X X X X

Henningsgaard, David R. CenterPoint Energy-Minnegasco, Minneapolis, MN

X X X X

Henry, Jill A. Ohio PUC, Columbus, OH

X X X X

Addendum No. 6, September 2006 liv

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istribution

M

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esign

D

P/ER

IM

P/Corrosion

O

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Plastic Pipe

R

egulations

Editorial

Executive

Liaison

Hotinger, James M. X X X VA State Corp. Comm., Richmond, VA Humes, Dennis W. Mueller Co.- Gas Products Div., Decatur, IL

X X X

Hurbanek, Stephen F. Pennsylvania PUC, Darlington, PA

X X

Huriaux, Richard D. PHMSA, Washington, DC

X X X

Kirkland, David L. Columbia Gas Trmn. Corp., Charleston, WV

X X X

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

X X Chair X X X

Krummert, Lawrence Columbia Gas of PA

X X

Lathrap, Philip A. Retired-Pacific Gas & Elec. Co., Lafayette, CA

X X X X X

Lee, Stewart Pacific Gas and Electric Co.

X X X

Lewis, Raymond D. Rosen USA, Houston, TX

X X X

Addendum No. 6, September 2006 lv

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istribution

M

anufacturers

Transm

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D

esign

D

P/ER

IM

P/Corrosion

O

&M

/OQ

Plastic Pipe

R

egulations

Editorial

Executive

Liaison

Lively, Karen S. Performance Pipe, Plano, TX

X X X

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

X X Chair X

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

X X X X

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

X X X

Mackay-Smith, Seth UMAC, Inc., Exton, PA

X X X X

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

Chair X

Mason, James F. Arkema, Inc., King of Prussia, PA

X X

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

X X

McMaine Jeffrey B. Texas Gas Trmn., LLC, Owensboro, KY

X X X

Miller, D. Lane Transportation Safety Inst., Oklahoma City, OK

X X X X Sec

Addendum No. 6, September 2006 lvi

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IHS

--``,,,``,`````,``,``,,,`,,`,,`-`-`,,`,,`,`,,`---




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

R

egulations

Editorial

Executive

Liaison

Naper, Robert C. KeySpan Corp., Waltham, MA

X X

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

X X X X X

Palermo, Eugene F. Palermo Plastics Pipe Consulting, Oak Hill, VA

X X X X

Peters, Kenneth C. El Paso Corp. Pipeline Group, Birmingham, AL

X Chair X X X

Pioli, Christopher A. Jacobs Consultancy, Pasadena, CA

X X X X

Quezada, Leticia Nicor Gas, Naperville, IL

X X X X Chair X

Reynolds, Donald Lee NiSource Inc., Columbus, OH

X Chair X X

Roberson, Edwin H. Natural Gas Odorizing, Katy, TX

X X

Robertson, Joseph P. Williams Gas Pipeline-NW, Salt Lake City, UT

X X X

Schmidt, Robert A. Trinity Industry, Russellville, AR

X Chair X X

Addendum No. 6, September 2006 lvii

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IHS

--``,,,``,`````,``,``,,,`,,`,,`-`-`,,`,,`,`,,`---




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

R

egulations

Editorial

Executive

Liaison

Scott, Edward W. AmerenIP, Pawnee, IL

X X X

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

X X X X

Sher, Philip CT Dept. Public Utility Control, New Britain, CT

2nd V Chair

X

Siedlecki, Walter AEGIS Insurance Services, Inc., Jersey City, NJ

X X

Slagle, Richard Vectren Energy Delivery of OH, Evansville, IN

X SEC X Chair

Sprenger, Roger W. San Diego Gas & Elec. Co., San Diego, CA

X X X

Stewart, Lee Pacific Gas and Electric Co.

X X X

Strohm, Billy J. George Fischer Sloane, Little Rock, AR

X X

Themig, Jerome S. Ameren Services Co., Pawnee, IL

X X X

Torbin, Robert Cutting Edge Solutions, LLC, Framingham, MA

X X

Addendum No. 6, September 2006 lviii

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lix


DIVISIONS TASK GROUPS SECTIONS

iations:

st 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

R

egulations

Editorial

Executive

Liaison

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

X X

Ulanday, Alfredo S. Peoples Energy Corp., Chicago, IL

X X X

Veerapaneni, Ram DTE Energy - MichCon, Detroit, MI

X X X X

Volgstadt, Frank R. Volgstadt & Associates, Inc., Madison, OH

X SEC SEC

Weber, David E. Keyspan Corp., Waltham, MA

X X X X

Wilkes, Al Performance Pipe, Plano, TX

X X X

Wolf, Brian D. Iroquois Pipeline Operating Co., Shelton, CT

X X X

Wolf, Russell A. Willbros Engr., Inc., Tulsa, OK

X X

Zapalac, Daniel P. R.W. Lyall & Co., Inc., Corona, CA

X X



AbbrevChairperson: Chair First Vice Chairperson: 1

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Reserved

Addendum No. 6, September 2006 lx



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GPTC GUIDE FOR GAS TRANSMISSION AND §192.3 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART A

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

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

Thermosetting plastic is a plastic that is capable of being changed into a substantially infusible or insoluble product when cured under the application of heat or by chemical means.

Thickness. See Nominal wall thickness. Valve. See Curb valve and Service line valve. Vault is an underground structure which may be entered, and which is designed to contain piping and piping

components (such as valves or pressure regulators). Yield strength is the strength at which a material exhibits a specified limiting permanent set, or produces a

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

GLOSSARY OF COMMONLY USED ABBREVIATIONS

Abbreviation Meaning

ABS acrylonitrile-butadiene-styrene ASV automatic shut-off valve BAP baseline assessment plan CAB cellulose acetate butyrate CDA confirmatory direct assessment CGI combustible gas indicator DA direct assessment ECDA external corrosion direct assessment EFV excess flow valve EFVB excess flow valve – bypass (automatic reset) EFVNB excess flow valve – non-bypass (manual reset) ERW electric resistance welded ESD emergency shutdown FAQ frequently asked question HCA high consequence area HDB hydrostatic design basis HFI hydrogen flame ionization IC internal corrosion ICDA internal corrosion direct assessment ILI In-line inspection IMP integrity management program IR drop voltage drop LEL lower explosive limit LNG liquefied natural gas LPG liquid petroleum gas LTHS long-term hydrostatic strength MAOP maximum allowable operating pressure MRS minimum required strength NPS nominal pipe size O&M operations and maintenance OCS outer continental shelf OQ operator qualification

Addendum No. 6, September 2006 19Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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GLOSSARY OF COMMOMLY USED APPBREVIATIONS (Continued)

Abbreviation Meaning

PA Polyamide P&M measures preventive and mitigative measures PDB pressure design basis PE polyethylene PVC poly (vinyl chloride), also written as polyvinyl chloride RCV remote control valve SCADA supervisory control and data acquisition SCC stress corrosion cracking SCCDA stress corrosion cracking direct assessment SDB strength design basis SDR standard dimension ratio SMYS specified minimum yield strength

§192.5 Class locations.

[Effective Date: 7-13-98]

(a) This section classifies pipeline locations for purposes of this part. The following criteria apply to classifications under this section. (1) A "class location unit" is an onshore area that extends 220 yards (200 meters) on either side of the centerline of any continuous 1- mile (1.6 kilometers) length of pipeline. (2) Each separate dwelling unit in a multiple dwelling unit building is counted as a separate building intended for human occupancy. (b) Except as provided in paragraph (c) of this section, pipeline locations are classified as follows: (1) A Class 1 location is: (i) An offshore area; or (ii) Any class location unit that has 10 or fewer buildings intended for human occupancy. (2) A Class 2 location is any class location unit that has more than 10 but fewer than 46 buildings intended for human occupancy. (3) A Class 3 location is: (i) Any class location unit that has 46 or more buildings intended for human occupancy; or (ii) An area where the pipeline lies within 100 yards (91 meters) of either a building or a small, well-defined outside area (such as a playground, recreation area, outdoor theater, or other place of public assembly) that is occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12-month period. (The days and weeks need not be consecutive.) (4) A Class 4 location is any class location unit where buildings with four or more stories above ground are prevalent. (c) The length of Class locations 2, 3, and 4 may be adjusted as follows: (1) A Class 4 location ends 220 yards (200 meters) from the nearest building with four or more stories above ground. (2) When a cluster of buildings intended for human occupancy requires a Class 2 or 3 location, the class location ends 220 yards (200 meters) from the nearest building in the cluster.

Addendum No. 5, May 2006 20Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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[Amdt. 192-27, 41 FR 34598, Aug. 16, 1976; Amdt. 192-56, 52 FR 32924, Sept. 1, 1987; Amdt. 192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996 and Amdt. 192-78 Correction, 61 FR 35139, July 5, 1996; Amdt. 192-85, 63 FR 37500, July 13, 1998]

GUIDE MATERIAL

No guide material available at present.

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


(a) Any documents or portions thereof incorporated by reference in this part are included in this part as though set out in full. When only a portion of a document is referenced, the remainder is not incorporated in this part. (b) All incorporated materials are available for inspection in the Pipeline and Hazardous Materials Safety Administration, 400 Seventh Street, SW., Washington, DC, or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202–741–6030 or go to: http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html. These materials have been approved for incorporation by reference by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. In addition, the incorporated materials are available from the respective organizations listed in paragraph (c) (1) of this section. (c) The full titles of documents incorporated by reference, in whole or in part, are provided herein. The numbers in parentheses indicate applicable editions. For each incorporated document, citations of all affected sections are provided. Earlier editions of currently listed documents or editions of documents listed in previous editions of 49 CFR part 192 may be used for materials and components designed, manufactured, or installed in accordance with these earlier documents at the time they were listed. The user must refer to the appropriate previous edition of 49 CFR part 192 for a listing of the earlier listed editions or documents. (1) Incorporated by reference (IBR). List of Organizations and Addresses:

A. Pipeline Research Council International, Inc. (PRCI), c/o Technical Toolboxes, 3801 Kirby Drive, Suite 520, Houston, TX 77098.

B. American Petroleum Institute (API), 1220 L Street, NW, Washington, DC 20005. C. American Society for Testing and Materials (ASTM), 100 Barr Harbor Drive, West Conshohocken, PA 19428. D. ASME International (ASME), Three Park Avenue, New York, NY 10016–5990. E. Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS), 127 Park Street, NE, Vienna, VA 22180. F. National Fire Protection Association (NFPA), 1 Batterymarch Park, P.O. Box 9101, Quincy, MA 02269–9101. G. Plastics Pipe Institute, Inc. (PPI), 1825 Connecticut Avenue, NW, Suite 680, Washington, DC 20009. H. NACE International (NACE), 1440 South Creek Drive, Houston, TX 77084. I. Gas Technology Institute (GTI), 1700 South Mount Prospect Road, Des Plaines, IL 60018.



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

Source and name of referenced material 49 CFR reference

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

(1) AGA Pipeline Research Committee, Project PR–3–805, ‘‘A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe,’’ (December 22, 1989). The RSTRENG program may be used for calculating remaining strength.

§§192.933(a); 192.485(c).

B. American Petroleum Institute (API): (1) API Specification 5L ‘‘Specification for Line Pipe,’’ (43rd edition and errata, 2004).

§§192.55(e); 192.113; Item I of Appendix B.

(2) API Recommended Practice 5L1 ‘‘Recommended Practice for Railroad Transportation of Line Pipe,’’ (6th edition, 2002).

§192.65(a).

(3) API Specification 6D ‘‘Pipeline Valves,’’ (22nd edition, January 2002).

§192.145(a).

(4) API 1104 ‘‘Welding of Pipelines and Related Facilities,’’ (19th edition, 1999, including Errata October 31, 2001).

§§192.227(a); 192.229(c)(1); 192.241(c); Item II, Appendix B.

(5) API Recommended Practice 1162 ‘‘Public Awareness Programs for Pipeline Operators,’’ (1st Edition December 2003).

§§192.616(a); 192.616(b); 192.616(c).

C. American Society for Testing and Materials (ASTM): (1) ASTM A 53/A53M–04a (2004) ‘‘Standard Specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated, Welded and Seamless.’’

§§192.113; Item I, Appendix B.

(2) ASTM A106/A106M-04b (2004) ‘‘Standard Specification for Seamless Carbon Steel Pipe for High-Temperature Service.’’


(3) ASTM A333/A333M-05 (2005) ‘‘Standard Specification for Seamless and Welded Steel Pipe for Low-Temperature Service.’’


(4) ASTM A372/A372M-03 (2003) ‘‘Standard Specification for Carbon and Alloy Steel Forgings for Thin-Walled Pressure Vessels.’’

§ 192.177(b)(1).

(5) ASTM A381–96 (Reapproved 2001) ‘‘Standard Specification for Metal-Arc-Welded Steel Pipe for Use With High-Pressure Transmission Systems.’’


(6) ASTM A671-04 (2004) ‘‘Standard Specification for Electric-Fusion-Welded Steel Pipe for Atmospheric and Lower Temperatures.’’


(7) ASTM A672-96 (Reapproved 2001) ‘‘Standard Specification for Electric-Fusion-Welded Steel Pipe for High-Pressure Service at Moderate Temperatures.’’


Addendum No. 6, September 2006 22 Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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

(8) ASTM A691-98 (Reapproved 2002) ‘‘Standard Specification for Carbon and Alloy Steel Pipe, Electric-Fusion-Welded for High-Pressure Service at High Temperatures.’’


(9) ASTM D638-03 ‘‘Standard Test Method for Tensile Properties of Plastics.’’

§§192.283(a)(3); 192.283(b)(1).

(10) ASTM D2513-87 ‘‘Standard Specification for Thermoplastic Gas Pressure Pipe, Tubing, and Fittings.”

§192.63(a)(1).

(11) ASTM D2513-99 ‘‘Standard Specification for Thermoplastic Gas Pressure Pipe, Tubing, and Fittings.”

§§192.191(b); 192.281(b)(2); 192.283(a)(1)(i); Item I, Appendix B.

(12) ASTM D2517-00 ‘‘Standard Specification for Reinforced Epoxy Resin Gas Pressure Pipe and Fittings.’’

§§192.191(a); 192.281(d)(1); 192.283(a)(1)(ii); Item I, Appendix B.

(13) ASTM F1055-1998 ‘‘Standard Specification for Electrofusion Type Polyethylene Fittings for Outside Diameter Controlled Polyethylene Pipe and Tubing.’’

§192.283(a)(1)(iii).

D. ASME International (ASME): (1) ASME B16.1-1998 ‘‘Cast Iron Pipe Flanges and Flanged Fittings.’’

§192.147(c).

(2) ASME B16.5-2003 (October 2004) ‘‘Pipe Flanges and Flanged Fittings.’’

§§192.147(a); 192.279.

(3) ASME B31G-1991 (Reaffirmed; 2004) ‘‘Manual for Determining the Remaining Strength of Corroded Pipelines.’’

§§192.485(c); 192.933(a).

(4) ASME B31.8-2003 (February 2004) ‘‘Gas Transmission and Distribution Piping Systems.’’

§192.619(a)(1)(i).

(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).



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

(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). 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).



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[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]

GUIDE MATERIAL

This guide material is under review following Amendment 192-103. Additional standards and specifications recommended for use under this Guide, and the names and addresses of the sponsoring organizations, are shown in Guide Material Appendix G-192-1. See Guide Material Appendix G-192-1A for documents previously incorporated by reference in the Regulations.

§192.8 How are onshore gathering lines and regulated onshore gathering

lines determined? [Effective Date: 4-14-06]

(a) An operator must use API RP 80 (incorporated by reference, see §192.7), to determine if an onshore pipeline (or part of a connected series of pipelines) is an onshore gathering line. The determination is subject to the limitations listed below. After making this determination, an operator must determine if the onshore gathering line is a regulated onshore gathering line under paragraph (b) of this section. (1) The beginning of gathering, under section 2.2(a)(1) of API RP 80, may not extend beyond the furthermost downstream point in a production operation as defined in section 2.3 of API RP 80. This furthermost downstream point does not include equipment that can be used in either production or transportation, such as separators or dehydrators, unless that equipment is involved in the processes of ‘‘production and preparation for transportation or delivery of hydrocarbon gas’’ within the meaning of ‘‘production operation.’’ (2) The endpoint of gathering, under section 2.2(a)(1)(A) of API RP 80, may not extend beyond the first downstream natural gas processing plant, unless the operator can demonstrate, using sound engineering principles, that gathering extends to a further downstream plant. (3) If the endpoint of gathering, under section 2.2(a)(1)(C) of API RP 80, is determined by the commingling of gas from separate production fields, the fields may not be more than 50 miles from each other, unless the Administrator finds a longer separation distance is justified in a particular case (see 49 CFR §190.9). (4) The endpoint of gathering, under section 2.2(a)(1)(D) of API RP 80, may not extend beyond the furthermost downstream compressor used to increase gathering line pressure for delivery to another pipeline. (b) For purposes of §192.9, ‘‘regulated onshore gathering line’’ means: (1) Each onshore gathering line (or segment of onshore gathering line) with a feature described in the second column that lies in an area described in the third column; and (2) As applicable, additional lengths of line described in the fourth column to provide a safety buffer:



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Type Feature Area Safety Buffer

A — Metallic and the MAOP produces a hoop stress of 20 percent or more of SMYS. If the stress level is unknown, an operator must determine the stress level according to the applicable provisions in subpart C of this part. — Non-metallic and the MAOP is more than 125 psig (862 kPa).

Class 2, 3, or 4 location (see §192.5).

None.

B — Metallic and the MAOP produces a hoop stress of less than 20 percent of SMYS. If the stress level is unknown, an operator must determine the stress level according to the applicable provisions in subpart C of this part. — Non-metallic and the MAOP is 125 psig (862 kPa) or less.

Area 1. Class 3 or 4 location. Area 2. An area within a Class 2 location the operator determines by using any of the following three methods: (a) A Class 2 location. (b) An area extending 150 feet (45.7 m) on each side of the centerline of any continuous 1 mile (1.6 km) of pipeline and including more than 10 but fewer than 46 dwellings. (c) An area extending 150 feet (45.7 m) on each side of the centerline of any continuous 1000 feet (305 m) of pipeline and including 5 or more buildings.

If the gathering line is in Area 2(b) or 2(c), the additional lengths of line extend upstream and downstream from the area to a point where the line is at least 150 feet (45.7 m) from the nearest dwelling in the area. However, if a cluster of dwellings in area 2(b) or 2(c) qualifies a line as Type B, the Type B classification ends 150 feet (45.7 m) from the nearest dwelling in the cluster.

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

GUIDE MATERIAL


Addendum No. 5, May 2005 26 Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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GPTC GUIDE FOR GAS TRANSMISSION AND 192.111 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART C

(4) Is used in a fabricated assembly, (including separators, mainline valve assemblies, cross-connections, and river crossing headers) or is used within five pipe diameters in any direction from the last fitting of a fabricated assembly, other than a transition piece or an elbow used in place of a pipe bend which is not associated with a fabricated assembly. (c) For Class 2 locations, a design factor of 0.50, or less, must be used in the design formula in §192.105 for uncased steel pipe that crosses the right-of-way of a hard surfaced road, a highway, a public street, or a railroad. (d) For Class 1 and Class 2 locations, a design factor of 0.50, or less, must be used in the design formula in §192.105 for -- (1) Steel pipe in a compressor station, regulating station, or measuring station; and (2) Steel pipe, including a pipe riser, on a platform located offshore or in inland navigable waters. [Amdt. 192-27, 41 FR 34598, Aug. 16, 1976]

GUIDE MATERIAL 1 USE OF DESIGN FACTOR (F) FOR STEEL PIPE IN §§192.111(b), (c), and (d)

INSTALLATION CONDITION LOCATION CLASS

1 2 3 4

Crossings without casings of:

Private roads (See Note 1) .72 .60 .50 .40

The rights-of-way of unimproved public roads .60 .60 .50 .40

The rights-of-way of hard surfaced roads, highways, public streets, railroads

.60 .50 .50 .40

Crossings with casings of:




.72 .60 .50 .40

Parallel encroachments on:




.60 .60 .50 .40

Amendment No. 6, September 2006 39 Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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INSTALLATION CONDITION (Continued) LOCATION CLASS

1 2 3 4

Pipelines on bridges .60 .60 .50 .40

Fabricated assemblies (See Note 2) .60 .60 .50 .40

Compressor, regulating, or measuring station piping .50 .50 .50 .40

Pipe, including pipe risers, on platforms located offshore .50 N/A N/A N/A

Pipe, including risers, on platforms located in inland navigable waters .50 .50 .50 .40

Notes: 1. "Private roads" are roads that are not intended for use by the general public and over which travel

and transportation are restricted. 2. Section 192.165(b)(3) requires that liquid separators located in compressor stations and

constructed of pipe and fittings without internal welding must be fabricated with a design factor (F) of 0.40, or less.

TABLE 192.111i

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

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


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

Specification

Pipe Class

Longitudinal Joint Factor (E)

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

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

1.00 1.00 0.60 1.00 1.00 1.00 1.00 1.00



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Specification (Continued)

Pipe Class

Longitudinal Joint Factor (E)

ASTM A 672 ASTM A 691 API 5L Other Other

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

1.00 1.00 1.00 1.00 1.00 1.00 0.60 0.80 0.60

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

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

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


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

Gas temperature in degrees

Fahrenheit (Celsius)

Temperature derating

factor ( T )

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

1.000 0.967 0.933 0.900 0.867

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



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GUIDE MATERIAL

No guide material necessary.

§192.117 (Removed and reserved.)


§192.119 (Removed and reserved.)


§192.121 Design of plastic pipe.


Subject to the limitations of §192.123, the design pressure for plastic pipe is determined in accordance with either of the following formulas: P = 2S t 0.32 (D-t) P = 2S 0.32 (SDR-1) Where: P = Design pressure, gauge, kPa (psig). 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 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).

t = Specified wall thickness, mm (in.). D = Specified outside diameter, mm (in.). 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.

[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]



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GUIDE MATERIAL

This guide material is under review following Amendments 192-94. 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 D 2513 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 D 2513, 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 D 2517 is 11,000 psi.

(e) HDB values apply only to materials meeting all the requirements of ASTM D 2513 and are based on engineering test data analyzed in accordance with ASTM D 2837, "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 D 2513 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 D 2513 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 D 2513 earlier than 2001. The operator is advised to check §192.7.

TABLE 192.121i

2 PETROLEUM GASES

PE and PA materials listed in ASTM D 2513 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.



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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, kPa (psi) D = Specified outside diameter, mm (in.) S = The long-term hydrostatic strength, for thermoplastic pipe, kPa (psi) determined at 23 oC

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

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

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

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

)1 1(

)1 1)((

HL

TLHL

LT

TT

TTSS

SS−

−−−=

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)



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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) 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).



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(d) The wall thickness for reinforced thermosetting plastic pipe may not be less than that listed in the following table:

Nominal size in

inches (millimeters)

Minimum wall thickness in

inches (millimeters)

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

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

(e) The design pressure for thermoplastic pipe produced after July 14, 2004 may exceed a gauge pressure of 100 psig (689 kPa) provided that: (1) The design pressure does not exceed 125 psig (862 kPa); (2) The material is a PE2406 or a PE3408 as specified within ASTM D2513 (incorporated by reference, see §192.7); (3) The pipe size is nominal pipe size (IPS) 12 or less; and (4) The design pressure is determined in accordance with the design equation defined in §192.121. [Amdt. 192-31, 43 FR 13880, Apr. 3, 1978; Amdt. 192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-93, 68 FR 53895, Sept. 15, 2003; Amdt. 192-94, 69 FR 32886, June 14, 2004 with Amdt. 192-94 Correction, 69 FR 54591, Sept. 9, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006]

GUIDE MATERIAL

This guide material is under review following Amendment 192-94. 1 IMPACT AND DUCTILITY The impact and ductility properties of plastics should be evaluated when the material is intended for use

in facilities subjected to low temperatures. 2 PETROLEUM GASES The pressure-temperature relationship with petroleum gases should be such that condensation will not

occur when using PE piping. 3 HOT TAPS (a) To minimize the probability of a blowout when making a hot-plate saddle fusion on polyethylene

(PE) pipe with a wall thickness of 0.216 inches or less, operating at pressures up to and including 100 psig, it may be necessary to require heavier wall thickness than determined by the pressure design formula. The manufacturer of the PE pipe should be contacted for recommendations.

(b) For those PE pipelines operated at pressures greater than 100 psig, the probability of blowouts when making hot-plate saddle fusions increases due to the increased pressure. The pipeline pressure may need to be reduced during such fusions.

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

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



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4 EFFECTS OF LIQUID HYDROCARBONS 4.1 General.

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

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

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

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

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

TABLE 192.123i

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

should be consulted to determine the appropriate DFC.

4.3 References. (a) PA pipe. (1) “An Evaluation of Polyamide 11 for Use in High Pressure/High Temperature Gas Piping

Systems,” T.J. Pitzi et al., 15th Plastic Fuel Gas Pipe Symposium Proceedings - 1997, p. 107. (2) “Polyamide 11 Liners Withstand Hydrocarbons, High Temperature,” A. Berry, Pipeline & Gas

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

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

Gases.” (3) “Mechanical Integrity of Fusion Joints Made from Polyethylene Pipe Exposed to Heavy

Hydrocarbons,” S.M. Pimputkar, 14th Plastic Fuel Gas Pipe Symposium Proceedings - 1995, p. 141.

(4) “Strength of Fusion Joints Made from Polyethylene Pipe Exposed to Heavy Hydrocarbons,” S.M. Pimputkar, 15th Plastic Fuel Gas Pipe Symposium Proceedings - 1997, p. 309.

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

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



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

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

§192.125 Design of copper pipe.


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

Standard size inch

(millimeter)

Nominal O.D. inch

(millimeter)

Wall thickness inch (millimeter)

Nominal Tolerance

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

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

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

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

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

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



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GPTC GUIDE FOR GAS TRANSMISSION AND §192.141 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART D

SUBPART D DESIGN OF PIPELINE COMPONENTS

§192.141 Scope.


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

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.


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



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[Amdt. 192-48, 49 FR 19823, May 10, 1984]

GUIDE MATERIAL The designer should select components that will withstand the field test pressure to which they will be subjected without failure or leakage and without impairment to their serviceability. Consideration should also be given to pulsation-induced vibrations that could produce excessive cyclic stresses. See Guide Material Appendix G-192-9 and Guide Material Appendix G-192-10.

§192.144 Qualifying Metallic Components.


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

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.

§192.145 Valves.


(a) Except for cast iron and plastic valves, each valve must meet the minimum requirements of API 6D (incorporated by reference, see §192.7), or to a national or international standard that provides an equivalent



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performance level. A valve may not be used under operating conditions that exceed the applicable pressure-temperature ratings contained in those requirements. (b) Each cast iron and plastic valve must comply with the following: (1) The valve must have a maximum service pressure rating for temperatures that equal or exceed the maximum service temperature. (2) The valve must be tested as part of the manufacturing, as follows: (i) With the valve in the fully open position, the shell must be tested with no leakage to a pressure at least 1.5 times the maximum service rating. (ii) After the shell test, the seat must be tested to a pressure not less than 1.5 times the maximum service pressure rating. Except for swing check valves, test pressure during the seat test must be applied successively on each side of the closed valve with the opposite side open. No visible leakage is permitted. (iii) After the last pressure test is completed, the valve must be operated through its full travel to demonstrate freedom from interference. (c) Each valve must be able to meet the anticipated operating conditions. (d) No valve having shell components made of ductile iron may be used at pressures exceeding 80 percent of the pressure ratings for comparable steel valves at their listed temperature. However, a valve having shell components made of ductile iron may be used at pressures up to 80 percent of the pressure ratings for comparable steel valves at their listed temperature, if -- (1) The temperature-adjusted service pressure does not exceed 1,000 p.s.i (7MPa) gage; and (2) Welding is not used on any ductile iron component in the fabrication of the valve shells or their assembly. (e) No valve having pressure-containing parts made of ductile iron may be used in the gas pipe components of compressor stations. [Amdt. 192-3, 35 FR 17659, Nov. 17, 1970; Amdt. 192-22, 41 FR 13589, Mar. 31, 1976; Amdt. 192-37, 46 FR 10157, Feb. 2, 1981; Amdt. 192-62, 54 FR 5625, Feb. 6, 1989; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-94, 69 FR 32886, June 14, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006]

GUIDE MATERIAL 1 FLANGED CAST IRON VALVES IN STEEL PIPELINES Consideration should be given to the effect of secondary stresses (e.g., resulting from earth movement,

expansion and contraction or other external forces) which could affect the structural integrity of flanged cast iron valves in steel pipelines. Adequate support, compression couplings, or other means may be used.

2 EQUIVALENCY 2.1 Equivalent standards. Valve standards API Spec 6A, API Std 600, ASME B16.33, ASME B16.34, and ASME B16.38 provide

an equivalent performance level to API Spec 6D for gas application purposes. 2.2 Valves not listed in API Spec 6D. Although all valve sizes (such as those smaller than 2 inches) are not listed in API Spec 6D,

manufacturers may design, build and test non-listed sizes in accordance with all applicable requirements of API Spec 6D and, thereby, meet the equivalency criteria. However, application of the API monogram to valve sizes not listed in the API Specification is not permitted.



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

material(s) which require a reduced maximum temperature limit should be provided with markings on the nameplate showing the maximum pressure rating at that temperature and with the pressure rating at 100 oF.

§192.147 Flanges and flange accessories.


(a) Each flange or flange accessory (other than cast iron) must meet the minimum re-quirements of ASME/ANSI B16.5, MSS SP-44, or the equivalent. (b) Each flange assembly must be able to withstand the maximum pressure at which the pipeline is to be operated and to maintain its physical and chemical properties at any temperature to which it is anticipated that it might be subjected in service. (c) Each flange on a flanged joint in cast iron pipe must conform in dimensions, drilling, face and gasket design to ASME/ANSI B16.1 and be cast integrally with the pipe, valve, or fitting. [Amdt. 192-62, 54 FR 5625, Feb. 6, 1989; Amdt. 192-68, 58 FR 14519, Mar. 18, 1993]

GUIDE MATERIAL 1 FLANGES 1.1 Flange types. (a) The dimensions and drilling for all line or end flanges should conform to one of the following

standards. ASME B16 Series listed in Appendix A (for iron and steel) MSS SP-44 Steel Pipe Line Flanges Flanges cast or forged integral with pipe, fittings or valves in sizes and for the maximum service

rating covered by the standards listed above may be used subject to the facing, bolting and gasketing requirements of this paragraph and 1.2, 2.1 and 2.2 below.

(b) Threaded companion flanges that comply with the B16 group of American National Standards, in sizes and for maximum service ratings covered by these standards, may be used.

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

Slip-on flanges or rectangular section may be substituted for hubbed slip-on flanges provided the thickness is increased as required to produce equivalent strength as determined by calculations made in accordance with Section VIII, Pressure Vessels, of the ASME Boiler and Pressure Vessel Code.

(e) Welding neck flanges in sizes and pressure standards established in ASME B16.5, ASME B16.47, and MSS SP-44 may be used. The bore of the flanges should correspond to the inside diameter of the pipe used. For acceptable welding end treatment see Figure 192.235B in Guide Material Appendix G-192-5.

(f) Flanges made of ductile iron should conform to material and dimensional standards listed in §192.145(a) and should be subject to all service restrictions as outlined for valves in that paragraph. The bolting requirements for ductile iron flanges should be the same as for carbon and low alloy steel flanges as listed in 2.1 below.



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GPTC GUIDE FOR GAS TRANSMISSION AND §192.221 DISTRIBUTION PIPING SYSTEMS: 2003 Edition Subpart E

SUBPART E WELDING OF STEEL IN PIPELINES

§192.221 Scope.


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

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."



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(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 appendix A 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]

GUIDE MATERIAL 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.



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(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 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.



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GUIDE MATERIAL


§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.



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

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

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

§192.237 (Removed.)


§192.239 (Removed.)


§192.241 Inspection and test of welds.


(a) Visual inspection of welding must be conducted by an individual qualified by appropriate training and experience to ensure that: (1) The welding is performed in accordance with the welding procedure; and (2) The weld is acceptable under paragraph (c) of this section. (b) The welds on a pipeline to be operated at a pressure that produces a hoop stress of 20 percent or more of SMYS must be nondestructively tested in accordance with §192.243, except that welds that are visually inspected and approved by a qualified welding inspector need not be nondestructively tested if -- (1) The pipe has a nominal diameter of less than 6 inches (152 millimeters); or (2) The pipeline is to be operated at a pressure that produces a hoop stress of less than 40 percent of SMYS and the welds are so limited in number that nondestructive testing is impractical. (c) The acceptability of a weld that is nondestructively tested or visually inspected is determined according to the standards in Section 9 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.



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[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 Amendment 192-94. 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) Inspection should be performed by qualified individuals with consideration given to the following. (1) Experience. (2) Training. (3) Results of qualification examinations, if any. (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



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GPTC GUIDE FOR GAS TRANSMISSION AND §192.279 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART F

§192.279 Copper pipe.


Copper pipe may not be threaded except that copper pipe used for joining screw fittings or valves may be threaded if the wall thickness is equivalent to the comparable size of Schedule 40 or heavier wall pipe listed in Table C1 of ASME/ANSI B16.5. [Amdt. 192-62, 54 FR 5625, Feb. 6, 1989; Amdt. 192-68, 58 FR 14519, Mar. 18, 1993]

GUIDE MATERIAL (a) Copper pipe may be joined by a mechanical joint or a brazed or soldered lap joint. The filler material used for brazing should be a copper-phosphorous or a silver base alloy. (b) Butt welds should not be used for joining copper pipe or copper tubing.

§192.281 Plastic pipe.


(a) General. A plastic pipe joint that is joined by solvent cement, adhesive, or heat fusion may not be disturbed until it has properly set. Plastic pipe may not be joined by a threaded joint or miter joint. (b) Solvent cement joints. Each solvent cement joint on plastic pipe must comply with the following: (1) The mating surfaces of the joint must be clean, dry, and free of material which might be detrimental to the joint. (2) The solvent cement must conform to ASTM Designation D 2513. (3) The joint may not be heated to accelerate the setting of the cement. (c) Heat-fusion joints. Each heat-fusion joint on plastic pipe must comply with the following: (1) A butt heat-fusion joint must be joined by a device that holds the heater element square to the ends of the piping, compresses the heated ends together, and holds the pipe in proper alignment while the plastic hardens. (2) A socket heat-fusion joint must be joined by a device that heats the mating surfaces of the joint uniformly and simultaneously to essentially the same temperature. (3) An electrofusion joint must be joined utilizing the equipment and techniques of the fittings manufacturer or equipment and techniques shown, by testing joints to the requirements of §192.283(a)(1)(iii), to be at least equivalent to those of the fittings manufacturer. (4) Heat may not be applied with a torch or other open flame. (d) Adhesive joints. Each adhesive joint on plastic pipe must comply with the following: (1) The adhesive must conform to ASTM Designation D 2517. (2) The materials and adhesive must be compatible with each other. (e) Mechanical joints. Each compression type mechanical joint on plastic pipe must comply with the following: (1) The gasket material in the coupling must be compatible with the plastic. (2) A rigid internal tubular stiffener, other than a split tubular stiffener, must be used in conjunction with the coupling.

99 Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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GPTC GUIDE FOR GAS TRANSMISSION AND §192.281 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART F [Amdt. 192-34, 44 FR 42968, July 23, 1979 with Amdt. 192-34 Correction, 44 FR 50841, Aug. 30, 1979 and Amdt. 192-34 Correction, 44 FR 57100, Oct. 4, 1979; Amdt. 192-58, 53 FR 1633, Jan. 21, 1988; Amdt. 192-61, 53 FR 36793, Sept. 22, 1988; 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]

GUIDE MATERIAL 1 INTRODUCTION (Plastic-to-plastic and plastic-to-metal) To achieve sound joints in plastic piping requires skillful application of qualified procedures and the use

of proper materials and equipment in good condition. Joints should be made by personnel qualified by training or experience in the written procedures required for the type of joint involved.

2 GENERAL (Plastic-to-plastic) Plastic piping is joined by several material-specific joining methods including solvent cement, heat

fusion, and adhesives as described below. All plastic piping materials may be joined by mechanical methods. The Regulations require that the joining procedures be qualified and that joining personnel and inspectors be trained and qualified. (See §§192.281, 192.283, 192.285, and 192.287.)

3 FIELD JOINING (Plastic-to-plastic and plastic-to-metal) 3.1 Solvent cement for repairing PVC piping only. (Plastic-to-plastic)

Note: Editions of ASTM D 2513 issued after 2001 no longer permit use of PVC piping for new 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 D 2513 earlier than 2001. The operator is advised to check §192.7.

(a) The solvent cement and piping components may be conditioned prior to assembly by warming, provided that it is done in accordance with the manufacturer's recommendations. Special precautions are required when the surface temperature of the material is below 50 oF or above 100 oF.

(b) Square cut ends, free of burrs, are required for a proper socket joint. Beveling of the leading edge of the spigot end will provide for ease of insertion and better distribution of the cement.

(c) Proper fit between the pipe or tubing and the mating socket or sleeve is essential to a good joint. Before application of cement, the pipe or tubing should freely enter the fitting but should not bottom against the internal shoulder. Sound joints cannot normally be made between components that have a loose or very tight fit.

(d) A uniform coating of the solvent cement is required on both mating surfaces. A light coating should be applied to the socket and a heavier coating applied to the pipe or tubing. The pipe should immediately be inserted into the socket and bottomed in the socket.

For diameters greater than 2 inches, additional measures may be necessary to bottom the pipe.

The completed joint should be held together for sufficient time to prevent the pipe from backing out of the fitting. After the joint is made, excess cement should be removed from the outside of the joint.

(e) The joint should not be subject to a pressure test until it has developed a high percentage of its ultimate strength. The time required for this to occur varies with the type of cement, humidity, and temperature.

(f) Other recommendations for making joints may be found in ASTM D 2855 (for PVC), the Appendix of ASTM D 2235 (for ABS), and the Appendix of ASTM D 2560 (for CAB).



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GPTC GUIDE FOR GAS TRANSMISSION AND §192.281 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART F 3.2 Heat fusion for PA-to-PA and PE-to-PE only by externally applied heat. (Plastic-to-plastic) (a) PA and PE cannot be fused to each other. (b) General training programs that include both printed material and slides are available from the

Plastics Pipe Institute (see Guide Material Appendix G-192-1) and many manufacturers of plastic pipe.

(c) Care should be used in the heating operation. The material should be sufficiently heated to produce a sound joint but not overheated to the extent that the material is damaged.

(d) Square cut ends, free of burrs, are required for a proper joint. (e) The mating surfaces should be clean, dry, and free of material which might be detrimental to the

joint. (f) Other recommendations for making heat-fusion joints may be found in ASTM D 2657. (g) PE piping of different compounds or grades can be heat fused to each other. Such joining should

not be undertaken indiscriminately, and should be undertaken only when qualified procedures for joining the specific compounds are used. Suggested references are as follows.

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

(2) PPI TR-33, “Generic Butt Fusion Joining Procedure for Polyethylene Gas Pipe.” (3) PPI TR-41, “Generic Saddle Fusion Joining Procedure for Polyethylene Gas Piping.” (h) Rain, cold, and windy weather conditions can influence fusion quality. Modification of the

recommended heating time in the procedure should be given consideration during such conditions. (i) For hot taps on PE, see the guide material under §192.123. (j) The condition of equipment for heat fusing PE must conform to the equipment manufacturer's

recommended tolerances for acceptable wear of critical components. The use of damaged or worn equipment may result in fusion joints that are weak or out of alignment. The frequency of inspection should be determined by the operator based on equipment usage, equipment age and condition, and manufacturer's recommendation. See Guide Material Appendix G-192-20 for a sample inspection form.

3.3 Heat-fusion by electrofusion. (Plastic-to-plastic) (a) Sections 192.273 and 192.283 require that procedures for making joints other than by welding be

written and qualified. Each electrofusion equipment manufacturer is a source of appropriate procedures for their respective system. The operator should check state requirements on the use of electrofusion. Generally each procedure should contain some or all of the following elements:

(1) Couplings. (i) The pipe should be cut at a square angle. (ii) The pipe should be marked with the proper stab depth for the fitting. (iii) Surface oxidation should be removed from the area of the pipe to be fused, up to the

stab-depth marks, using the tool specified in the qualified procedure. (iv) One end of the pipe should be secured in an appropriate clamping device, the fitting slid

onto pipe, the second piece of pipe placed into clamp, and the fitting slid to final position onto each pipe so it is properly aligned. Insertion up to the stab-depth marks should be ensured.

(v) The control box should be tested for proper function. (vi) The fitting should be connected to the fusion control box and the cycle activated. The

fitting should be left in the clamp until cooling has been completed. (vii) The joint should be inspected in accordance with §192.273. (2) Sidewall fittings. (i) Determine the pipe area where the fitting is to be fused. (ii) All surface oxidation should be removed from the pipe in the area to be fused using the

tool specified in the qualified procedure. (iii) The fitting should be positioned and clamped in the cleaned area. (iv) The control box should be tested for proper function. (v) The fitting should be connected to the fusion control box and the cycle activated. The

fitting should be left in the clamp until cooling has been completed. (vi) The joint should be inspected in accordance with §192.273.



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GPTC GUIDE FOR GAS TRANSMISSION AND §192.281 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART F (b) The following are references for joining plastic pipe by electrofusion. (1) ASTM F 1055, "Standard Specification for Electrofusion Type Polyethylene Fittings for Outside

Diameter Controlled Polyethylene Pipe and Tubing." (2) ASTM F 1290, "Standard Practice for Electrofusion Joining Polyolefin Pipe and Fittings." (3) PPI Technical Committee Project 141, "Standard Practice for Electrofusion Joining Polyolefin

Pipe and Fittings." 3.4 Adhesive for thermosetting pipe only. (Plastic-to-plastic) (a) The mating surfaces should be suitably prepared and should be dry and free of material that might

be detrimental to the joint. (b) Adhesive should be properly mixed and liberally applied on both mating surfaces. The assembled

joint should be held together in alignment for sufficient time to prevent the pipe or tubing from backing out of the fitting.

(c) The assembled joint should not be disturbed until the adhesive has properly set. The joint should not be subjected to a pressure test until it has developed a high percentage of its ultimate strength. The time required for this to occur varies with the adhesive, humidity, and ambient temperature.

(d) To accelerate curing, an adhesive bonded joint may be heated in accordance with the manufacturer's recommendation.

3.5 Mechanical joints for all plastic piping. (Plastic-to-plastic and plastic-to-metal) (a) When compression type mechanical joints are used, the elastomeric gasket material in the fitting

should be compatible with the plastic; that is, neither the plastic nor the elastomer should cause deterioration in chemical or mechanical properties to the other over a long period.

(b) A stiffener is required for thermoplastic piping. The tubular stiffener required to reinforce the end of the pipe or tubing should extend at least under that section of the pipe compressed by the gasket or gripping material. The stiffener should be free of rough or sharp edges that could damage the piping. Stiffeners that fit the pipe or tube too tightly or too loosely may cause defective joining. The operator should check with the manufacturer for recommendations.

(c) The pull-out resistance of compression-type fittings varies with the type and size of the fitting and the wall thickness of the pipe being joined. ASTM D 2513 describes requirements for three categories of mechanical fittings.

(1) Category 1 – full seal, full restraint. These types of mechanical fittings, when properly installed, are designed to provide a joint that is stronger than the piping being connected.

(2) Category 2 – full seal, no restraint. (3) Category 3 – full seal, partial restraint. (d) All mechanical joints should be designed and installed to effectively sustain the longitudinal pull-out

forces caused by contraction of the piping and by maximum anticipated external loading. To minimize these forces, practices such as the following should be used.

(1) With direct burial, snaking the pipe in the ditch when the pipe is sufficiently flexible. (2) With insertion in a casing, pushing the pipe into place so that it is in compression rather than

tension. (3) Allowing for the effect of thermal expansion and contraction of installed pipe due to seasonal

changes in the temperature. The importance of this allowance increases with the length of the installation. This allowance may be accomplished by the following:

(i) Offsets. (ii) Anchoring. (iii) Strapping the joint. (iv) Placing the pipe in slight axial compression. (v) Expansion-contraction devices. (vi) Fittings designed to prevent pull-out (ASTM D 2513, Categories 1 and 3). (vii) Combinations of the above. This allowance is of paramount importance when the plastic pipe is used for insertion inside

another pipe because it is not restrained. Coefficients of thermal expansion for thermoplastic materials determined using ASTM D 696 are listed in Table 192.281i.



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GPTC GUIDE FOR GAS TRANSMISSION AND §192.281 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART F

COEFFICIENTS OF THERMAL EXPANSION

Pipe Material

Nominal Coefficients of Thermal Expansion1

(x 10-5 in./in./oF)

Expansion (in./100 ft. pipe/oF increase)

PA 32312 (PA 11) 8.5 0.108

PE 2406 9.0 0.108 PE 3408 9.0 0.108

PVC 1120 3.0 0.036 PVC 2116 4.0 0.048 1Individual compounds may differ from the values in this table by as much as ±10 percent. More exact values for specific commercial products may be obtained from the manufacturer.

PA = polyamide

PE = polyethylene

PVC = poly (vinyl chloride)

TABLE 192.281i

§192.283 Plastic pipe: Qualifying joining procedures.


(a) Heat fusion, solvent cement, and adhesive joints. Before any written procedure established under §192.273(b) is used for making plastic pipe joints by a heat fusion, solvent cement, or adhesive method, the procedure must be qualified by subjecting specimen joints made according to the procedure to the following tests: (1) The burst test requirements of -- (i) In the case of thermoplastic pipe, paragraph 6.6 (sustained pressure test) or paragraph 6.7 (Minimum Hydrostatic Burst Test) or paragraph 8.9 (Sustained Static pressure Test) of ASTM D2513 (incorporated by reference, see §192.7); (ii) In the case of thermosetting plastic pipe, paragraph 8.5 (Minimum Hydrostatic Burst Pressure) or paragraph 8.9 (Sustained Static Pressure Test) of ASTM D2517 (incorporated by reference, see §192.7); or (iii) In the case of electrofusion fittings for polyethylene pipe and tubing, paragraph 9.1 (Minimum Hydraulic Burst Pressure Test), paragraph 9.2 (Sustained Pressure Test), paragraph 9.3 (Tensile Strength Test), or paragraph 9.4 (Joint Integrity Tests) of ASTM Designation F1055 (incorporated by reference, see §192.7). (2) For procedures intended for lateral pipe connections, subject a specimen joint made from pipe sections joined at right angles according to the procedure to a force on the lateral pipe until failure occurs in the specimen. If failure initiates outside the joint area, the procedure qualifies for use; and (3) For procedures intended for nonlateral pipe connections, follow the tensile test



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GPTC GUIDE FOR GAS TRANSMISSION AND §192.283 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART F requirements of ASTM D638 (incorporated by reference, see §192.7), except that the test may be conducted at ambient temperature and humidity. If the specimen elongates no less than 25 percent or failure initiates outside the joint area, the procedure qualifies for use. (b) Mechanical joints. Before any written procedure established under §192.273(b) is used for making mechanical plastic pipe joints that are designed to withstand tensile forces, the procedure must be qualified by subjecting 5 specimen joints made according to the procedure to the following tensile test: (1) Use an apparatus for the test as specified in ASTM D 638 (except for conditioning), (incorporated by reference, see §192.7). (2) The specimen must be of such length that the distance between the grips of the apparatus and the end of the stiffener does not affect the joint strength. (3) The speed of testing is 0.20 in (5.0 mm) per minute, plus or minus 25 percent. (4) Pipe specimens less than 4 inches (102 mm) in diameter are qualified if the pipe yields to an elongation of no less than 25 percent or failure initiates outside the joint area. (5) Pipe specimens 4 inches (102 mm) and larger in diameter shall be pulled until the pipe is subjected to a tensile stress equal to or greater than the maximum thermal stress that would be produced by a temperature change of 100 oF (38 oC) or until the pipe is pulled from the fitting. If the pipe pulls from the fitting, the lowest value of the five test results or the manufacturer's rating, whichever is lower must be used in the design calculations for stress. (6) Each specimen that fails at the grips must be retested using new pipe. (7) Results obtained pertain only to the specific outside diameter, and material of the pipe tested, except that testing of a heavier wall pipe may be used to qualify pipe of the same material but with a lesser wall thickness. (c) A copy of each written procedure being used for joining plastic pipe must be available to the persons making and inspecting joints. (d) Pipe or fittings manufactured before July 1, 1980, may be used in accordance with procedures that the manufacturer certifies will produce a joint as strong as the pipe. [Issued by Amdt. 192-34, 44 FR 42968, July 23, 1979 with Amdt. 192-34 Time Ext., 44 FR 50841, Aug. 30, 1979, Amdt. 192-34 Time Ext., 44 FR 57100, Oct. 4, 1979, Amdt. 192-34A, 45 FR 9931, Feb. 14, 1980, Amdt. 192-34B, 46 FR 39, Jan. 2, 1981, Amdt. 192-34 Correction, 47 FR 32720, July 29, 1982 and Amdt. 192-34 Correction, 47 FR 49973, Nov. 4, 1982; 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. 192-85,63 FR 37500, July 13, 1998; Amdt. 192-94, 69 FR 32886, June 14, 2004 with Amdt. 192-94 Correction, 69 FR 54591, Sept. 9, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006]

GUIDE MATERIAL 1 WRITTEN PROCEDURES (a) An operator may elect to develop and qualify joining procedures or may follow the joining

procedures qualified by piping or fitting manufacturers. In either instance, the operator is responsible for ensuring that the joining procedure used is qualified in accordance with the requirements of §192.283.

(b) When a manufacturer's qualified joining procedure is used, the manufacturer should supply written

procedures, including pictures, demonstrating the appearance of satisfactory joints. Written procedures for fitting installation are often packaged with each fitting.

(c) Qualified procedures should be in the operator’s installation manuals and may be printed on wallet

or shirt pocket cards, or made available by other means.



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GPTC GUIDE FOR GAS TRANSMISSION AND §192.301 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART G

SUBPART G GENERAL CONSTRUCTION REQUIREMENTS

FOR TRANSMISSION LINES AND MAINS

§192.301 Scope.


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

GUIDE MATERIAL


§192.303 Compliance with specifications or standards.


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

GUIDE MATERIAL


§192.305 Inspection: General.


Each transmission line or main must be inspected to ensure that it is constructed in accordance with this part.

GUIDE MATERIAL (a) Each operator should provide inspection by persons qualified by either experience or training. Inspection

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

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



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§192.307 Inspection of materials.


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

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

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

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

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

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

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

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

§192.309 Repair of steel pipe.


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

110 Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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GPTC GUIDE FOR GAS TRANSMISSION AND §192.319 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART G 3.4 Consolidation. If trench flooding is used to consolidate the backfill, care should be taken to see that the pipe is not

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

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

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

drilling to install steel pipelines.

§192.321 Installation of plastic pipe.


(a) Plastic pipe must be installed below ground level except as provided by paragraphs (g) and (h) of this section. (b) Plastic pipe that is installed in a vault or any other below grade enclosure must be completely encased in gas-tight metal pipe and fittings that are adequately protected from corrosion. (c) Plastic pipe must be installed so as to minimize shear or tensile stresses. (d) Thermoplastic pipe that is not encased must have a minimum wall thickness of 0.090 inch (2.29 millimeters), except that pipe with an outside diameter of 0.875 inch (22.3 millimeters) or less may have a minimum wall thickness of 0.062 inch (1.58 millimeters). (e) Plastic pipe that is not encased must have an electrically conducting wire or other means of locating the pipe while it is underground. Tracer wire may not be wrapped around the pipe and contact with the pipe must be minimized but is not prohibited. Tracer wire or other metallic elements installed for pipe locating purposes must be resistant to corrosion damage, either by use of coated copper wire or by other means. (f) Plastic pipe that is being encased must be inserted into the casing pipe in a manner that will protect the plastic. The leading end of the plastic must be closed before insertion. (g) Uncased plastic pipe may be temporarily installed above ground level under the following conditions: (1) The operator must be able to demonstrate that the cumulative aboveground exposure of the pipe does not exceed the manufacturer's recommended maximum period of exposure or 2 years, whichever is less. (2) The pipe either is located where damage by external forces is unlikely or is otherwise protected against such damage. (3) The pipe adequately resists exposure to ultraviolet light and high and low temperatures. (h) Plastic pipe may be installed on bridges provided that it is: (1) Installed with protection from mechanical damage, such as installation in a metallic casing; (2) Protected from ultraviolet radiation; and (3) Not allowed to exceed the pipe temperature limits specified in §192.123. [Amdt. 192-78, 61 FR 28770, June 6, 1996 with Amdt. 192-78 Correction, 61 FR 30824, June 18, 1996; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-93, 68 FR 53895, Sept. 15, 2003; Amdt. 192-94, 69 FR 32886, June 14, 2004]



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GUIDE MATERIAL

This guide material is under review following Amendment 192-94.

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

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

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

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

be protected from long-term exposure to direct sunlight. (See 2 of the guide material under §192.59.)

2 DIRECT BURIAL OF PLASTIC PIPE 2.1 Contraction. The piping should be installed with sufficient slack to provide for possible contraction. Under high

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

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

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

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

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

(b) Backfill material. Backfilling should be performed in a manner to provide firm support around the piping. The material used for backfilling should be free of large rocks, pieces of pavement, or any other materials that might damage the pipe.

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

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

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

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



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GPTC GUIDE FOR GAS TRANSMISSION AND §192.321 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART G (3) Tracer wire should not be wrapped around plastic pipe. It may be taped to the outside of the

plastic pipe, especially for installation by boring or plowing-in, or placed loosely in the trench directly adjacent to the pipe.

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

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

(6) Splicing of tracer wire, if necessary, should be done in a manner to produce an electrically and mechanically sound joint that will not loosen or separate under conditions to which it may be subjected such as backfilling operations and freeze-thaw cycles. (7) Where the tracer wire is electrically connected to metallic structures (e.g., steel or cast iron

pipe) for reasons such as expanded locating capabilities or cathodic protection, consideration should be given to the effects of electrical current surges on the ability to locate the plastic pipe or the increased potential for damage.

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

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

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

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

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

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

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

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

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

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

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

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

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

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



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GPTC GUIDE FOR GAS TRANSMISSION AND §192.321 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART G (d) Cased plastic pipe can contract due to cold gas or low ambient temperature. See 3.5(c)(3) of the

guide material under §192.281. (e) Where a gas leak migrating through the annular space between the plastic pipe and the casing or

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

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

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

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

manufacturer for the kind, type, grade, wall thickness, and diameter of the particular plastic pipe used. 5 SQUEEZE-OFF AND REOPENING THERMOPLASTIC PIPE FOR PRESSURE CONTROL

PURPOSES 5.1 Preliminary investigation.

Before thermoplastic pipe is squeezed-off and reopened, investigations and tests should be made to determine that the particular type, grade, size, and wall thickness of pipe of the same manufacture can be squeezed-off and reopened without causing failure under the conditions which will prevail at the time of the squeeze-off and reopening. References for squeeze-off procedures, tools, and precautions are included in the following.

(a) AGA XR0104, “Plastic Pipe Manual for Gas Service.” (b) GRI-92/0147.1, “Users' Guide on Squeeze-Off of Polyethylene Gas Pipes."

(c) GRI-94/0205, “Guidelines and Technical Reference on Gas Flow Shut-Off in Polyethylene Pipes Using Squeeze Tools.”

(d) ASTM F 1041, “Standard Guide for Squeeze-Off of Polyolefin Gas Pressure Pipe and Tubing." (e) ASTM F 1563, “Standard Specification for Tools to Squeeze-Off Polyethylene (PE) Gas Pipe or

Tubing.” 5.2 Field consideration. (a) The work should be done utilizing equipment and procedures that have been established and

proven by test to be capable of performing the operation safely and effectively. (b) Unless it has been determined by investigation and test that squeeze-off and reopening does not

significantly affect the long-term properties of the pipe, the squeezed-off and reopened area of the pipe should be reinforced in accordance with the guide material under §192.311.

(c) To prevent squeeze-off at the same point, a permanent mark or clamp should be put on the plastic pipe at the location of the squeeze point.

6 DAMAGE PREVENTION DURING DIRECTIONAL DRILLING

See Guide Material Appendix G-192-6 for damage prevention considerations while performing directional drilling or using other trenchless technologies.



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7 PLASTIC PIPE TEMPORARILY INSTALLED ABOVE GROUND 7.1 Aboveground exposure to sunlight.

Before using plastic pipe above ground, the operator should obtain the recommended maximum exposure time from the manufacturer and determine the date of manufacture from the Pipe Production Code marked on the pipe. If the operator cannot accurately document the actual time that pipe was stored outdoors, the entire time since the date of manufacture should be considered as aboveground exposure.

7.2 Protection from external forces. Means to protect the pipe may include: (a) Barricades. (b) Fencing. (c) Elevation support. To prevent strain on the plastic pipe due to sagging or wind forces, elevation

support should be provided. A reference for determining support spacing is PPI Handbook of Polyethylene Pipe, chapter titled "Above Ground Applications for Polyethylene Pipe."

(d) Signs and markers. (e) Physical barriers such as planks or sleeves. 7.3 Temperature exposure.

Aboveground pipe is exposed to greater variations in temperature than pipe installed below ground. During installation, consideration should be given to pipe elongation and contraction as the temperature changes during the day or seasonally.

7.4 Valves. Valves installed in aboveground plastic pipe should be braced or anchored, or the adjacent pipe stiffened or reinforced, to decrease torque forces being transferred to the pipe during operation of the valve.

8 PLASTIC PIPE INSTALLED ACROSS BRIDGES See Guide Material Appendix G-192-21.

§192.323 Casing.


Each casing used on a transmission line or main under a railroad or highway must comply with the following: (a) The casing must be designed to withstand the superimposed loads. (b) If there is a possibility of water entering the casing, the ends must be sealed. (c) If the ends of an unvented casing are sealed and the sealing is strong enough to retain the maximum allowable operating pressure of the pipe, the casing must be designed to hold this pressure at a stress level of not more than 72 percent of SMYS. (d) If vents are installed on a casing, the vents must be protected from the weather to prevent water from entering the casing.

GUIDE MATERIAL (a) Where plastic piping must be cased or bridged, suitable precautions should be taken to prevent

crushing or shearing the piping. See guide material under §192.321. (b) A reference for the design, installation, maintenance, repair, and monitoring of steel-cased pipelines is

NACE RP0200, “Steel-Cased Pipeline Practices.”



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Addendum No. 6, September 2006 122

§192.325 Underground clearance.


(a) Each transmission line must be installed with at least 12 inches (305 millimeters) of clearance from any other underground structure not associated with the transmission line. If this clearance cannot be attained, the transmission line must be protected from damage that might result from the proximity of the other structure. (b) Each main must be installed with enough clearance from any other underground structure to allow proper maintenance and to protect against damage that might result from proximity to other structures. (c) In addition to meeting the requirements of paragraph (a) or (b) of this section, each plastic transmission line or main must be installed with sufficient clearance, or must be insulated from any source of heat so as to prevent the heat from impairing the serviceability of the pipe. (d) Each pipe-type or bottle-type holder must be installed with a minimum clearance from any other holder as prescribed in §192.175(b). [Amdt. 192-85, 63 FR 37500, July 13, 1998]

GUIDE MATERIAL 1 CLEARANCE 1.1 Transmission lines. If 12 inches of clearance cannot be maintained, less clearance may be allowed provided: (a) Adequate measures are undertaken to prevent contact between the pipeline and the underground

structure, such as encasement of the pipeline with concrete, polyethylene or vulcanized elastomer, or the installation of sand-cement bags, concrete pads or open-cell polyurethane pads in the space between the pipeline and the underground structure.

(b) Adequate measures are taken to prevent mechanical damage to the pipe and coating of multiple pipeline bundles installed by directional boring. Adequate measures should be employed to provide separation between the individual pipelines in the bundle in order to minimize damage to the pipe and coating. This may be accomplished by employing dielectric spacing devices such as dense rubber spacers or vulcanized elastomer spacers between the individual pipelines in the bundle. Refer to §192.461(e).

1.2 Mains. Sufficient clearance should be maintained between mains and other underground structures to: (a) Permit installation and operation of maintenance and emergency control devices, such as leak

clamps, pressure control fittings and pinching equipment. (b) Permit installation of service laterals to both the mains and to other underground structures as

might be required. (c) Provide heat damage protection from other underground facilities such as steam or electric power

lines, particularly where plastic piping is installed in common trenches with sources of heat. (d) For additional methods of protection to ensure sufficient clearance, refer to 1.1(a) above.



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GPTC GUIDE FOR GAS TRANSMISSION AND §192.451 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART I

SUBPART I REQUIREMENTS FOR CORROSION CONTROL

§192.451 Scope.


This subpart prescribes minimum requirements for the protection of metallic pipelines from external, internal, and atmospheric corrosion. [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]

GUIDE MATERIAL




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§192.452 How does this subpart apply to converted pipelines and

regulated onshore gathering lines? [Effective Date: 4-14-06]

(a) Converted pipelines. Notwithstanding the date the pipeline was installed or any earlier deadlines for compliance, each pipeline which qualifies for use under this part in accordance with §192.14 must meet the requirements of the subpart specifically applicable to pipelines installed before August 1, 1971, and all other applicable requirements within 1 year after the pipeline is readied for service. However, the requirements of this subpart specifically applicable to pipelines installed after July 31, 1971, apply if the pipeline substantially meets those requirements before it is readied for service or it is a segment that is replaced, relocated or substantially altered. (b) Regulated onshore gathering lines. For any regulated onshore gathering line under §192.9 existing on April 14, 2006, that was not previously subject to this part, and for any onshore gathering line that becomes a regulated onshore gathering line under §192.9 after April 14, 2006, because of a change in class location or increase in dwelling density: (1) The requirements of this subpart specifically applicable to pipelines installed before August 1, 1971, apply to the gathering line regardless of the date the pipeline was actually installed; and (2) The requirements of this subpart specifically applicable to pipelines installed after July 31, 1971, apply only if the pipeline substantially meets those requirements. [Issued by Amdt. 192-30, 42 FR 60146, Nov. 25, 1977; Amdt. 192-102, 71 FR 13289, Mar. 15,2006]

GUIDE MATERIAL

This guide material is under review following Amendment 192-102. The operator should review the corrosion control records or perform field tests and surveys for the pipeline to be converted to ensure that cathodic protection can be applied to the pipeline to meet the requirements of Subpart I within 12 months of the conversion. The tests and surveys may include electrical surveys, pipe examination, coating examination and soil tests. A record of the review or tests and surveys should be maintained.



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§192.453 General.


The corrosion control procedures required by §192.605(b)(2), including those for the design, installation, operation and maintenance of cathodic protection systems, must be carried out by, or under the direction of, a person qualified in pipeline corrosion control methods. [Issued by Amdt. 192-4, 36 FR 12297, June 30, 1971; Amdt. 192-71, 59 FR 6579, Feb. 11, 1994]

GUIDE MATERIAL 1 PERSONNEL QUALIFICATIONS

Personnel responsible for directing the design, installation, operation, or maintenance of an operator’s corrosion control systems should have knowledge of and practical experience in the following.

(a) Pipeline coatings. (b) Cathodic protection systems (galvanic and impressed current). (c) Stray current interference. (d) Electrical isolation. (e) Survey methods and evaluation techniques. (f) Instruments used. 2 REFERENCE

A reference for the design and installation of cathodic protection systems is NACE RP0169, Sections 7 and 8.

Addendum No. 6, September 2006 144(a) Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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§192.455 External corrosion control: Buried or submerged pipelines

installed after July 31, 1971. [Effective Date: 7-13-98]

(a) Except as provided in paragraphs (b), (c), and (f) of this section, each buried or submerged pipeline installed after July 31, 1971, must be protected against external corrosion, including the following: (1) It must have an external protective coating meeting the requirements of §192.461. (2) It must have a cathodic protection system designed to protect the pipeline in accordance with this subpart, installed and placed in operation within 1 year after completion of construction. (b) An operator need not comply with paragraph (a) of this section, if the operator can demonstrate by tests, investigation, or experience in the area of application, including, as a minimum, soil resistivity measurements and tests for corrosion accelerating bacteria, that a corrosive environment does not exist. However, within six months after an installation made pursuant to the preceding sentence, the operator shall conduct tests, including pipe-to-soil potential measurements with respect to either a continuous reference electrode or an electrode using close spacing, not to exceed 20 feet (6 meters), and soil resistivity measurements at potential profile peak locations, to adequately evaluate the potential profile along the entire pipeline. If the tests made indicate that a corrosive condition exists, the pipeline must be cathodically protected in accordance with subparagraph (a) (2) of this section. (c) An operator need not comply with paragraph (a) of this section, if the operator can demonstrate by tests, investigation, or experience that -- (1) For a copper pipeline, a corrosive environment does not exist; or (2) For a temporary pipeline with an operating period of service not to exceed five years beyond installation, corrosion during the five-year period of service of the pipeline will not be detrimental to public safety. (d) Notwithstanding the provisions of paragraph (b) or (c) of this section, if a pipeline is externally coated, it must be cathodically protected in accordance with subparagraph (a) (2) of this section. (e) Aluminum may not be installed in a buried or submerged pipeline if that aluminum is

Addendum No. 6, September 2006 144(b) Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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2 PRACTICALITY OF ELECTRICAL SURVEYS See 5 of the guide material under §192.457. 3 MONITORING OF CATHODICALLY PROTECTED PIPELINES (§192.465(a)) (a) "Active" corrosion areas. See guide material under §192.457. For areas of local corrosion protection provided by galvanic anodes at individual locations of

"active" corrosion, the anodes need to provide a level of cathodic protection that complies with §192.463. Monitoring is mandatory in accordance with §192.465(a).

(b) "Not active" corrosion areas. For areas of local protection provided by galvanic anodes at individual locations of "not active"

corrosion, the corrosion protection levels are not subject to the requirements of §192.463. Such "voluntarily installed" anodes need not be monitored in accordance with §192.465(a), but the pipeline must be reevaluated every three years in accordance with §192.465(e).

4 REMEDIAL ACTION (a) Common corrosion control methods include coating, cathodic protection, and electrical isolation.

Cathodic protection systems typically use galvanic anodes or impressed current (rectifiers). Other corrosion control devices may include electrical isolators, interference bonds, diodes, and reverse current switches.

(b) Remedial action is required whenever it is determined that the cathodic protection or other installed corrosion control methods are not operating effectively.

(c) The specific remedial action to be taken depends on the type of corrosion control method installed and the problem encountered. In certain situations, the deficiency can be corrected by modifying existing corrosion control methods (e.g., increasing output from adjacent rectifiers).

(d) Operators are required to take prompt remedial action to correct deficiencies indicated by monitoring. Remedial action should correct the deficiency before the next monitoring cycle required by §192.465. However, for monitoring cycles greater than one year, remedial action should be completed within 15 months of discovery.

Example: It is discovered that pipe coating has deteriorated and that the existing corrosion control system is unable to achieve the desired cathodic protection level. The operator should initiate and document action taken to achieve the acceptable cathodic protection level before the next monitoring cycle. Remedial action might include the following.

(1) Installing additional cathodic protection, (2) Recoating the pipe to meet the requirements of §192.461, or (3) Replacing the pipe. (e) If remedial action cannot be completed prior to the next scheduled monitoring cycle, the operator

should document the actions taken to correct the deficiency and the expected timeframe for completion.



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5 MONITORING OF NON-CATHODICALLY PROTECTED PIPELINES (§192.465(e)) Noncathodically protected pipelines are required to be reevaluated at intervals not exceeding three

years to identify areas of "active" corrosion in accordance with §192.465(e). Electrical surveys must be utilized, except as follows:

(a) Where electrical survey is impractical, the study of failures, leakage history, corrosion, class location hazard to the public and unusual operating/maintenance conditions may be utilized to evaluate the need for protection.

(b) Where the pipeline is remotely located or otherwise determined that corrosion caused leaks would not be a detriment to public safety.

(1) "Active" corrosion areas. See guide material under §192.457. Non-cathodically protected pipelines in which "active" corrosion is found are required to be

cathodically protected and monitored in accordance with §§192.463 and 192.465(a). See 3 above.

(2) "Non-active" corrosion areas. See guide material under §192.457. Non-cathodically protected pipelines containing "non-active" corrosion need to be reevaluated

at intervals not exceeding three years in accordance with §192.465(e).



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§192.467 External corrosion control: Electrical isolation.


(a) Each buried or submerged pipeline must be electrically isolated from other underground metallic structures, unless the pipeline and the other structures are electrically interconnected and cathodically protected as a single unit. (b) One or more insulating devices must be installed where electrical isolation of a portion of a pipeline is necessary to facilitate the application of corrosion control. (c) Except for unprotected copper inserted in ferrous pipe, each pipeline must be electrically isolated from metallic casings that are a part of the underground system. However, if isolation is not achieved because it is impractical, other measures must be taken to minimize corrosion of the pipeline inside the casing. (d) Inspection and electrical tests must be made to assure that electrical isolation is adequate. (e) An insulating device may not be installed in an area where a combustible atmosphere is anticipated unless precautions are taken to prevent arcing. (f) Where a pipeline is located in close proximity to electrical transmission tower footings, ground cables or counterpoise, or in other areas where fault currents or unusual risk of lightning may be anticipated, it must be provided with protection against damage due to fault currents or lightning, and protective measures must also be taken at insulating devices. [Issued by Amdt. 192-4, 36 FR 12297, June 30, 1971; Amdt. 192-33, 43 FR 39389, Sept. 5, 1978]

GUIDE MATERIAL 1 ELECTRICAL ISOLATION (§§192.467(a), (b), and (c)) 1.1 Insulating devices. (§§192.467(a) and (b)) Insulating devices may consist of insulating flange assemblies (see guide material under §192.147),

unions or couplings, or fabricated insulating joints. These devices should be properly rated for temperature, pressure, and dielectric strength. Typical locations where electrical insulating devices should be considered include the following.

(a) At supporting pipe stanchions, bridge structures, tunnel enclosures, piling, and reinforced concrete foundations where electrical contact would preclude effective cathodic protection. It may be necessary to electrically isolate the piping from such a structure, or the piping and structure from adjacent underground piping.

(b) At metallic curb boxes and valve enclosures. These should be designed, fabricated and installed in such a manner that electrical isolation from the piping system will be maintained.

(c) Where a pipe enters a building through a metallic wall sleeve and where it is intended to maintain electrical isolation between the sleeve and the pipe. To accomplish this, insulating spacers should be used.

(d) At river weights, pipeline anchors, and metallic reinforcement in weight coatings. These should be electrically isolated from the carrier pipe and installed so that coating damage will not occur.

(e) Points at which facilities change ownership, such as meter stations and well heads. (f) Connections to main line piping systems such as gathering or distribution system laterals. (g) Inlet and outlet piping of inline measuring or pressure regulating stations or both. (h) Compressor or pumping stations, either in the suction and discharge piping or in the main line

immediately upstream and downstream of the station. (i) In stray current areas. (j) At the termination of service line connections and entrance piping to prevent electrical continuity

with other metallic systems. Addendum No. 6, September 2006 154(a)



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1.2 Casings. (§192.467(c)) (a) New installations. (1) Spacers and sealing. All new construction of cased metallic pipelines should provide for the

installation of insulating type casing spacers or other suitable means to prevent physical contact between the carrier pipe and casing. The ends of the casing may be sealed with a non-conductive sealing method to prevent mud, silt, and water from entering the annular space between the casing and the carrier pipe. It may be necessary to fill this annular space with a non-conductive type casing filler to ensure continued isolation in those installations where end seals alone may not be sufficient to resist the entrance of water.

(2) Joining. Lengths of casing should be joined by a full weld, or other type of joint that will provide an adequate seal against water entrance. Any holes in the casing should be closed by welding, or otherwise sealed.

(3) Insertion. Care should be taken during installation to reduce the possibility of electrical shorts. The carrier pipe should be as straight as practical. The internal diameter of the casing should be adequate to ensure physical clearance from the carrier pipe. The carrier pipe should be carefully inspected and all coating damage repaired. Care should be taken during insertion of the carrier pipe. To prevent damage to the coating and spacer, the casing should be clear of any mud, water, or debris prior to insertion of the carrier pipe. When existing buried pipe is being used as

Addendum No. 6, September 2006 154(b)Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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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.



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Addendum No. 4, January 2006 162

(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.



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GPTC GUIDE FOR GAS TRANSMISSION AND §192.515 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART J 2.3 Tests in excess of 90 percent SMYS. When the test pressure will produce a hoop stress in excess of 90 percent of SMYS, the following

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

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

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

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

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

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

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

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

(4) Develop installation techniques, including effective anchoring systems, that address expected forces to be experienced during the test, and ensure that they are implemented during filling and dewatering operations.

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

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

out persons not involved with the test. (c) See OPS Advisory Bulletin ADB-04-01 (69 FR 58225, Sept. 29, 2004) for additional background

information on this subject (accessible via Federal Register (FR) at www.gpoaccess.gov/fr/advanced.html).

4 ENVIRONMENTAL CONSIDERATIONS Each operator, in fulfilling the local, state, and federal environmental regulations with respect to the

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

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

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



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GPTC GUIDE FOR GAS TRANSMISSION AND §192.517 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART J

§192.517 Records.


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

GUIDE MATERIAL

(a) For tests conducted under §§192.509, 192.511, or 192.513, records are required to show that the tests have been conducted. The date, location of the test, and the test pressure applied may be sufficient documentation. Additional information may be included at the discretion of the operator.

(b) For segments of steel service line stressed to 20 percent or more of SMYS (§192.511(c)), records

are required to document testing in accordance with §192.507.



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GPTC GUIDE FOR GAS TRANSMISSION AND §192.557 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART K

(B) Ductile iron fittings were cast from grade (70-50-05) ductile iron and conform to the requirements of ANSI A21.14-1989.

(2) Useful references for performing the analysis include the following. (i) For cast iron pipe, the design formulas in AWWA C101-67 (withdrawn 1982) and for

ductile iron pipe, AWWA C150/A21.50-81 (R86). (ii) For wall thickness determination of cast iron pipe, the standard thickness listed in tables

1-3 and 1-7 of AWWA C101-67. (iii) For wall thickness determination of ductile iron pipe, the standard thickness listed in table

50.5 of AWWA C150/A21.50-81. (c) A review of leakage, corrosion, operating pressure and maintenance history to ascertain the

present condition of facilities. (d) An analysis of the effect of the ultimate separation and uprating on adjoining facilities. 1.2 Additional consideration. (a) An analysis should be made to confirm that the proposed MAOP is in accordance with the

requirements as set forth in §192.553(d). (b) For cast iron pipe, see Guide Material Appendix G-192-18. 2 WORK PRELIMINARY TO UPRATING 2.1 Leakage survey. A leakage survey may be required by §192.557(b)(2). Types of leakage surveys are described in Guide

Material Appendix G-192-11 (Natural Gas) and Guide Material Appendix G-192-11A (Petroleum Gas). 2.2 Changes to the system. Repairs, replacements, or other alterations necessary for the safe operation of both the system to be

uprated and the existing system should include the following. (a) Installation of anchors or joint reinforcement as required in §192.557(b)(4). (b) Renewal of gas service lines where warranted. (c) Installation of service line shutoff valves where required and in accordance with §§192.363 and

192.365. (d) Installation of service regulators where required and in accordance with §§192.197, 192.353,

192.355 and 192.357. (e) Consideration of the adequacy of existing service regulators and their characteristics with present

orifice sizing at the proposed pressure levels. 2.3 Monitoring. Provision should be made for monitoring field pressures prior to and during uprating to ensure the

integrity of both the system to be uprated and the adjacent systems that might be affected by the uprating.

2.4 Interface. The necessary field work should be performed to provide positive control to avoid overpressuring the

sections of the systems that are not being uprated. Control procedures may involve actual physical separation of sections, installation of regulator equipment that is properly operated and set to control at the proper pressure, or other effective means of separation.

2.5 Customer notification. Customers should be notified of planned interruptions of gas service. 3 INCREASING PRESSURE 3.1 Communications. Lines of communication should be established between all control points.



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GPTC GUIDE FOR GAS TRANSMISSION AND §192.557 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART K

3.2 Isolation. The system should be isolated from all lower pressure systems. 3.3 Pressure regulation. The valve to each service regulator should be closed or the operation of each service regulator should

be monitored as the pressure in the main is increased. 3.4 Pressure increments.

See §192.557(c). 3.5 Leak check.

See §192.553(a)(1). 3.6 Leak repairs.

See §192.553(a)(2). 3.7 Monitoring. The pressure in adjacent facilities should be monitored during the uprating procedure to establish: (a) That no connection is acting as a source of unregulated gas from the higher pressure segment to

the lower pressure system; and (b) The adequacy of the remaining lower pressure system at points of separation and other locations. 3.8 Final leak survey. After the uprating is completed, a final leak survey should be made to confirm the integrity of the

facilities. Necessary leak repairs should be made. 4 RECORDS The records of investigations, the work, and the testing should be forwarded to the proper department

for retention for the life of the facility.



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GPTC GUIDE FOR GAS TRANSMISSION AND §192.615 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART L 1.4 Assuring the availability of personnel, equipment, tools, and materials. Arrangements made to assure the availability of personnel, equipment, tools, and materials that may be

needed (in accordance with the type of emergency) should be described. These arrangements should include the assignment of responsibilities for coordinating, directing and performing emergency functions, including the following.

(a) Responsibility for overall coordination (which may be at the local headquarters or at the operating executive level, depending on the scope of the emergency).

(b) Responsibility for execution of emergency operations (based on the scope of the emergency). (c) Determination of departmental functions or services during an emergency, including determination

of individual job assignments required to implement the plan. (d) Determination of coordination required between departments including provision for bypassing

normal chain of command as necessitated by the emergency. (e) Determination of coordination required to implement mutual aid agreements. (f) Responsibility for providing accurate information and cooperation with the news media. 1.5 Controlling emergency situations. Actions that may be initiated by the first employee arriving at the scene in order to protect people and

property should be described. These actions may include the following. (a) Determining the scope of the emergency. (b) Evacuating and preventing access to premises that are or may be affected. (c) Preventing accidental ignition. (d) Reporting to the appropriate supervisor on the situation, and requesting further instructions or

assistance if needed. 1.6 Emergency shutdown and pressure reduction. (a) Provisions for shutdown or pressure reduction in the pipeline system as may be necessary to

minimize hazards should be described. The plans should include the following. (1) Circumstances under which available shutdown, pressure reduction, or system isolation

methods are applicable. Considerations should include access to and operability of valves located in areas prone to high water or flooding conditions.

(2) Circumstances under which natural gas might be allowed to safely escape to atmosphere (i.e., vent) until shutdown or repair.

(i) Some possible reasons for using this alternative are as follows. (A) Curtailment will affect critical customers (e.g., hospitals). (B) Curtailment will affect large numbers of customers during adverse weather

conditions. (C) Line break or leak is remotely located and does not cause a hazard to the public or

property. (ii) Some factors to consider are as follows. (A) Sources of ignition. (B) Leak or damage location (rural vs. urban). (C) Proximity to buildings and other structures. (D) Ability to make and keep the area safe while gas vents. (E) Ability to coordinate with other emergency responders and public officials. (3) Lists or maps of valve locations, regulator locations, compressor schematics and blowdown

locations. (4) Maps or other records to identify sections of the system that will be affected by the operation

of each valve or other permanent shutdown device. (5) Provision for positive identification of critical valves and other permanent facilities required for

shutdown. See 3.2 of the guide material under §192.605. (6) Instructions for operating station blowdown and isolation systems for each compressor station.

See Guide Material Appendix G-192-12. (7) Provisions for notifying affected customers. (8) Provisions for confirming that the shutdown or pressure reduction was effective. (b) Distribution system plans should include consideration of the potential hazards associated with an

outage and the need to minimize the extent of an outage and to expedite service restoration. In addition to the use of any existing emergency valves within a distribution system, consideration



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GPTC GUIDE FOR GAS TRANSMISSION AND §192.615 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART L

should also be given to other methods of stopping gas flow (such as injecting viscous materials or polyurethane foam through drip risers or any other available connections to the main, or through the use of squeezing or bagging-off techniques).

1.7 Making safe any actual or potential hazard. Provisions should be described for identifying, locating, and making safe any actual or potential hazard. These may include the following. (a) Controlling pedestrian and vehicular traffic in the area. (b) Eliminating potential sources of ignition. (c) Controlling the flow of leaking gas and its migration. See Guide Material Appendices G-192-11 for

natural gas systems and G-192-11A for petroleum gas systems. (d) Ventilating affected premises. (e) Venting the area of the leak by removing manhole covers, barholing, installing vent holes, or other

means. (f) Determining the full extent of the hazardous area, including the discovery of gas migration and secondary damage such as the following. (1) Deformation of a gas service line indicating that the service line might be separated

underground near a foundation wall or at an inside meter set assembly. (2) Multiple underground leaks that may have occurred, allowing gas to migrate into adjacent

buildings. (3) Potential pipe separation and gas release at unseen underground locations that may result in

gas entering adjacent buildings, or following or entering other underground structures connected to buildings.

(g) Monitoring for a change in the extent of the hazardous area. (h) Determining whether there are utilities whose proximity to the pipeline may affect the response. (1) Visually identify the presence of electric and other utilities surrounding the pipeline facility. (2) Evaluate the potential risk associated with the continued operation of the surrounding utilities. (3) Use the ICS to contact the owner of the surrounding utilities, as necessary, to implement a

more effective and coordinated emergency response. (i) Coordinating with fire, police, and other public officials the actions to be taken. (j) Maintaining ongoing communication with fire, police, and other public officials as events unfold to

ensure that information pertinent to emergency response is shared in a timely manner. 1.8 Restoration of service. Planning for the safe restoration of service to all facilities affected by the emergency, after proper

corrective measures have been taken, should include consideration of the following. (a) Provisions for safe restoration of service should include the following. (1) Turn-off and turn-on of service to customers, including strict control of turn-off and turn-on

orders to assure safety in operation. (2) Purging and repressuring of pipeline facilities. (3) Resurvey of the area involved in a leak incident to locate any additional leaks. (b) Execution of the repair and restoration of service functions will necessitate prior planning such as

the following. (1) Sectionalizing to reduce extent of outages and to expedite turn-on following a major outage. (2) Lists and maps for valve locations, regulator locations, and blowoff or purge locations. (3) Provisions for positive identification of valves and regulator facilities. See 3.2 of the guide

material under §192.605. (4) Equipment checklist for repair crews. (5) Instructions for operating station blowdown and isolation systems for each compressor station.

See Guide Material Appendix G-192-12. (6) Emergency supply connections with other gas companies and procedures for making use of

such connections. (7) List of contractors, other utilities, and municipalities that have agreed to provide equipment

and workmen to assist with repair and service restoration. Procedures for securing and utilizing this manpower and equipment should be described.



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GPTC GUIDE FOR GAS TRANSMISSION AND §192.615 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART L (6) An incident in a highly populated area. (b) The types of emergencies that might require notification to gas system operators by public officials

include the following. (1) Report of gas odor. (2) Damage to gas facilities. (3) Operation of a gas system valve by non-operator personnel. (4) Report of a gas outage. 3.4 Plan with public officials and operators of facilities in the vicinity of the pipeline for mutual assistance. (a) Operator personnel should establish and maintain liaison with appropriate fire, police, and other

public officials and operators of facilities in the vicinity of the pipeline to plan how to engage in mutual assistance to minimize hazards to life and property. This planning should include how to work together effectively in an Incident Command System. Consideration should be given to various situations including the following.

(1) Situations where the operator has reason to believe a hazard may exist and where other emergency personnel, such as fire and police, may be able to respond more quickly than operator personnel. Police and fire department personnel should take action toward protecting the public by means of evacuation and building ventilation where needed, pending the arrival of operator personnel.

(2) Situations that involve the evacuation of buildings and properties. (i) Advise police and fire departments that operator personnel may need to conduct leak

investigations inside buildings and on properties within the area of the emergency. (ii) The operator, police department, and fire department should plan for access to

evacuated buildings and properties. The plan should include provisions to instruct personnel in charge of evacuated buildings and properties to provide a means of access when required.

(3) Situations where the operation of electric or other utilities located in the vicinity of the pipeline may provide sources of ignition for the gas released, may increase burning time or intensity of fires that have already started, or may delay responders who are attempting to make the situation safe.

(4) Means of ensuring that communication is ongoing during the emergency response so that pertinent information is shared in a timely manner.

(b) The gas characteristics and properties, such as pressure, specific gravity, gas odor, and flammability limits, should be provided to emergency response officials. The implications of these characteristics and properties on emergency response decisions should be thoroughly discussed. In discussions with emergency response officials, the operator should emphasize the following.

(1) The importance of this information to outside emergency response personnel arriving before the operator's personnel.

(2) The use of this information in making decisions, such as areas to be evacuated, traffic rerouting, and control of ignition sources.

(3) The importance of gas detectors in properly responding to an incident.

§192.616 Public awareness.


(a) Each pipeline operator must develop and implement a written continuing public education program that follows the guidance provided in the American Petroleum Institute’s (API) Recommended Practice (RP) 1162 (incorporated by reference, see §192.7). (b) The operator’s program must follow the general program recommendations of API RP 1162 and assess the unique attributes and characteristics of the operator’s pipeline and facilities. (c) The operator must follow the general program recommendations, including baseline and supplemental requirements of API RP 1162, unless the operator provides justification in its program or procedural manual as to why compliance with all or certain provisions of the recommended practice is not practicable and not necessary for safety.



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(d) The operator’s program must specifically include provisions to educate the public, appropriate government organizations, and persons engaged in excavation related activities on: (1) Use of a one-call notification system prior to excavation and other damage prevention activities; (2) Possible hazards associated with unintended releases from a gas pipeline facility; (3) Physical indications that such a release may have occurred; (4) Steps that should be taken for public safety in the event of a gas pipeline release; and (5) Procedures for reporting such an event. (e) The program must include activities to advise affected municipalities, school districts, businesses, and residents of pipeline facility locations. (f) The program and the media used must be as comprehensive as necessary to reach all areas in which the operator transports gas. (g) The program must be conducted in English and in other languages commonly understood by a significant number and concentration of the non-English speaking population in the operator’s area. (h) Operators in existence on June 20, 2005, must have completed their written programs no later than June 20, 2006. As an exception, operators of small propane distribution systems having less than 25 customers and master meter operators having less than 25 customers must have completed development and documentation of their programs no later than June 20, 2007. Upon request, operators must submit their completed programs to PHMSA or, in the case of an intrastate pipeline facility operator, the appropriate State agency. (i) The operator’s program documentation and evaluation results must be available for periodic review by appropriate regulatory agencies. [Issued by Amdt. 192-71, 59 FR 6579, Feb. 11, 1994; Amdt. 192-99, 70 FR 28833, May 19, 2005 with Amdt. 192-99 Correction, 70 FR 35041, June 16, 2005; Amdt. 192-103, 71 FR 33402, June 9, 2006]

GUIDE MATERIAL

This guide material is under review following Amendment 192-99.

1 GENERAL The educational program called for under this section should be tailored to the type of pipeline

operation and the environment traversed by the pipeline and should be conducted in each language that is significant in the community or area. Operators should communicate their programs to consumers, the general public including non-consumers, appropriate government officials, operators of facilities in the vicinity of the pipeline (e.g., telephone, electric, gas, cable, water, sewer and railroads), and excavators in their area. See 2.3 and 2.4 of the guide material under §192.614 for other related information.

Operators of transmission systems should communicate their programs to residences and businesses

along their pipeline rights-of-way, with a request that landlords and employers provide the information to their tenants and employees. The extent of program coverage may vary depending on the location of the transmission pipeline with respect to occupants of residences and businesses. In determining the scope of the operator’s communication, the likelihood that the occupant would be able to recognize a pipeline emergency on the rights-of-way should be considered. Distance, terrain, other homes, or buildings between the occupant and the pipeline are factors that influence the ability to recognize a pipeline emergency. The programs and media used should be as comprehensive as necessary to reach all areas through which the operator transports gas. The programs of operators in the same area should be coordinated to properly direct reports of emergencies and to avoid inconsistencies.



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3 INCIDENT DATA COLLECTION When a detailed analysis is to be made, a person at the scene of the incident should be designated to

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

may be of great value in the investigation. (e) Ensuring the notification of all appropriate governmental authorities. (f) Ensuring the preservation of evidence. 4 INVESTIGATION TEAM When a detailed analysis is to be made, a fully qualified investigation team should be designated. The

investigation team should be qualified either by training or experience in the proper procedures for investigation of an incident. The investigation should include the following.

(a) Determination of the probable cause of the incident. (b) Evaluation of the initial response to the incident. (c) The need for system improvements if necessary. (d) The need for improvements in response, management and investigation of incidents. 5 SPECIMENS A procedure should be prepared for selecting, collecting, preserving, labeling, and handling of

specimens. Procedures for collecting plastic or metallurgical specimens should include precautions against changing the granular structure in the areas of investigatory interest (e.g., avoid heat effects from cutting and outside forces due to tools and equipment). When corrosion may be involved, procedures may be necessary for proper sampling and handling of soil and ground water specimens. Procedures controlling the cutting, cleaning, lifting, identifying, and shipping of pipe specimens should be considered for preservation of valuable evidence on the pipe surface, and on any tear surface or fracture face, including making cuts far enough from the failure to avoid damaging critical areas of the specimen.

The number of specimens needed to be collected at the failure site may vary depending on the type

and number of tests anticipated. A series of independent or destructive tests may require multiple specimens. If there is a need to confirm the pipe materials specifications, then additional pipe specimens should be obtained near the failure, but in an area of the piping where the physical properties and characteristics are unaffected by the failure itself. Other investigatory procedures may be utilized to confirm pipe material specifications.

6 TESTING AND ANALYSIS Recognized standard destructive and non-destructive techniques are the preferred means to examine

test specimens. The testing methods used should be suited to the particular material being tested, and be pertinent to the failure investigation.

Analysis and data on failures should be compiled and reviewed. The need for continuing surveillance of

pipeline facilities should be determined. See the guide material under §192.613. 7 REFERENCES (a) "First at the Scene" by J.M. Lennon, Director of Claims, Philadelphia Electric Company; AGA

Operating Section Proceedings - 1983.



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(b) "How to Protect the Company at the Scene of an Incident" by Robert E. Kennedy, Director of

Claims, Claim & Security Department, The Brooklyn Union Gas Company; AGA Operating Section Proceedings - 1983.

(c) NFPA 921, "Guide for Fire and Explosion Investigations." (d) NACE RP0173, "Collection and Identification of Corrosion Products" (Discontinued).

§192.619 What is the maximum allowable operating pressure for

steel or plastic pipelines? [Effective Date: 7-10-06]

(a) Except as provided in paragraph (c) of this section, no person may operate a segment of steel or plastic pipeline at a pressure that exceeds the lowest of the following: (1) The design pressure of the weakest element in the segment, determined in accordance with subparts C and D of this part. However, for steel pipe in pipelines being converted under §192.14 or uprated under subpart K of this part, if any variable necessary to determine the design pressure under the design formula (§192.105) is unknown, one of the following pressures is to be used as design pressure: (i) Eighty percent of the first test pressure that produces yield under section N5 of Appendix N of ASME B31.8 (incorporated by reference, see §192.7), reduced by the appropriate factor in paragraph (a)(2)(ii) of this section; or (ii) If the pipe is 12¾ inches (324 mm) or less in outside diameter and is not tested to yield under this paragraph, 200 p.s.i. (1379 kPa). (2) The pressure obtained by dividing the pressure to which the segment was tested after construction as follows: (i) For plastic pipe in all locations, the test pressure is divided by a factor of 1.5. (ii) For steel pipe operated at 100 p.s.i. (689 kPa) gage or more, the test pressure is divided by a factor determined in accordance with the following table:

Class location

Factor1, segment--

Installed before (Nov. 12, 1970)

Installed after (Nov. 11, 1970)

Converted under §192.14

1 2 3 4

1.1 1.25 1.4 1.4

1.1 1.25 1.5 1.5

1.25 1.25 1.5 1.5

1For offshore segments installed, uprated or converted after July 31, 1977, that are not located on an offshore platform, the factor is 1.25. For segments installed, uprated or converted after July 31, 1977, that are located on an offshore platform or on a platform in inland navigable waters, including a pipe riser, the factor is 1.5.

(3) The highest actual operating pressure to which the segment was subjected during the 5 years preceding the applicable date in the second column. This pressure restriction applies unless the segment was tested according to the requirements in paragraph (a)(2) of this section after the applicable date in the third column or the segment was uprated according to the requirements in subpart K of this part:



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Pipeline segment Pressure date Test date

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

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

5 years preceding applicable date in second column.

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

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

GUIDE MATERIAL

This guide material is under review following Amendment 192-102. See Guide Material Appendices G-192-9 and G-192-10.

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


(a) No person may operate a segment of a high pressure distribution system at a pressure that exceeds the lowest of the following pressures, as applicable: (1) The design pressure of the weakest element in the segment, determined in accordance with Subparts C and D of this part.



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

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

§192.623 Maximum and minimum allowable operating pressure:

Low-pressure distribution systems. [Effective Date: 4-26-96]

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



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GPTC GUIDE FOR GAS TRANSMISSION AND §192.745 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART M

(b) Valves should be operated to the extent necessary to establish operability during an emergency. When operating the valve, precautions should be taken to avoid a service outage or overpressurization of the system.

(c) When maintenance is completed, the operator should verify that the valves are in the proper position.

(d) When inspecting or maintaining valves, the location reference data contained in the operator's records should be compared with field conditions. Changes, such as referenced landmarks, street alignment, and topography, should be noted and incorporated in the records.

2 INOPERABLE VALVES The following actions should be considered if a valve is found inoperable. (a) Repair the valve to make it operable. (b) Designate another valve or valves to substitute for the inoperable valve that will provide a similar

level of effectiveness for isolating the line section. Consideration should be given to the following. (1) Spacing requirements as prescribed in §192.179. (2) Updating records for emergency shutdown and future maintenance requirements. (3) Informing employees of the change to the isolation or emergency shutdown plan. (c) Replace the valve.

§192.747 Valve maintenance: Distribution systems.


(a) Each valve, the use of which may be necessary for the safe operation of a distribution system, must be checked and serviced at intervals not exceeding 15 months, but at least once each calendar year. (b) Each operator must take prompt remedial action to correct any valve found inoperable, unless the operator designates an alternative valve. [Amdt. 192-43, 47 FR 46850, Oct. 21, 1982; Amdt. 192-93, 68 FR 53895, Sept. 15, 2003]

GUIDE MATERIAL 1 INSPECTION AND MAINTENANCE Valves should be checked for adequate lubrication and proper alignment to permit the use of a key,

wrench, handle, or other operating device. Where applicable, the valve box or vault should be cleared of any debris that would interfere with or delay the operation of the valve.

2 PRECAUTIONS If a valve is to be partially operated, precautions should be taken to avoid a service outage or

overpressurizing the system. Such precautions might include the following. (a) Documenting the valve type (e.g., plug, gate, ball) and the direction and number of turns to operate

the valve. (b) Verifying the orientation of the valve in relation to the valve stops. (c) Monitoring downstream pressure for any variation from normal operating pressure.



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3 INOPERABLE VALVES The following actions should be considered if a valve is found inoperable. (a) Repair the valve to make it operable. (b) Designate another valve or valves to substitute for the inoperable valve that will provide a similar

level of effectiveness for isolating the desired area. Consideration should be given to the following. (1) Updating records for emergency shutdown and future maintenance requirements. (2) Informing employees of the change to the isolation or emergency shutdown plan. (c) Replace the valve. 4 IDENTIFICATION AND RECORD VERIFICATION (a) See §192.181 for additional information on identifying valves necessary for the safe operation of a

distribution system. (b) See the guide material under §192.745 regarding verification of records with current field data.

§192.749 Vault maintenance.


(a) Each vault housing pressure regulating and pressure limiting equipment, and having a volumetric internal content of 200 cubic feet (5.66 cubic meters) or more, must be inspected at intervals not exceeding 15 months, but at least once each calendar year, to determine that it is in good physical condition and adequately ventilated. (b) If gas is found in the vault, the equipment in the vault must be inspected for leaks, and any leaks found must be repaired. (c) The ventilating equipment must also be inspected to determine that it is functioning properly. (d) Each vault cover must be inspected to assure that it does not present a hazard to public safety. [Amdt. 192-43, 47 FR 46850, Oct. 21, 1982; Amdt. 192-85, 63 FR 37500, July 13, 1998]

GUIDE MATERIAL 1 APPLICABILITY The following procedures apply primarily to vaults that have restricted openings (e.g., manholes) or are

more than four feet deep. However, an operator should review the following procedures and select those that, for its particular situation, are applicable to vaults that have full opening covers and are less than four feet deep.



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(ii) The impact of water displacement on liquid hydrocarbons in those instances where water may enter into the pipeline segment.

(c) Monitoring isolated segments. (1) Monitoring procedures should be established based on the pressure, volumes, closures, and

other pertinent factors. (2) Personnel assigned to operate isolation equipment should have a means to determine

pressure build-ups, such as gauges and vents. (3) Personnel monitoring at remote locations should have communication with the work site and

the individual in charge of the operation. 4 NOTIFICATIONS PRIOR TO PURGE OR BLOWDOWN 4.1 Public officials. The appropriate public officials should be notified prior to a purge or blowdown in those situations where

the normal traffic flow through the area might be disturbed, or where it is anticipated that there will be calls from the public regarding the purge or blowdown.

4.2 Public in vicinity of gas discharge. The public in the vicinity of the gas discharge should be notified prior to a purge or blowdown if it is

anticipated that the public might be affected by the process. The primary considerations for determining the need for notification are noise, odor, and the possibility of accidental ignition.

5 REFERENCE

A reference is AGA XR0104, ”Plastic Pipe Manual for Gas Service," Chapter VI – Maintenance, Operation and Emergency Control Procedures.

§192.753 Caulked bell and spigot joints.


(a) Each cast iron caulked bell and spigot joint that is subject to pressures of more than 25 psi (172 kPa) gage must be sealed with: (1) A mechanical leak clamp; or (2) A material or device which: (i) Does not reduce the flexibility of the joint; (ii) Permanently bonds, either chemically or mechanically, or both, with the bell and spigot metal surfaces or adjacent pipe metal surfaces; and (iii) Seals and bonds in a manner that meets the strength, environmental, and chemical compatibility requirements of §§192.53(a) and (b) and 192.143. (b) Each cast iron caulked bell and spigot joint that is subject to pressures 25 psi (172 kPa) gage or less and is exposed for any reason must be sealed by a means other than caulking. [Amdt. 192-25, 41 FR 23679, June 11, 1976; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-93, 68 FR 53895, Sept. 15, 2003]

GUIDE MATERIAL


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§192.755 Protecting cast-iron pipelines.


When an operator has knowledge that the support for a segment of a buried cast-iron pipeline is disturbed: (a) That segment of the pipeline must be protected, as necessary, against damage during the disturbance by: (1) Vibrations from heavy construction equipment, trains, trucks, buses, or blasting; (2) Impact forces by vehicles; (3) Earth movement; (4) Apparent future excavations near the pipeline; or (5) Other foreseeable outside forces that may subject that segment of the pipeline to bending stress. (b) As soon as feasible, appropriate steps must be taken to provide permanent protection for the disturbed segment from damage that might result from external loads, including compliance with applicable requirements of §§192.317(a), 192.319, and 192.361(b) -- (d). [Issued by Amdt. 192-23, 41 FR 13588, Mar. 31, 1976]

GUIDE MATERIAL See Guide Material Appendices G-192-16 and G-192-18.

§192.761 (Removed.)


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GPTC GUIDE FOR GAS TRANSMISSION AND §192.901 DISTRIBUTION PIPING SYSTEMS: 2003 Edition SUBPART O

SUBPART O GAS TRANSMISSION PIPELINE INTEGRITY MANAGEMENT

§192.901 What do the regulations in this subpart cover?


This subpart prescribes minimum requirements for an integrity management program on any gas transmission pipeline covered under this part. For gas transmission pipelines constructed of plastic, only the requirements in §§192.917, 192.921, 192.935 and 192.937 apply. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004]

GUIDE MATERIAL

1 GENERAL

The requirements of Subpart O apply to all transmission pipelines including compressor stations, metering stations, regulator stations, valve sets, and other fabricated assemblies. The requirements of Subpart O do not apply to distribution lines or to gathering lines.

2 APPLICABILITY OF THIS SUBPART

Table 192.901i identifies the applicability of each section of Subpart O to plastic line pipe, steel line pipe and pipeline components. In the table, “Components” refers to gas-carrying components other than line pipe that are typically above ground, such as compressor stations, meter stations, and regulator stations.

APPLICABILITY OF SUBPART O

Legend: R = Required; C = Consider; NA = Not Applicable

Natural Gas Transmission Pipeline System Covered Segment (see §192.903) Non-Covered Segment

Regulation Section

Plastic Line Pipe

Steel Line Pipe Components

Plastic Line Pipe


192.901 R R R R R R 192.903 R R R R R R 192.905 R R R R R R 192.907 R R R C C C 192.909 R R R NA NA NA 192.911 C R R NA NA NA

TABLE 192.901i

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APPLICABILITY OF SUBPART O (Continued)

Legend: R = Required; C = Consider; NA = Not Applicable

Natural Gas Transmission Pipeline System Covered Segment (see §192.903) Non-Covered Segment

Regulation Section

Plastic Line Pipe


Plastic Line Pipe

Steel Line Pipe

Components

192.913 (if used) NA R R NA C C

192.915 C R R C R R 192.917 R R R R R R 192.919 C R R NA NA NA 192.921 R R R NA NA NA 192.923 NA * * NA * * 192.925 NA * * NA * * 192.927 NA * * NA * * 192.929 NA * * NA * * 192.931 NA * * NA * * 192.933 NA R R NA C C 192.935 R R R NA R R 192.937 R R R R R R 192.939 C R R NA NA NA 192.941 (if used) NA R R NA C C

192.943 (if used) NA R R NA NA NA

192.945 C R R C C C 192.947 C R R C C C 192.949 R R R NA NA NA 192.951 NA R R NA NA NA * See guide material under these sections for detailed discussions.

TABLE 192.901i

§192.903 What definitions apply to this subpart?


The following definitions apply to this subpart. Assessment is the use of testing techniques as allowed in this subpart to ascertain the condition of a covered pipeline segment. Confirmatory direct assessment is an integrity assessment method using more focused application of the principles and techniques of direct assessment to identify internal and external corrosion in a covered transmission pipeline segment. Covered segment or covered pipeline segment means a segment of gas transmission pipeline located in a high consequence area. The terms gas and transmission line are defined in §192.3.

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Direct assessment is an integrity assessment method that utilizes a process to evaluate certain threats (i.e., external corrosion, internal corrosion and stress corrosion cracking) to a covered pipeline segment’s integrity. The process includes the gathering and integration of risk factor data, indirect examination or analysis to identify areas of suspected corrosion, direct examination of the pipeline in these areas, and post assessment evaluation. High consequence area means an area established by one of the methods described in paragraphs (1) or (2) as follows: (1) An area defined as — (i) A Class 3 location under §192.5; or (ii) A Class 4 location under §192.5; or (iii) Any area in a Class 1 or Class 2 location where the potential impact radius is greater than 660 feet (200 meters), and the area within a potential impact circle contains 20 or more buildings intended for human occupancy; or (iv) Any area in a Class 1 or Class 2 location where the potential impact circle contains an identified site. (2) The area within a potential impact circle containing — (i) 20 or more buildings intended for human occupancy, unless the exception in paragraph (4) applies; or (ii) An identified site. (3) Where a potential impact circle is calculated under either method (1) or (2) to establish a high consequence area, the length of the high consequence area extends axially along the length of the pipeline from the outermost edge of the first potential impact circle that contains either an identified site or 20 or more buildings intended for human occupancy to the outermost edge of the last contiguous potential impact circle that contains either an identified site or 20 or more buildings intended for human occupancy. (See Figure E.I.A. in Appendix E.) (4) If in identifying a high consequence area under paragraph (1)(iii) of this definition or paragraph (2)(i) of this definition, the radius of the potential impact circle is greater than 660 feet (200 meters), the operator may identify a high consequence area based on a prorated number of buildings intended for human occupancy within a distance 660 feet (200 meters) from the centerline of the pipeline until December17, 2006. If an operator chooses this approach, the operator must prorate the number of buildings intended for human occupancy based on the ratio of an area with a radius of 660 feet (200 meters) to the area of the potential impact circle (i.e., the prorated number of buildings intended for human occupancy is equal to [20 x (660 feet [or 200 meters]/ potential impact radius in feet [or meters]) 2]). Identified site means each of the following areas: (a) An outside area or open structure that is occupied by twenty (20) or more persons on at least 50 days in any twelve (12)-month period. (The days need not be consecutive). Examples include but are not limited to, beaches, playgrounds, recreational facilities, camping grounds, outdoor theaters, stadiums, recreational areas near a body of water, or areas outside a rural building such as a religious facility); or (b) A building that is occupied by twenty (20) or more persons on at least five (5) days a week for ten (10) weeks in any twelve (12)-month period. (The days and weeks need not be consecutive). Examples include, but are not limited to, religious facilities, office buildings, community centers, general stores, 4-H facilities, or roller skating rinks); or (c) A facility occupied by persons who are confined, are of impaired mobility, or would be difficult to evacuate. Examples include but are not limited to hospitals, prisons, schools, day-care facilities, retirement facilities or assisted-living facilities. Potential impact circle is a circle of radius equal to the potential impact radius (PIR). Potential impact radius (PIR) means the radius of a circle within which the potential failure of a pipeline could have significant impact on people or property. PIR is determined by the formula r = 0.69 * (square root of (p*d2)), where ‘r’ is the radius of a circular area in feet surrounding the point of failure, ‘p’ is the maximum allowable operating pressure (MAOP) in the pipeline segment in pounds per square inch and ‘d’ is the nominal diameter of the pipeline in inches.

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Note: 0.69 is the factor for natural gas. This number will vary for other gases depending upon their heat of combustion. An operator transporting gas other than natural gas must use section 3.2 of ASME/ANSI B31.8S-2001 (Supplement to ASME B31.8; incorporated by reference, see §192.7) to calculate the impact radius formula. Remediation is a repair or mitigation activity an operator takes on a covered segment to limit or reduce the probability of an undesired event occurring or the expected consequences from the event. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004, Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004 and Amdt. 192-95 Correction, 69 FR 29903, May 26, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006]

GUIDE MATERIAL

Glossary of Commonly Used Terms and Abbreviations Used in Subpart O BAP means baseline assessment plan. CDA means confirmatory direct assessment. DA means direct assessment. ECDA means external corrosion direct assessment. FAQs mean frequently asked questions. Framework is an early version of an operator’s Integrity Management Program (IMP), which does not have

all the detailed processes in place. HCA means high consequence area. ICDA means internal corrosion direct assessment. IMP means Integrity Management Program. Low-frequency ERW (electric-resistance-welded) pipe is pipe that was manufactured using a 250-Hertz (Hz)

alternating electrical current to provide heat for fusion of the weld seam. Most pipe made using this process was manufactured prior to 1970.

Low-stress transmission line is a steel transmission line that operates below 30% SMYS. Plan is a particular component of the overall Integrity Management Program (IMP), and refers to a specific

action plan and documented criteria for implementing a particular program element or rule requirement. Process is a step-by-step logical set of integrated activities that proceed from the initial understanding of

what needs to be done, to the successful performance and documentation of results. Program is a document or a set of documents that systematically defines, controls, and implements integrity

management. SCCDA means stress corrosion cracking direct assessment. Note: For other terms and abbreviations, see Glossary of Commonly Used Terms and Glossary of Commonly Used Abbreviations of the guide material under §192.3.

§192.905 How does an operator identify a high consequence area?


(a) General. To determine which segments of an operator’s transmission pipeline system are covered by this subpart, an operator must identify the high consequence areas. An operator must use method (1) or (2) from the definition in §192.903 to identify a high consequence area. An operator

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may apply one method to its entire pipeline system, or an operator may apply one method to individual portions of the pipeline system. An operator must describe in its integrity management program which method it is applying to each portion of the operator’s pipeline system. The description must include the potential impact radius when utilized to establish a high consequence area. (See Appendix E.I. for guidance on identifying high consequence areas.) (b) (1) Identified sites. An operator must identify an identified site, for purposes of this subpart, from information the operator has obtained from routine operation and maintenance activities and from public officials with safety or emergency response or planning responsibilities who indicate to the operator that they know of locations that meet the identified site criteria. These public officials could include officials on a local emergency planning commission or relevant Native American tribal officials. (2) If a public official with safety or emergency response or planning responsibilities informs an operator that it does not have the information to identify an identified site, the operator must use one of the following sources, as appropriate, to identify these sites. (i) Visible marking (e.g., a sign); or (ii) The site is licensed or registered by a Federal, State, or local government agency; or (iii) The site is on a list (including a list on an internet web site) or map maintained by or available from a Federal, State, or local government agency and available to the general public. (c) Newly-identified areas. When an operator has information that the area around a pipeline segment not previously identified as a high consequence area could satisfy any of the definitions in §192.903, the operator must complete the evaluation using method (1) or (2). If the segment is determined to meet the definition as a high consequence area, it must be incorporated into the operator’s baseline assessment plan as a high consequence area within one year from the date the area is identified. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004]

GUIDE MATERIAL


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


(a) General. No later than December 17, 2004, an operator of a covered pipeline segment must develop and follow a written integrity management program that contains all the elements described in §192.911 and that addresses the risks on each covered transmission pipeline segment. The initial integrity management program must consist, at a minimum, of a framework that describes the process for implementing each program element, how relevant decisions will be made and by whom, a time line for completing the work to implement the program element, and how information gained from experience will be continuously incorporated into the program. The framework will evolve into a more detailed and comprehensive program. An operator must make continual improvements to the program. (b) Implementation Standards. In carrying out this subpart, an operator must follow the requirements of this subpart and of ASME/ANSI B31.8S (incorporated by reference, see §192.7) and its appendices, where specified. An operator may follow an equivalent standard or practice only when the operator demonstrates the alternative standard or practice provides an equivalent level of

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safety to the public and property. In the event of a conflict between this subpart and ASME/ANSI B31.8S, the requirements in this subpart control. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006]

GUIDE MATERIAL 1 WRITTEN PROGRAM 1.1 General.

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

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

ANSI Technical Report by GPTC (AGA Catalog Number X69806). 2 OPERATORS WITH NO HCAs

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

3 INCORPORATION BY REFERENCE 3.1 General. Subpart O requires use of the following documents, which are incorporated by reference in §192.7. (a) ASME B31.8S, “Supplement to B31.8 on Managing System Integrity of Gas Pipelines.” (b) NACE RP0502, “Pipeline External Corrosion Direct Assessment Methodology.”

An operator must meet the requirements of Subpart O and the referenced sections of these documents. In the event of a conflict between ASME B31.8S and NACE RP0502, the more stringent requirement should be followed.

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

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

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

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

SUMMARY OF INCORPORATED REFERENCES TO ASME B31.8S

ASME B31.8S Subpart O References General §§192.907(b); 192.911; 192.913(a), (b)(1), & (c); 192.935(b)(1)(iv)

Section 2 §192.917(a)

Section 3.2 §192.903 - definition of potential impact radius

Section 4 §192.917(b) & (d)

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

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

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

Section 7 §192.933(c) & (d)(1)

Section 9 §192.911(i)

Section 9.4 §192.945(a)

Section 10 §192.911(m)

Section 11 §192.911(k)

Section 12 §192.911(l)

Appendix A §§192.917(b); 192.945(a)

Appendix A2 §192.927(c)(1)(i)

Appendix A3 §§192.923(b)(3); 192.929(b)(1) & (b)(2)

Appendix A3.3 §192.929(b)(1)

Appendix A3.4 §192.929(b)(2)

Appendices A4.3 & A4.4 §192.917(e)(4)

Appendix A7 §192.917(e)(1)

Appendix B2 §§192.923(b)(2); 192.927(b)

TABLE 192.907i

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§192.909 How can an operator change its integrity management program?


(a) General. An operator must document any change to its program and the reasons for the change before implementing the change. (b) Notification. An operator must notify OPS, in accordance with §192.949, of any change to the program that may substantially affect the program’s implementation or may significantly modify the program or schedule for carrying out the program elements. An operator must also notify a State or local pipeline safety authority when either a covered segment is located in a State where OPS has an interstate agent agreement, or an intrastate covered segment is regulated by that State. An operator must provide the notification within 30 days after adopting this type of change into its program. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004 and Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004]

GUIDE MATERIAL 1 CHANGES TO BE DOCUMENTED

It is anticipated that there will be a number of changes over time to an operator’s Integrity Management Program (IMP). Documentation of changes and the reasons for them should include decisions, analyses, and processes used to change elements of the IMP. The operator should maintain previous versions of the IMP for the life of the pipeline. See guide material under §192.947. This documentation can be in electronic format. Factors that might cause a change to the IMP include the following.

(a) Information obtained from the integrity assessments. (b) Operating experience. (c) The operator’s understanding about the specific integrity threats and the relative importance of

those threats may change. (d) The operator’s understanding about a specific integrity assessment tool changes, and the operator

chooses to use another type. (e) Risks are different than previously understood and an operator needs to reprioritize assessments. (f) Identification of a new HCA, which adjusts the baseline assessment plan. (g) Development of additional program elements. 2 NOTIFICATION

When applicable, notification of program changes is required to OPS (and typically providing an informational copy to the state). Where OPS has an interstate agent agreement, or an intrastate covered segment is regulated by that state, the operator must also notify the state pipeline safety authority. A reference for state contacts is available at http://www.napsr.org.

2.1 Changes requiring notification.

Examples of situations that may lead to changes substantially affecting program implementation, or significantly modifying the program or schedule, are as follows.

(a) An incident on a lower-risk pipeline that would cause a reprioritization of the assessment schedule. (b) Changes that affect the overall manner in which an operator is conducting its IMP. (c) A merger of two companies that causes reprioritization of the assessment schedule under the

merged IMP.

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(d) Circumstances that would keep an operator from achieving the 2007 or 2012 assessment deadlines (e.g., weather or permit delays).

Notification should include the changes to the program and reasons for such changes. See guide material under §192.949.

2.2 Changes not requiring notification.

Minor changes that do not significantly affect program implementation or plans for carrying out program elements do not require a notification. Examples include the following.

(a) Editorial revisions. (b) Schedule changes due to weather or permit delays that have no impact on meeting deadlines. (c) Priority changes due to updated risk assessment information.

§192.911 What are the elements of an integrity management program?


An operator’s initial integrity management program begins with a framework (see § 192.907) and evolves into a more detailed and comprehensive integrity management program, as information is gained and incorporated into the program. An operator must make continual improvements to its program. The initial program framework and subsequent program must, at minimum, contain the following elements. (When indicated, refer to ASME/ANSI B31.8S (incorporated by reference, see §192.7) for more detailed information on the listed element.) (a) An identification of all high consequence areas, in accordance with §192.905. (b) A baseline assessment plan meeting the requirements of §192.919 and §192.921. (c) An identification of threats to each covered pipeline segment, which must include data integration and a risk assessment. An operator must use the threat identification and risk assessment to prioritize covered segments for assessment (§192.917) and to evaluate the merits of additional preventive and mitigative measures (§192.935) for each covered segment. (d) A direct assessment plan, if applicable, meeting the requirements of §192.923, and depending on the threat assessed, of §§192.925, 192.927, or 192.929. (e) Provisions meeting the requirements of §192.933 for remediating conditions found during an integrity assessment. (f) A process for continual evaluation and assessment meeting the requirements of §192.937. (g) If applicable, a plan for confirmatory direct assessment meeting the requirements of §192.931. (h) Provisions meeting the requirements of §192.935 for adding preventive and mitigative measures to protect the high consequence area. (i) A performance plan as outlined in ASME/ANSI B31.8S, section 9 that includes performance measures meeting the requirements of §192.945. (j) Record keeping provisions meeting the requirements of §192.947. (k) A management of change process as outlined in ASME/ANSI B31.8S, section 11. (l) A quality assurance process as outlined in ASME/ANSI B31.8S, section 12. (m) A communication plan that includes the elements of ASME/ANSI B31.8S, section 10, and that includes procedures for addressing safety concerns raised by — (1) OPS; and (2) A State or local pipeline safety authority when a covered segment is located in a State where OPS has an interstate agent agreement. (n) Procedures for providing (when requested), by electronic or other means, a copy of the operator’s risk analysis or integrity management program to — (1) OPS; and

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(2) A State or local pipeline safety authority when a covered segment is located in a State where OPS has an interstate agent agreement. (o) Procedures for ensuring that each integrity assessment is being conducted in a manner that minimizes environmental and safety risks. (p) A process for identification and assessment of newly-identified high consequence areas. (See §§192.905 and 192.921.) [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004 and Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006]

GUIDE MATERIAL


§192.913 When may an operator deviate its program from

certain requirements of this subpart? [Effective Date: 7-10-06]

(a) General. ASME/ANSI B31.8S (incorporated by reference, see §192.7) provides the essential features of a performance-based or a prescriptive integrity management program. An operator that uses a performance-based approach that satisfies the requirements for exceptional performance in paragraph (b) of this section may deviate from certain requirements in this subpart, as provided in paragraph (c) of this section. (b) Exceptional performance. An operator must be able to demonstrate the exceptional performance of its integrity management program through the following actions. (1) To deviate from any of the requirements set forth in paragraph (c) of this section, an operator must have a performance-based integrity management program that meets or exceed the performance-based requirements of ASME/ANSI B31.8S and includes, at a minimum, the following elements — (i) A comprehensive process for risk analysis; (ii) All risk factor data used to support the program; (iii) A comprehensive data integration process; (iv) A procedure for applying lessons learned from assessment of covered pipeline segments to pipeline segments not covered by this subpart; (v) A procedure for evaluating every incident, including its cause, within the operator’s sector of the pipeline industry for implications both to the operator’s pipeline system and to the operator’s integrity management program; (vi) A performance matrix that demonstrates the program has been effective in ensuring the integrity of the covered segments by controlling the identified threats to the covered segments; (vii) Semi-annual performance measures beyond those required in §192.945 that are part of the operator’s performance plan. (See §192.911(i).) An operator must submit these measures, by electronic or other means, on a semi-annual frequency to OPS in accordance with §192.951; and (viii) An analysis that supports the desired integrity reassessment interval and the remediation methods to be used for all covered segments. (2) In addition to the requirements for the performance-based plan, an operator must — (i) Have completed at least two integrity assessments on each covered pipeline segment the operator is including under the performance-based approach, and be able to

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demonstrate that each assessment effectively addressed the identified threats on the covered segment. (ii) Remediate all anomalies identified in the more recent assessment according to the requirements in §192.933, and incorporate the results and lessons learned from the more recent assessment into the operator’s data integration and risk assessment. (c) Deviation. Once an operator has demonstrated that it has satisfied the requirements of paragraph (b) of this section, the operator may deviate from the prescriptive requirements of ASME/ANSI B31.8S and of this subpart only in the following instances. (1) The time frame for reassessment as provided in §192.939 except that reassessment by some method allowed under this subpart (e.g., confirmatory direct assessment) must be carried out at intervals no longer than seven years; (2) The time frame for remediation as provided in §192.933 if the operator demonstrates the time frame will not jeopardize the safety of the covered segment. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004 and Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006]

GUIDE MATERIAL


§192.915 What knowledge and training must personnel have to carry out

an integrity management program? [Effective Date: 2-14-04]

(a) Supervisory personnel. The integrity management program must provide that each supervisor whose responsibilities relate to the integrity management program possesses and maintains a thorough knowledge of the integrity management program and of the elements for which the supervisor is responsible. The program must provide that any person who qualifies as a supervisor for the integrity management program has appropriate training or experience in the area for which the person is responsible. (b) Persons who carry out assessments and evaluate assessment results. The integrity management program must provide criteria for the qualification of any person — (1) Who conducts an integrity assessment allowed under this subpart; or (2) Who reviews and analyzes the results from an integrity assessment and evaluation; or (3) Who makes decisions on actions to be taken based on these assessments. (c) Persons responsible for preventive and mitigative measures. The integrity management program must provide criteria for the qualification of any person — (1) Who implements preventive and mitigative measures to carry out this subpart, including the marking and locating of buried structures; or (2) Who directly supervises excavation work carried out in conjunction with an integrity assessment. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004]

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GUIDE MATERIAL

1 SUPERVISORY PERSONNEL QUALIFICATIONS 1.1 General.

The integrity management program (IMP) should define the training, qualification, or experience required for supervisory personnel whose responsibilities relate to the IMP. Supervisory personnel can acquire thorough knowledge of the IMP by achieving the following.

(a) General understanding of, and familiarity with, the overall program; and (b) Specific knowledge in their respective areas of responsibility. 1.2 Gaining general understanding. Examples of means used to gain general understanding of the IMP include the following. (a) Conducting periodic review of the written program. (b) Training or orientation sessions. (c) Conducting peer reviews. (d) Using a list of subject matter experts that can be contacted for additional details. 1.3 Demonstrating specific knowledge.

Examples of means used to demonstrate specific knowledge of an individual’s area of responsibility include the following.

(a) Internal and external training records. (b) Experience résumés. (c) Licenses or certifications. (d) Continuing educational credits. (e) Qualification records. (f) Authored papers or articles that have been published. (g) Documented experience in developing standards and procedures. (h) Copies of presentations given to public, industry, or an operator’s internal groups. (i) Regulatory testimony. 2 OTHER QUALIFICATIONS 2.1 Personnel who require qualification.

The IMP must define the qualification criteria (e.g., knowledge, skills, abilities) for personnel who do the following.

(a) Perform assessments. (b) Evaluate assessment results. (c) Make technical decisions based upon assessment results (e.g., dig locations, repair methods,

prioritization of fieldwork). (d) Implement preventive and mitigative measures. (e) Supervise excavation work associated with assessments. 2.2 Demonstrating qualifications.

Examples of means used to demonstrate qualification of employees and contractors include the following.

(a) Training records. (b) Documented experience. (c) Qualification records. (d) Certifications from industry organizations. (e) Education records.

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3 DOCUMENTATION

The operator might consider developing a matrix of integrity management related tasks, which outline the qualification requirements, and what operator or contractor position may perform each task.

(a) Documentation of the knowledge and training of integrity management personnel should demonstrate the following.

(1) Competence in performing the assigned IMP element. (2) Awareness of the IMP requirements. (3) The process used to qualify the person for the IMP element. (b) Operators using contractors in the IMP should document that the contractor employees are

aware of and qualified for the applicable sections of the operator’s IMP. 4 REFERENCE

Qualification guidance is provided by ASNT ILI-PQ, “In-line Inspection Personnel Qualification and Certification.”

§192.917 How does an operator identify potential threats to pipeline integrity and

use the threat identification in its integrity program? [Effective Date: 7-10-06]

(a) Threat identification. An operator must identify and evaluate all potential threats to each covered pipeline segment. Potential threats that an operator must consider include, but are not limited to, the threats listed in ASME/ANSI B31.8S (incorporated by reference, see §192.7), section 2, which are grouped under the following four categories: (1) Time dependent threats such as internal corrosion, external corrosion, and stress corrosion cracking; (2) Static or resident threats, such as fabrication or construction defects; (3) Time independent threats such as third party damage and outside force damage; and (4) Human error. (b) Data gathering and integration. To identify and evaluate the potential threats to a covered pipeline segment, an operator must gather and integrate existing data and information on the entire pipeline that could be relevant to the covered segment. In performing this data gathering and integration, an operator must follow the requirements in ASME/ANSI B31.8S, section 4. At a minimum, an operator must gather and evaluate the set of data specified in Appendix A to ASME/ANSI B31.8S, and consider both on the covered segment and similar non-covered segments, past incident history, corrosion control records, continuing surveillance records, patrolling records, maintenance history, internal inspection records and all other conditions specific to each pipeline. (c) Risk assessment. An operator must conduct a risk assessment that follows ASME/ANSI B31.8S, section 5, and considers the identified threats for each covered segment. An operator must use the risk assessment to prioritize the covered segments for the baseline and continual reassessments (§§192.919, 192.921, 192.937), and to determine what additional preventive and mitigative measures are needed (§192.935) for the covered segment. (d) Plastic Transmission Pipeline. An operator of a plastic transmission pipeline must assess the threats to each covered segment using the information in sections 4 and 5 of ASME B31.8S, and consider any threats unique to the integrity of plastic pipe. (e) Actions to address particular threats. If an operator identifies any of the following threats, the operator must take the following actions to address the threat.

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(1) Third party damage. An operator must utilize the data integration required in paragraph (b) of this section and ASME/ANSI B31.8S, Appendix A7 to determine the susceptibility of each covered segment to the threat of third party damage. If an operator identifies the threat of third party damage, the operator must implement comprehensive additional preventive measures in accordance with §192.935 and monitor the effectiveness of the preventive measures. If, in conducting a baseline assessment under § 192.921, or a reassessment under §192.937, an operator uses an internal inspection tool or external corrosion direct assessment, the operator must integrate data from these assessments with data related to any encroachment or foreign line crossing on the covered segment, to define where potential indications of third party damage may exist in the covered segment. An operator must also have procedures in its integrity management program addressing actions it will take to respond to findings from this data integration. (2) Cyclic fatigue. How does an operator identify potential threats to pipeline integrity and use the threat identification in its integrity program? An operator must evaluate whether cyclic fatigue or other loading condition (including ground movement, suspension bridge condition) could lead to a failure of a deformation, including a dent or gouge, or other defect in the covered segment. An evaluation must assume the presence of threats in the covered segment that could be exacerbated by cyclic fatigue. An operator must use the results from the evaluation together with the criteria used to evaluate the significance of this threat to the covered segment to prioritize the integrity baseline assessment or reassessment. (3) Manufacturing and construction defects. If an operator identifies the threat of manufacturing and construction defects (including seam defects) in the covered segment, an operator must analyze the covered segment to determine the risk of failure from these defects. The analysis must consider the results of prior assessments on the covered segment. An operator may consider manufacturing and construction related defects to be stable defects if the operating pressure on the covered segment has not increased over the maximum operating pressure experienced during the five years preceding identification of the high consequence area. If any of the following changes occur in the covered segment, an operator must prioritize the covered segment as a high risk segment for the baseline assessment or a subsequent reassessment. (i) Operating pressure increases above the maximum operating pressure experienced during the preceding five years; (ii) MAOP increases; or (iii) The stresses leading to cyclic fatigue increase. (4) ERW pipe. If a covered pipeline segment contains low frequency electric resistance welded pipe (ERW), lap welded pipe or other pipe that satisfies the conditions specified in ASME/ANSI B31.8S, Appendices A4.3 and A4.4, and any covered or noncovered segment in the pipeline system with such pipe has experienced seam failure, or operating pressure on the covered segment has increased over the maximum operating pressure experienced during the preceding five years, an operator must select an assessment technology or technologies with a proven application capable of assessing seam integrity and seam corrosion anomalies. The operator must prioritize the covered segment as a high risk segment for the baseline assessment or a subsequent reassessment. (5) Corrosion. If an operator identifies corrosion on a covered pipeline segment that could adversely affect the integrity of the line (conditions specified in §192.935), the operator must evaluate and remediate, as necessary, all pipeline segments (both covered and non-covered) with similar material coating and environmental characteristics. An operator must establish a schedule for evaluating and remediating, as necessary, the similar segments that is consistent with the operator’s established operating and maintenance procedures under Part 192 for testing and repair. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004 and Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006]

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GUIDE MATERIAL


§192.919 What must be in the baseline assessment plan?


An operator must include each of the following elements in its written baseline assessment plan: (a) Identification of the potential threats to each covered pipeline segment and the information supporting the threat identification. (See §192.917.); (b) The methods selected to assess the integrity of the line pipe, including an explanation of why the assessment method was selected to address the identified threats to each covered segment. The integrity assessment method an operator uses must be based on the threats identified to the covered segment. (See §192.917.) More than one method may be required to address all the threats to the covered pipeline segment; (c) A schedule for completing the integrity assessment of all covered segments, including, risk factors considered in establishing the assessment schedule; (d) If applicable, a direct assessment plan that meets the requirements of §§192.923, and depending on the threat to be addressed, of §192.925, §192.927, or §192.929; and (e) A procedure to ensure that the baseline assessment is being conducted in a manner that minimizes environmental and safety risks. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004]

GUIDE MATERIAL


§192.921 How is the baseline assessment to be conducted?


(a) Assessment methods. An operator must assess the integrity of the line pipe in each covered segment by applying one or more of the following methods depending on the threats to which the covered segment is susceptible. An operator must select the method or methods best suited to address the threats identified to the covered segment (See §192.917). (1) Internal inspection tool or tools capable of detecting corrosion, and any other threats to which the covered segment is susceptible. An operator must follow ASME/ANSI B31.8S (incorporated by reference, see §192.7), section 6.2 in selecting the appropriate internal inspection tools for the covered segment. (2) Pressure test conducted in accordance with subpart J of this part. An operator must use the test pressures specified in Table 3 of section 5 of ASME/ANSI B31.8S, to justify an extended reassessment interval in accordance with §192.939.

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(3) Direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking. An operator must conduct the direct assessment in accordance with the requirements listed in §192.923 and with, as applicable, the requirements specified in §§192.925, 192.927 or 192.929; (4) Other technology that an operator demonstrates can provide an equivalent understanding of the condition of the line pipe. An operator choosing this option must notify the Office of Pipeline Safety (OPS) 180 days before conducting the assessment, in accordance with §192.949. An operator must also notify a State or local pipeline safety authority when either a covered segment is located in a State where OPS has an interstate agent agreement, or an intrastate covered segment is regulated by that State. (b) Prioritizing segments. An operator must prioritize the covered pipeline segments for the baseline assessment according to a risk analysis that considers the potential threats to each covered segment. The risk analysis must comply with the requirements in §192.917. (c) Assessment for particular threats. In choosing an assessment method for the baseline assessment of each covered segment, an operator must take the actions required in §192.917(e) to address particular threats that it has identified. (d) Time period. An operator must prioritize all the covered segments for assessment in accordance with § 192.917(c) and paragraph (b) of this section. An operator must assess at least 50% of the covered segments beginning with the highest risk segments, by December 17, 2007. An operator must complete the baseline assessment of all covered segments by December 17, 2012. (e) Prior assessment. An operator may use a prior integrity assessment conducted before December 17, 2002 as a baseline assessment for the covered segment, if the integrity assessment meets the baseline requirements in this subpart and subsequent remedial actions to address the conditions listed in §192.933 have been carried out. In addition, if an operator uses this prior assessment as its baseline assessment, the operator must reassess the line pipe in the covered segment according to the requirements of §192.937 and §192.939. (f) Newly-identified areas. When an operator identifies a new high consequence area (see §192.905), an operator must complete the baseline assessment of the line pipe in the newly- identified high consequence area within ten (10) years from the date the area is identified. (g) Newly-installed pipe. An operator must complete the baseline assessment of a newly-installed segment of pipe covered by this subpart within ten (10) years from the date the pipe is installed. An operator may conduct a pressure test in accordance with paragraph (a)(2) of this section, to satisfy the requirement for a baseline assessment. (h) Plastic transmission pipeline. If the threat analysis required in §192.917(d) on a plastic transmission pipeline indicates that a covered segment is susceptible to failure from causes other than third-party damage, an operator must conduct a baseline assessment of the segment in accordance with the requirements of this section and of §192.917. The operator must justify the use of an alternative assessment method that will address the identified threats to the covered segment. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004 and Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006]

GUIDE MATERIAL


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§192.923 How is direct assessment used and for what threats?


(a) General. An operator may use direct assessment either as a primary assessment method or as a supplement to the other assessment methods allowed under this subpart. An operator may only use direct assessment as the primary assessment method to address the identified threats of external corrosion (ECDA), internal corrosion (ICDA), and stress corrosion cracking (SCCDA). (b) Primary Method. An operator using direct assessment as a primary assessment method must have a plan that complies with the requirements in — (1) ASME/ANSI B31.8S (incorporated by reference, see §192.7), section 6.4; NACE RP0502-2002 (incorporated by reference, see §192.7); and §192.925 if addressing external corrosion (ECDA). (2) ASME/ANSI B31.8S, section 6.4 and Appendix B2, and §192.927 if addressing internal corrosion (ICDA). (3) ASME/ANSI B31.8S Appendix A3, and §192.929 if addressing stress corrosion cracking (SCCDA). (c) Supplemental method. An operator using direct assessment as a supplemental assessment method for any applicable threat must have a plan that follows the requirements for confirmatory direct assessment in §192.931. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006]

GUIDE MATERIAL 1 GENERAL (a) Direct Assessment (DA) is a structured process for assessing buried, onshore steel pipelines. This

process is comprised of multiple, interdependent steps, which include the following. (1) Gathering and integration of data. (2) Indirect examination. (3) Direct examination. (4) Post-assessment evaluation. (b) See guide material under §§192.925, 192.927, and 192.929. 2 DIRECT ASSESSMENT PLAN (a) Only operators that use DA need to prepare a written DA plan. (b) An operator’s DA plan should include a written statement, procedure, or other document

addressing each specific step of the DA methodology. The plan can be multiple binders with relevant plan sections kept at appropriate locations. Other documents (or applicable sections) may be referenced. The referenced documents should be readily available to the users.

(c) DA plans will vary in length and complexity depending upon an operator’s size, locale, policies, and amount of pipeline to be assessed. An operator may choose to have a single DA plan for all, or a separate DA plan for each, of the three corrosion threats: external, internal, and stress corrosion cracking.

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§192.925 What are the requirements for using

External Corrosion Direct Assessment (ECDA)? [Effective Date: 7-10-06]

(a) Definition. ECDA is a four-step process that combines preassessment, indirect inspection, direct examination, and post assessment to evaluate the threat of external corrosion to the integrity of a pipeline. (b) General requirements. An operator that uses direct assessment to assess the threat of external corrosion must follow the requirements in this section, in ASME/ANSI B31.8S (incorporated by reference, see §192.7), section 6.4, and in NACE RP0502–2002 (incorporated by reference, see §192.7). An operator must develop and implement a direct assessment plan that has procedures addressing preassessment, indirect examination, direct examination, and post-assessment. If the ECDA detects pipeline coating damage, the operator must also integrate the data from the ECDA with other information from the data integration (§192.917(b)) to evaluate the covered segment for the threat of third party damage, and to address the threat as required by §192.917(e)(1). (1) Preassessment. In addition to the requirements in ASME/ANSI B31.8S section 6.4 and NACE RP0502–2002, section 3, the plan’s procedures for preassessment must include — (i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a covered segment; and (ii) The basis on which an operator selects at least two different, but complementary indirect assessment tools to assess each ECDA Region. If an operator utilizes an indirect inspection method that is not discussed in Appendix A of NACE RP0502–2002, the operator must demonstrate the applicability, validation basis, equipment used, application procedure, and utilization of data for the inspection method. (2) Indirect examination. In addition to the requirements in ASME/ANSI B31.8S section 6.4 and NACE RP0502–2002, section 4, the plan’s procedures for indirect examination of the ECDA regions must include — (i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a covered segment; (ii) Criteria for identifying and documenting those indications that must be considered for excavation and direct examination. Minimum identification criteria include the known sensitivities of assessment tools, the procedures for using each tool, and the approach to be used for decreasing the physical spacing of indirect assessment tool readings when the presence of a defect is suspected; (iii) Criteria for defining the urgency of excavation and direct examination of each indication identified during the indirect examination. These criteria must specify how an operator will define the urgency of excavating the indication as immediate, scheduled or monitored; and (iv) Criteria for scheduling excavation of indications for each urgency level. (3) Direct examination. In addition to the requirements in ASME/ANSI B31.8S section 6.4 and NACE RP0502–2002, section 5, the plan’s procedures for direct examination of indications from the indirect examination must include — (i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a covered segment; (ii) Criteria for deciding what action should be taken if either: (A) Corrosion defects are discovered that exceed allowable limits (Section 5.5.2.2 of NACE RP0502–2002), or (B) Root cause analysis reveals conditions for which ECDA is not suitable (Section 5.6.2 of NACE RP0502–2002); (iii) Criteria and notification procedures for any changes in the ECDA Plan, including changes that affect the severity classification, the priority of direct examination, and the time frame for direct examination of indications; and

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(iv) Criteria that describe how and on what basis an operator will reclassify and reprioritize any of the provisions that are specified in section 5.9 of NACE RP0502–2002. (4) Post assessment and continuing evaluation. In addition to the requirements in ASME/ANSI B31.8S section 6.4 and NACE RP0502–2002, section 6, the plan’s procedures for post assessment of the effectiveness of the ECDA process must include — (i) Measures for evaluating the long-term effectiveness of ECDA in addressing external corrosion in covered segments; and (ii) Criteria for evaluating whether conditions discovered by direct examination of indications in each ECDA region indicate a need for reassessment of the covered segment at an interval less than that specified in §192.939. (See Appendix D of NACE RP0502–2002.) [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004, Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004 and Amdt. 192-95 Correction, 69 FR 29903, May 26, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006]

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§192.927 What are the requirements for using

Internal Corrosion Direct Assessment (ICDA)? [Effective Date: 7-10-06]

(a) Definition. Internal Corrosion Direct Assessment (ICDA) is a process an operator uses to identify areas along the pipeline where fluid or other electrolyte introduced during normal operation or by an upset condition may reside, and then focuses direct examination on the locations in covered segments where internal corrosion is most likely to exist. The process identifies the potential for internal corrosion caused by microorganisms, or fluid with CO2, O2, hydrogen sulfide or other contaminants present in the gas. (b) General requirements. An operator using direct assessment as an assessment method to address internal corrosion in a covered pipeline segment must follow the requirements in this section and in ASME/ANSI B31.8S (incorporated by reference, see §192.7), section 6.4 and appendix B2. The ICDA process described in this section applies only for a segment of pipe transporting nominally dry natural gas, and not for a segment with electrolyte nominally present in the gas stream. If an operator uses ICDA to assess a covered segment operating with electrolyte present in the gas stream, the operator must develop a plan that demonstrates how it will conduct ICDA in the segment to effectively address internal corrosion, and must provide notification in accordance with §192.921(a)(4) or §192.937(c)(4). (c) The ICDA plan. An operator must develop and follow an ICDA plan that provides for preassessment, identification of ICDA regions and excavation locations, detailed examination of pipe at excavation locations, and post-assessment evaluation and monitoring. (1) Preassessment. In the preassessment stage, an operator must gather and integrate data and information needed to evaluate the feasibility of ICDA for the covered segment, and to support use of a model to identify the locations along the pipe segment where electrolyte may accumulate, to identify ICDA regions, and to identify areas within the covered segment where liquids may potentially be entrained. This data and information includes, but is not limited to — (i) All data elements listed in Appendix A2 of ASME/ANSI B31.8S; (ii) Information needed to support use of a model that an operator must use to identify areas along the pipeline where internal corrosion is most likely to occur. (See paragraph (a) of this

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

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with one of the two following required actions and remediate the conditions the operator finds in accordance with §192.933. (A) Conduct excavations of covered segments at locations downstream from where the electrolyte might have entered the pipe; or (B) Assess the covered segment using another integrity assessment method allowed by this subpart. (5) Other requirements. The ICDA plan must also include — (i) Criteria an operator will apply in making key decisions (e.g., ICDA feasibility, definition of ICDA Regions, conditions requiring excavation) in implementing each stage of the ICDA process; (ii) Provisions for applying more restrictive criteria when conducting ICDA for the first time on a covered segment and that become less stringent as the operator gains experience; and (iii) Provisions that analysis be carried out on the entire pipeline in which covered segments are present, except that application of the remediation criteria of §192.933 may be limited to covered segments. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan. 15, 2004 and Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006]

GUIDE MATERIAL


§192.929 What are the requirements for using Direct Assessment for

Stress Corrosion Cracking (SCCDA)? [Effective Date: 7-10-06]

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

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[Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004 and Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006]

GUIDE MATERIAL


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


An operator using the confirmatory direct assessment (CDA) method as allowed in §192.937 must have a plan that meets the requirements of this section and of §§192.925 (ECDA) and §192.927 (ICDA). (a) Threats. An operator may only use CDA on a covered segment to identify damage resulting from external corrosion or internal corrosion. (b) External corrosion plan. An operator’s CDA plan for identifying external corrosion must comply with §192.925 with the following exceptions. (1) The procedures for indirect examination may allow use of only one indirect examination tool suitable for the application. (2) The procedures for direct examination and remediation must provide that — (i) All immediate action indications must be excavated for each ECDA region; and (ii) At least one high risk indication that meets the criteria of scheduled action must be excavated in each ECDA region. (c) Internal corrosion plan. An operator’s CDA plan for identifying internal corrosion must comply with §192.927 except that the plan’s procedures for identifying locations for excavation may require excavation of only one high risk location in each ICDA region. (d) Defects requiring near-term remediation. If an assessment carried out under paragraph (b) or (c) of this section reveals any defect requiring remediation prior to the next scheduled assessment, the operator must schedule the next assessment in accordance with NACE RP0502-2002 (incorporated by reference, see §192.7), section 6.2 and 6.3. If the defect requires immediate remediation, then the operator must reduce pressure consistent with §192.933 until the operator has completed reassessment using one of the assessment techniques allowed in §192.937. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006]

GUIDE MATERIAL


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§192.933 What actions must be taken to address integrity issues?


(a) General requirements. An operator must take prompt action to address all anomalous conditions that the operator discovers through the integrity assessment. In addressing all conditions, an operator must evaluate all anomalous conditions and remediate those that could reduce a pipeline’s integrity. An operator must be able to demonstrate that the remediation of the condition will ensure that the condition is unlikely to pose a threat to the integrity of the pipeline until the next reassessment of the covered segment. If an operator is unable to respond within the time limits for certain conditions specified in this section, the operator must temporarily reduce the operating pressure of the pipeline or take other action that ensures the safety of the covered segment. If pressure is reduced, an operator must determine the temporary reduction in operating pressure using ASME/ANSI B31G (incorporated by reference, see §192.7) or AGA Pipeline Research Committee Project PR-3-805 ("RSTRENG"; incorporated by reference, see §192.7) or reduce the operating pressure to a level not exceeding 80% of the level at the time the condition was discovered. (See Appendix A to this part 192 for information on availability of incorporation by reference information). A reduction in operating pressure cannot exceed 365 days without an operator providing a technical justification that the continued pressure restriction will not jeopardize the integrity of the pipeline. (b) Discovery of condition. Discovery of a condition occurs when an operator has adequate information about a condition to determine that the condition presents a potential threat to the integrity of the pipeline. A condition that presents a potential threat includes, but is not limited to, those conditions that require remediation or monitoring listed under paragraphs (d)(1) through (d)(3) of this section. An operator must promptly, but no later than 180 days after conducting an integrity assessment, obtain sufficient information about a condition to make that determination, unless the operator demonstrates that the 180-day period is impracticable. (c) Schedule for evaluation and remediation. An operator must complete remediation of a condition according to a schedule that prioritizes the conditions for evaluation and remediation. Unless a special requirement for remediating certain conditions applies, as provided in paragraph (d) of this section, an operator must follow the schedule in ASME/ANSI B31.8S (incorporated by reference, see §192.7), section 7, Figure 4. If an operator cannot meet the schedule for any condition, the operator must justify the reasons why it cannot meet the schedule and that the changed schedule will not jeopardize public safety. An operator must notify OPS in accordance with § 192.949 if it cannot meet the schedule and cannot provide safety through a temporary reduction in operating pressure or other action. An operator must also notify a State or local pipeline safety authority when either a covered segment is located in a State where OPS has an interstate agent agreement, or an intrastate covered segment is regulated by that State. (d) Special requirements for scheduling remediation. (1) Immediate repair conditions. An operator’s evaluation and remediation schedule must follow ASME/ANSI B31.8S, section 7 in providing for immediate repair conditions. To maintain safety, an operator must temporarily reduce operating pressure in accordance with paragraph (a) of this section or shut down the pipeline until the operator completes the repair of these conditions. An operator must treat the following conditions as immediate repair conditions: (i) A calculation of the remaining strength of the pipe shows a predicted failure pressure less than or equal to1.1 times the maximum allowable operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, ASME/ANSI B31G; RSTRENG; or an alternative equivalent method of remaining strength calculation. These documents are incorporated by reference and available at the addresses listed in Appendix A to Part 192. (ii) A dent that has any indication of metal loss, cracking or a stress riser. (iii) An indication or anomaly that in the judgment of the person designated by the operator to evaluate the assessment results requires immediate action.

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(2) One-year conditions. Except for conditions listed in paragraph (d)(1) and (d)(3) of this section, an operator must remediate any of the following within one year of discovery of the condition: (i) A smooth dent located between the 8 o’clock and 4 o’clock positions (upper 2/3 of the pipe) with a depth greater than 6% of the pipeline diameter (greater than 0.50 inches in depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12). (ii) A dent with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or at a longitudinal seam weld. (3) Monitored conditions. An operator does not have to schedule the following conditions for remediation, but must record and monitor the conditions during subsequent risk assessments and integrity assessments for any change that may require remediation: (i) A dent with a depth greater than 6% of the pipeline diameter (greater than 0.50 inches in depth for a pipeline diameter less than NPS 12) located between the 4 o’clock position and the 8 o’clock position (bottom 1/3 of the pipe). (ii) A dent located between the 8 o’clock and 4 o’clock positions (upper 2/3 of the pipe) with a depth greater than 6% of the pipeline diameter (greater than 0.50 inches in depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12), and engineering analyses of the dent demonstrate critical strain levels are not exceeded. (iii) A dent with a depth greater than 2% of the pipeline’s diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or a longitudinal seam weld, and engineering analyses of the dent and girth or seam weld demonstrate critical strain levels are not exceeded. These analyses must consider weld properties. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004 and Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006]

GUIDE MATERIAL


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


(a) General requirements. An operator must take additional measures beyond those already required by Part 192 to prevent a pipeline failure and to mitigate the consequences of a pipeline failure in a high consequence area. An operator must base the additional measures on the threats the operator has identified to each pipeline segment. (See §192.917.) An operator must conduct, in accordance with one of the risk assessment approaches in ASME/ANSI B31.8S (incorporated by reference, see §192.7), section 5, a risk analysis of its pipeline to identify additional measures to protect the high consequence area and enhance public safety. Such additional measures include, but are not limited to, installing Automatic Shut-off Valves or Remote Control Valves, installing computerized monitoring and leak detection systems, replacing pipe segments with pipe of heavier wall thickness, providing additional training to personnel on response procedures, conducting drills with local emergency responders and implementing additional inspection and maintenance programs. (b) Third party damage and outside force damage. (1) Third party damage. An operator must enhance its damage prevention program, as

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required under §192.614 of this part, with respect to a covered segment to prevent and minimize the consequences of a release due to third party damage. Enhanced measures to an existing damage prevention program include, at a minimum — (i) Using qualified personnel (see §192.915) for work an operator is conducting that could adversely affect the integrity of a covered segment, such as marking, locating, and direct supervision of known excavation work. (ii) Collecting in a central database information that is location specific on excavation damage that occurs in covered and non covered segments in the transmission system and the root cause analysis to support identification of targeted additional preventative and mitigative measures in the high consequence areas. This information must include recognized damage that is not required to be reported as an incident under part 191. (iii) Participating in one-call systems in locations where covered segments are present. (iv) Monitoring of excavations conducted on covered pipeline segments by pipeline personnel. If an operator finds physical evidence of encroachment involving excavation that the operator did not monitor near a covered segment, an operator must either excavate the area near the encroachment or conduct an above ground survey using methods defined in NACE RP0502–2002 (incorporated by reference, see §192.7). An operator must excavate, and remediate, in accordance with ANSI/ASME B31.8S and §192.933 any indication of coating holidays or discontinuity warranting direct examination. (2) Outside force damage. If an operator determines that outside force (e.g., earth movement, floods, unstable suspension bridge) is a threat to the integrity of a covered segment, the operator must take measures to minimize the consequences to the covered segment from outside force damage. These measures include, but are not limited to, increasing the frequency of aerial, foot or other methods of patrols, adding external protection, reducing external stress, and relocating the line. (c) Automatic shut-off valves (ASV) or Remote control valves (RCV). If an operator determines, based on a risk analysis, that an ASV or RCV would be an efficient means of adding protection to a high consequence area in the event of a gas release, an operator must install the ASV or RCV. In making that determination, an operator must, at least, consider the following factors — swiftness of leak detection and pipe shutdown capabilities, the type of gas being transported, operating pressure, the rate of potential release, pipeline profile, the potential for ignition, and location of nearest response personnel. (d) Pipelines operating below 30% SMYS. An operator of a transmission pipeline operating below 30% SMYS located in a high consequence area must follow the requirements in paragraphs (d)(1) and (d)(2) of this section. An operator of a transmission pipeline operating below 30% SMYS located in a Class 3 or Class 4 area but not in a high consequence area must follow the requirements in paragraphs (d)(1), (d)(2) and (d)(3) of this section. (1) Apply the requirements in paragraphs (b)(1)(i) and (b)(1)(iii) of this section to the pipeline; and (2) Either monitor excavations near the pipeline, or conduct patrols as required by §192.705 of the pipeline at bi-monthly intervals. If an operator finds any indication of unreported construction activity, the operator must conduct a follow up investigation to determine if mechanical damage has occurred. (3) Perform semi-annual leak surveys (quarterly for unprotected pipelines or cathodically protected pipe where electrical surveys are impractical). (e) Plastic transmission pipeline. An operator of a plastic transmission pipeline must apply the requirements in paragraphs (b)(1)(i), (b)(1)(iii) and (b)(1)(iv) of this section to the covered segments of the pipeline. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004, Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004 and Amdt. 192-95 Correction, 69 FR 29903, May 26, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006]

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

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

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

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

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

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

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

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

potential release rate. (vi) Pipeline profile. Example: Heavier-than-air gases can pool in low elevation spots. An ASV

or RCV in such locations may allow faster shut off and, therefore, less accumulation of gas.

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

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

(2) An operator may also consider the following. (i) Seasonal weather restrictions that can impede access. (ii) Depth of pipe as it relates to access for squeeze-off. (iii) River crossings or other geographical features that affect access for maintenance or response. (iv) Proximity of the HCA to existing valves. (v) Population density. (vi) Wide pressure fluctuations due to normal operating conditions (e.g., power plant locations). (vii) Maintenance, reliability, and cost-benefit issues. (b) Installation of computerized monitoring and leak detection systems. An operator may consider the following, which could provide earlier leak or pipeline rupture detection. (1) Increasing the locations monitored by SCADA. (2) Automating data gathering from other monitoring devices such as pressure transmitters. (c) Replacing pipe with that of heavier wall thickness, which is more resistant to damage from external forces. (d) Providing additional training on response procedures. An operator may consider the following. (1) Increasing the frequency of emergency response training. (2) Conducting tabletop or field drills. (3) Hiring a third party with expertise in emergency response to conduct training. (4) Attending emergency response training offered by industry associations. (e) Conducting drills with local emergency responders. The operator may consider the following.

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(1) Including the drill as part of liaison meetings with emergency responders. (2) Working with local multi-agency, emergency coordination groups. (3) Incorporating the drill into local fire or police academy curriculum. (f) Implementing additional inspection and maintenance programs. The operator may consider the following. (1) Increasing leak survey frequencies. (2) Increasing patrol frequencies. (3) Using procedures with more stringent criteria than required by the Regulations. (4) Increasing facility inspection frequencies. 2 THIRD PARTY DAMAGE (§192.935(b)(1))

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

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

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

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

following. (i) Number of leaks or ruptures. (ii) Number of known damages not resulting in leaks or ruptures. (iii) Excavation method. (iv) Name of excavator causing damage. (2) Root cause analysis data to identify targeted P&M measures for HCAs. This might include the

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

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

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

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

HCA. (5) Documenting excavation monitoring using one or more of the following.

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(i) Time card accounting. (ii) Special forms. (iii) Time-stamped electronic data. (iv) Maps. (e) When there is physical evidence of an excavation near a covered segment that the operator did not

monitor, either excavate the area or conduct an aboveground survey as defined in NACE RP-0502-2002 (e.g., DCVG). Examples of how to identify an encroachment might include the following.

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

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

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

lowering or raising the pipeline. (b) An operator may also consider installing the following. (1) River anchors where appropriate. (2) Elevated relief or vent stacks on regulator stations. (3) Additional bridge hangers or pipe supports. 4 PIPELINES OPERATING BELOW 30% SMYS (§192.935(d)) Pipelines operating below 30% SMYS have additional requirements as follows. (a) For all Class locations in an HCA, the following apply. (1) Qualify personnel to conduct the following activities related to work the operator is conducting

in a covered segment. (i) Locating the pipeline. (ii) Marking the pipeline. (iii) Directly supervising known excavation work. A qualification for this activity might include

the following. (A) Recognition of line-locate markings. (B) Knowledge of One-Call requirements. (C) Knowledge of operator’s applicable procedures, including emergency response. (D) Understanding the risks of various excavation methods. (iv) Other activities that could adversely affect the integrity of the pipeline. (2) Participate in a One-Call program wherever there are covered segments. (3) Either monitor excavations near the pipeline, or conduct patrols on a bi-monthly frequency. Any

indication of unreported construction activity requires an investigation to determine if any damage has occurred.

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(b) For Class 3 or Class 4 areas outside of an HCA. (1) Qualify personnel to conduct the following activities related to work the operator is conducting

in covered segment. (i) Locating the pipeline. (ii) Marking the pipeline. (iii) Directly supervising known excavation work. A qualification for this activity might include

the following. (A) Recognition of line-locate markings. (B) Knowledge of One-Call requirements. (C) Knowledge of operator’s applicable procedures, including emergency response. (D) Understanding the risks of various excavation methods. (iv) Other activities that could adversely affect the integrity of the pipeline. (2) Participate in a One-Call program wherever there are covered segments. (3) Either monitor excavations near the pipeline, or conduct patrols on a bi-monthly frequency. Any

indication of unreported construction activity requires an investigation to determine if any damage has occurred.

(4) Perform semi-annual leak surveys. For unprotected or cathodically protected pipe where electrical surveys are impractical, perform quarterly leak surveys.

(c) See Table 192.935i. 5 PLASTIC TRANSMISSION LINES (§192.935(e)) Plastic transmission lines have additional requirements as follows. (a) Qualify personnel to conduct the following activities related to work the operator is conducting in a

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

following. (i) Recognition of line-locate markings. (ii) Knowledge of One-Call requirements. (iii) Knowledge of operator’s applicable procedures, including emergency response. (iv) Understanding the risks of various excavation methods. (4) Other activities that could adversely affect the integrity of the pipeline. (b) Participate in a One-Call program wherever there are covered segments. (c) Monitor excavations on covered segments. An operator may want to consider the following. (1) Mapping HCAs so field personnel can easily recognize when they are in an area that requires

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

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

HCA. (5) Documenting excavation monitoring by using one or more of the following. (i) Time card accounting. (ii) Special forms. (iii) Time-stamped electronic data. (iv) Maps. (d) When there is physical evidence of an encroachment on a covered segment that the operator did

not monitor, excavate the area to determine if any damage has occurred. Examples of how to identify an encroachment include the following.

(1) New pavement patches. (2) Heavy equipment on site. (3) Disturbed earth.

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(4) New structures requiring excavation (e.g., fence posts, telephone poles, buildings, slabs). (5) Exposed pipe. (6) New landscaping. (7) One-call documentation. (e) See Table 192.935i.

ADDITIONAL P&M MEASURES FOR TRANSMISSION PIPELINES OPERATING BELOW 30% SMYS AND

PLASTIC TRANSMISSION LINES

Location General Requirements

Use Qualified

Personnel

Participate in One-Call

Monitor Excavations or Additional Patrol

Additional Leak

Survey

Class 1 & 2 in HCA

X

X X X

Class 1 & 2 outside HCA

Class 3 & 4 in HCA

X

X X X

Class 3 & 4 outside HCA

X X X X

Plastic Transmission

X

X X X (monitor only)*

*The option of patrolling is not available for plastic transmission lines.

TABLE 192.935i

§192.937 What is a continual process of evaluation and assessment to

maintain a pipeline’s integrity? [Effective Date: 7-10-06]

(a) General. After completing the baseline integrity assessment of a covered segment, an operator must continue to assess the line pipe of that segment at the intervals specified in §192.939 and periodically evaluate the integrity of each covered pipeline segment as provided in paragraph (b) of this section. An operator must reassess a covered segment on which a prior assessment is credited as a baseline under §192.921(e) by no later than December 17, 2009. An operator must reassess a covered segment on which a baseline assessment is conducted during the baseline period specified in §192.921(d) by no later than seven years after the baseline assessment of that covered segment unless the evaluation under paragraph (b) of this section indicates earlier reassessment. (b) Evaluation. An operator must conduct a periodic evaluation as frequently as needed to assure the integrity of each covered segment. The periodic evaluation must be based on a data integration and risk assessment of the entire pipeline as specified in §192.917. For plastic transmission pipelines, the periodic evaluation is based on the threat analysis specified in 192.917(d). For all other transmission pipelines, the evaluation must consider the past and present

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integrity assessment results, data integration and risk assessment information (§192.917), and decisions about remediation (§192.933) and additional preventive and mitigative actions (§192.935). An operator must use the results from this evaluation to identify the threats specific to each covered segment and the risk represented by these threats. (c) Assessment methods. In conducting the integrity reassessment, an operator must assess the integrity of the line pipe in the covered segment by any of the following methods as appropriate for the threats to which the covered segment is susceptible (see §192.917), or by confirmatory direct assessment under the conditions specified in §192.931. (1) Internal inspection tool or tools capable of detecting corrosion, and any other threats to which the covered segment is susceptible. An operator must follow ASME/ANSI B31.8S (incorporated by reference, see §192.7), section 6.2 in selecting the appropriate internal inspection tools for the covered segment. (2) Pressure test conducted in accordance with subpart J of this part. An operator must use the test pressures specified in Table 3 of section 5 of ASME/ANSI B31.8S, to justify an extended reassessment interval in accordance with §192.939. (3) Direct assessment to address threats of external corrosion, internal corrosion, or stress corrosion cracking. An operator must conduct the direct assessment in accordance with the requirements listed in §192.923 and with as applicable, the requirements specified in §§192.925, 192.927 or 192.929; (4) Other technology that an operator demonstrates can provide an equivalent understanding of the condition of the line pipe. An operator choosing this option must notify the Office of Pipeline Safety (OPS) 180 days before conducting the assessment, in accordance with §192.949. An operator must also notify a State or local pipeline safety authority when either a covered segment is located in a State where OPS has an interstate agent agreement, or an intrastate covered segment is regulated by that State. (5) Confirmatory direct assessment when used on a covered segment that is scheduled for reassessment at a period longer than seven years. An operator using this reassessment method must comply with §192.931. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004 and Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006]

GUIDE MATERIAL


§192.939 What are the required reassessment intervals?


An operator must comply with the following requirements in establishing the reassessment interval for the operator’s covered pipeline segments. (a) Pipelines operating at or above 30% SMYS. An operator must establish a reassessment interval for each covered segment operating at or above 30% SMYS in accordance with the requirements of this section. The maximum reassessment interval by an allowable reassessment method is seven years. If an operator establishes a reassessment interval that is greater than seven years, the operator must, within the seven-year period, conduct a confirmatory direct assessment on the covered segment, and then conduct the follow-up reassessment at the interval the operator has established. A reassessment carried out using confirmatory direct assessment must be done in

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accordance with §192.931. The table that follows this section sets forth the maximum allowed reassessment intervals. (1) Pressure test or internal inspection or other equivalent technology. An operator that uses pressure testing or internal inspection as an assessment method must establish the reassessment interval for a covered pipeline segment by — (i) Basing the interval on the identified threats for the covered segment (see §192.917) and on the analysis of the results from the last integrity assessment and from the data integration and risk assessment required by §192.917; or (ii) Using the intervals specified for different stress levels of pipeline (operating at or above 30% SMYS) listed in ASME/ANSI B31.8S, section 5, Table 3. (2) External Corrosion Direct Assessment. An operator that uses ECDA that meets the requirements of this subpart must determine the reassessment interval according to the requirements in paragraphs 6.2 and 6.3 of NACE RP0502-2002 (incorporated by reference, see §192.7). (3) Internal Corrosion or SCC Direct Assessment. An operator that uses ICDA or SCCDA in accordance with the requirements of this subpart must determine the reassessment interval according to the following method. However, the reassessment interval cannot exceed those specified for direct assessment in ASME/ANSI B31.8S, section 5, Table 3. (i) Determine the largest defect most likely to remain in the covered segment and the corrosion rate appropriate for the pipe, soil and protection conditions; (ii) Use the largest remaining defect as the size of the largest defect discovered in the SCC or ICDA segment; and (iii) Estimate the reassessment interval as half the time required for the largest defect to grow to a critical size. (b) Pipelines Operating Below 30% SMYS. An operator must establish a reassessment interval for each covered segment operating below 30% SMYS in accordance with the requirements of this section. The maximum reassessment interval by an allowable reassessment method is seven years. An operator must establish reassessment by at least one of the following — (1) Reassessment by pressure test, internal inspection or other equivalent technology following the requirements in paragraph (a)(1) of this section except that the stress level referenced in (a)(1)(ii) would be adjusted to reflect the lower operating stress level. If an established interval is more than seven years, the operator must conduct by the seventh year of the interval either a confirmatory direct assessment in accordance with §192.931, or a low stress reassessment in accordance with §192.941. (2) Reassessment by ECDA following the requirements in paragraph (a)(2) of this section. (3) Reassessment by ICDA or SCCDA following the requirements in paragraph (a)(3) of this section. (4) Reassessment by confirmatory direct assessment at 7-year intervals in accordance with §192.931, with reassessment by one of the methods listed in paragraphs (b)(1 ) through (b)(3) of this section by year 20 of the interval. (5) Reassessment by the low stress assessment method at 7-year intervals in accordance with §192.941 with reassessment by one of the methods listed in paragraphs (b)(1) through (b)(3) of this section by year 20 of the interval. The following table sets forth the maximum reassessment intervals. Also refer to Appendix E.II for guidance on Assessment Methods and Assessment Schedule for Transmission Pipelines Operating Below 30% SMYS. In case of conflict between the rule and the guidance in the Appendix, the requirements of the rule control. An operator must comply with the following requirements in establishing a reassessment interval for a covered segment: (6) An operator must comply with the following requirements in establishing a reassessment interval for a covered segment:

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Maximum Reassessment Interval Assessment

Method Pipeline operating at or

above 50% SMYS Pipeline operating at or above 30% SMYS, up

to 50% SMYS

Pipeline operating below 30% SMYS

Internal Inspection Tool, Pressure Test or Direct Assessment

10 years(*) 15 years(*) 20 years(**)

Confirmatory Direct Assessment

7 years 7 years 7 years

Low Stress Reassessment

Not Applicable Not Applicable 7 years + ongoing actions specified in §192.941

(*) A Confirmatory direct assessment as described in §192.931 must be conducted by year 7 in a 10-year interval and years 7 and 14 of a 15-year interval. (**) A low stress reassessment or Confirmatory direct assessment must be conducted by years 7 and 14 of the interval.

[Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004 and Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004 Amdt. 192-103]

GUIDE MATERIAL


§192.941 What is a low stress reassessment?


(a) General. An operator of a transmission line that operates below 30% SMYS may use the following method to reassess a covered segment in accordance with §192.939. This method of reassessment addresses the threats of external and internal corrosion. The operator must have conducted a baseline assessment of the covered segment in accordance with the requirements of §§192.919 and 192.921. (b) External corrosion. An operator must take one of the following actions to address external corrosion on the low stress covered segment. (1) Cathodically protected pipe. To address the threat of external corrosion on cathodically protected pipe in a covered segment, an operator must perform an electrical survey (i.e. indirect examination tool/method) at least every 7 years on the covered segment. An operator must use the results of each survey as part of an overall evaluation of the cathodic protection and corrosion threat for the covered segment. This evaluation must consider, at minimum, the leak repair and inspection records, corrosion monitoring records, exposed pipe inspection records, and the pipeline environment. (2) Unprotected pipe or cathodically protected pipe where electrical surveys are impractical. If an electrical survey is impractical on the covered segment an operator must —

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(i) Conduct leakage surveys as required by §192.706 at 4-month intervals; and (ii) Every 18 months, identify and remediate areas of active corrosion by evaluating leak repair and inspection records, corrosion monitoring records, exposed pipe inspection records, and the pipeline environment. (c) Internal Corrosion. To address the threat of internal corrosion on a covered segment, an operator must — (1) Conduct a gas analysis for corrosive agents at least once each calendar year; (2) Conduct periodic testing of fluids removed from the segment. At least once each calendar year test the fluids removed from each storage field that may affect a covered segment; and (3) At least every seven (7) years, integrate data from the analysis and testing required by paragraphs (c)(1)- (c)(2) with applicable internal corrosion leak records, incident reports, safety- related condition reports, repair records, patrol records, exposed pipe reports, and test records, and define and implement appropriate remediation actions. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004 and Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004]

GUIDE MATERIAL


§192.943 When can an operator deviate from these reassessment intervals?


(a) Waiver from reassessment interval in limited situations. In the following limited instances, OPS may allow a waiver from a reassessment interval required by §192.939 if OPS finds a waiver would not be inconsistent with pipeline safety. (1) Lack of internal inspection tools. An operator who uses internal inspection as an assessment method may be able to justify a longer reassessment period for a covered segment if internal inspection tools are not available to assess the line pipe. To justify this, the operator must demonstrate that it cannot obtain the internal inspection tools within the required reassessment period and that the actions the operator is taking in the interim ensure the integrity of the covered segment. (2) Maintain product supply. An operator may be able to justify a longer reassessment period for a covered segment if the operator demonstrates that it cannot maintain local product supply if it conducts the reassessment within the required interval. (b) How to apply. If one of the conditions specified in paragraph (a)(1) or (a)(2) of this section applies, an operator may seek a waiver of the required reassessment interval. An operator must apply for a waiver in accordance with 49 U.S.C. 60118(c), at least 180 days before the end of the required reassessment interval, unless local product supply issues make the period impractical. If local product supply issues make the period impractical, an operator must apply for the waiver as soon as the need for the waiver becomes known. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004 and Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004]

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GUIDE MATERIAL 1 GENERAL OPS allows waivers in limited instances. A waiver is not required in the following situations. (a) When reassessment intervals established are more frequent than those required by §192.939. (b) Where an Integrity Management Program meets the criteria for exceptional performance in

§192.913. 2 CONDITIONS FOR A WAIVER A waiver can be requested under the following conditions. (a) Unavailability of internal inspection tools. Operators may consider a general contract provision with their internal inspection tool service

provider that requires written notification of tool availability. However, to support the request for waiver, an operator should consider obtaining documentation on the lack of availability from multiple vendors. This documentation might include the following.

(1) Request for Proposal (RFP). (2) Letters from vendors. (3) Timeline of activities. (b) Inability to maintain supply. An operator should consider submitting documentation substantiating the basis and possible

duration that local gas supply cannot be maintained. Documentation might include the following. (1) Operational flow control notifications from an upstream pipeline operator. (2) Supply nominations. (3) SCADA system data (i.e., flow rates and pressures). (4) Weather conditions. (5) Potential customer outages. (6) Upstream service interruptions. (7) Natural disasters. 3 WAIVER APPLICATIONS (a) Applications for a waiver can be made as follows. (1) From an interstate pipeline operator to OPS in accordance with 49 USC 60118(c) - Waivers

approved by Secretary. (2) From an intrastate pipeline operator to its state authority in accordance with 49 USC 60118(d) -

Waivers approved by State Authorities. If the state does not have a current pipeline program certification, the operator applies to OPS in accordance with 49 USC 60118(c).

(b) The application should include the following. (1) Information about the pipeline segment and HCA involved. (2) Supporting documentation. (3) The date when an assessment will take place.

§192.945 What methods must an operator use to measure program effectiveness?


(a) General. An operator must include in its integrity management program methods to measure, on a semi-annual basis, whether the program is effective in assessing and evaluating the integrity of each covered pipeline segment and in protecting the high consequence areas. These measures must include the four overall performance measures specified in ASME/ANSI B31.8S

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(incorporated by reference, see §192.7), section 9.4, and the specific measures for each identified threat specified in ASME/ANSI B31.8S, Appendix A. An operator must submit the four overall performance measures, by electronic or other means, on a semi-annual frequency to OPS in accordance with § 192.951. An operator must submit its first report on overall performance measures by August 31, 2004. Thereafter, the performance measures must be complete through June 30 and December 31 of each year and must be submitted within 2 months after those dates. (b) External corrosion direct assessment. In addition to the general requirements for performance measures in paragraph (a) of this section, an operator using direct assessment to assess the external corrosion threat must define and monitor measures to determine the effectiveness of the ECDA process. These measures must meet the requirements of §192.925. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004 and Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004; Amdt. 192-103, 71 FR 33402, June 9, 2006]

GUIDE MATERIAL


§192.947 What records must an operator keep?


An operator must maintain, for the useful life of the pipeline, records that demonstrate compliance with the requirements of this subpart. At minimum, an operator must maintain the following records for review during an inspection. (a) A written integrity management program in accordance with §192.907; (b) Documents supporting the threat identification and risk assessment in accordance with §192.917; (c) A written baseline assessment plan in accordance with§192.919; (d) Documents to support any decision, analysis and process developed and used to implement and evaluate each element of the baseline assessment plan and integrity management program. Documents include those developed and used in support of any identification, calculation, amendment, modification, justification, deviation and determination made, and any action taken to implement and evaluate any of the program elements; (e) Documents that demonstrate personnel have the required training, including a description of the training program, in accordance with §192.915; (f) Schedule required by §192.933 that prioritizes the conditions found during an assessment for evaluation and remediation, including technical justifications for the schedule. (g) Documents to carry out the requirements in §§192.923 through 192.929 for a direct assessment plan; (h) Documents to carry out the requirements in §192.931 for confirmatory direct assessment; (i) Verification that an operator has provided any documentation or notification required by this subpart to be provided to OPS, and when applicable, a State authority with which OPS has an interstate agent agreement, and a State or local pipeline safety authority that regulates a covered pipeline segment within that State. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004 and Amdt. 192-95 Correction & Petition for Reconsideration, 69 FR 18228, Apr. 6, 2004]

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GUIDE MATERIAL 1 PROGRAM AND PROCESS RECORDS 1.1 General.

Operators should maintain, for the useful life of the pipeline, documents to support decisions, analyses, and processes related to development, implementation, and evaluation of the integrity management program.

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

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

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

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

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(a) Procedures for assessment methods. (b) Criteria for evaluating assessment results. (c) Tool selection criteria. (d) Forms or other documentation of field data. 4 REGULATORY CORRESPONDENCE

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

§192.949 How does an operator notify OPS?


An operator must provide any notification required by this subpart by — (1) Sending the notification to the Information Resources Manager, Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, Room 7128, 400 Seventh Street, SW., Washington, DC 20590; (2) Sending the notification to the Information Resources Manager by facsimile to (202) 366-7128; or (3) Entering the information directly on the Integrity Management Database (IMDB) web site at http://primis.rspa.dot.gov/gasimp/. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004; RIN 2137-AD77, 70 FR 11135, Mar. 8, 2005]

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

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

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

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

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

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

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

implemented. (3) How public safety will be maintained. 2 NOTIFICATION METHODS 2.1 Notification to OPS.

An operator should use only one notification option to OPS; that is, by mail, telefacsimile, or online submission. The website for online submission is http://primis.phmsa.dot.gov/gasimp.

2.2 Notification to state authorities.

Where OPS has an interstate agent agreement, or an intrastate covered segment is regulated by that state, an operator must also notify the state pipeline safety authority. A reference for state contacts is available at http://www.napsr.org.

3 REFERENCE

OPS Advisory Bulletin ADB-05-04 (70 FR 43939, July 29, 2005), accessible via the Federal Register (FR) at www.gpoaccess.gov/fr/advanced.html.

§192.951 Where does an operator file a report?

[Effective Date3-8-05]

An operator must send any performance report required by this subpart to the Information Resources Manager — (1) By mail to the Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, Room 7128, 400 Seventh Street S.W., Washington, DC 20590; (2) Via facsimile to (202) 366-7128; or (3) Through the online reporting system provided by OPS for electronic reporting available at the OPS Home Page at http://ops.dot.gov. [Issued by Amdt. 192-95, 68 FR 69778, Dec. 15, 2003 with Amdt. 192-95 Correction, 69 FR 2307, Jan 15, 2004; RIN 2137-AD77, 70 FR 11135, Mar. 8, 2005]

GUIDE MATERIAL 1 REQUIRED REPORTS See the following sections for information regarding specific reporting requirements. (a) Section 192.945, regarding performance measures. (b) Section 192.913, regarding additional performance measures for exceptional performance

programs. (c) Sections 192.913 and 192.945 do not require reporting to state pipeline safety authorities.

However, intrastate operators should consider submitting a copy of the reports to their state authorities.

Addendum No. 6, September 2006 262(au) Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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2 REPORTING METHOD An operator should use only one reporting option to OPS; that is, by mail, via facsimile, or by going online electronically. Use the website listed in §192.949 to obtain the current mailing address or facsimile telephone number for notifications.

Addendum No. 6, September 2006 262(av) Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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GPTC GUIDE FOR GAS TRANSMISSION AND APPENDIX B DISTRIBUTION PIPING SYSTEMS: 2003 Edition PART 192

Appendix B to Part 192 Qualification of Pipe.


I. Listed Pipe Specifications API 5L—Steel pipe, ‘‘API Specification for Line Pipe’’ (incorporated by reference, see §192.7). ASTM A53/A53M—Steel pipe, ‘‘Standard Specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated, Welded and Seamless’’ (incorporated by reference, see §192.7). ASTM A106—Steel pipe, ‘‘Standard Specification for Seamless Carbon Steel Pipe for High- Temperature Service’’ (incorporated by reference, see §192.7). ASTM A333/A333M—Steel pipe, ‘‘Standard Specification for Seamless and Welded Steel Pipe for Low Temperature Service’’ (incorporated by reference, see §192.7). ASTM A381—Steel pipe, ‘‘Standard Specification for Metal-Arc-Welded Steel Pipe for Use with High- Pressure Transmission Systems’’ (incorporated by reference, see §192.7). ASTM A671—Steel pipe, ‘‘Standard Specification for Electric-Fusion-Welded [Steel] Pipe for Atmospheric and Lower Temperatures’’ (incorporated by reference, see §192.7). ASTM A672—Steel pipe, ‘‘Standard Specification for Electric-Fusion-Welded Steel Pipe for High- Pressure Service at Moderate Temperatures’’ (incorporated by reference, see §192.7). ASTM A691—Steel pipe, ‘‘Standard Specification for Carbon and Alloy Steel Pipe, Electric-Fusion-

Welded for High-Pressure Service at High Temperatures’’ (incorporated by reference, see §192.7).

ASTM D2513—Thermoplastic pipe and tubing, ‘‘Standard Specification for Thermoplastic Gas Pressure Pipe, Tubing, and Fittings’’ (incorporated by reference, see §192.7). ASTM D2517—Thermosetting plastic pipe and tubing, ‘‘Standard Specification for Reinforced Epoxy Resin Gas Pressure Pipe and Fittings’’ (incorporated by reference, see §192.7). II. Steel Pipe of Unknown or Unlisted Specification A. Bending Properties. For pipe 2 inches (51 millimeters) or less in diameter, a length of pipe must be cold bent through at least 90 degrees around a cylindrical mandrel that has a diameter 12 times the diameter of the pipe, without developing cracks at any portion and without opening the longitudinal weld. For pipe more than 2 inches (51 millimeters) in diameter, the pipe must meet the requirements of the flattening tests set forth in ASTM A53, except that the number of tests must be at least equal to the minimum required in paragraph II-D of this appendix to determine yield strength. B. Weldability. A girth weld must be made in the pipe by a welder who is qualified under subpart E of this part. The weld must be made under the most severe conditions under which welding will be allowed in the field and by means of the same procedure that will be used in the field. On pipe more than 4 inches (102 millimeters) in diameter, at least one test weld must be made for each 100 lengths of pipe. On pipe 4 inches (102 millimeters) or less in diameter, at least one test weld must be made for each 400 lengths of pipe. The weld must be tested in accordance with API Standard 1104 (incorporated by reference, see §192.7). If the requirements of API Standard 1104 cannot be met, weldability may be established by making chemical tests for carbon and manganese, and proceeding in accordance with section IX of the ASME Boiler and Pressure Vessel Code (incorporated by reference, see §192.7). The same number of chemical tests must be made as are required for testing a girth weld. C. Inspection. The pipe must be clean enough to permit adequate inspection. It must be visually inspected to ensure that it is reasonably round and straight and there are no defects which might impair the strength or tightness of the pipe.



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D. Tensile Properties. If the tensile properties of the pipe are not known, the minimum yield strength may be taken as 24,000 p.s.i. (165 MPa) or less, or the tensile properties may be established by performing tensile tests as set forth in API Specification 5L (incorporated by reference, see §192.7). All test specimens shall be selected at random and the following number of tests must be performed: Number of Tensile Tests - All Sizes

10 lengths or less 1 set of tests for each length.

11 to 100 lengths 1 set of tests for each 5 lengths, but not less than 10 tests.

Over 100 lengths 1 set of tests for each 10 lengths, but not less than 20 tests.

If the yield-tensile ratio, based on the properties determined by those tests, exceeds 0.85, the pipe may be used only as provided in §192.55(c). III. Steel pipe manufactured before November 12, 1970, to earlier editions of listed specifications. Steel pipe manufactured before November 12, 1970, in accordance with a specification of which a later edition is listed in section I of this Appendix, is qualified for use under this part if the following requirements are met: A. Inspection. The pipe must be clean enough to permit adequate inspection. It must be visually inspected to ensure that it is reasonably round and straight and that there are no defects which might impair the strength or tightness of the pipe. B. Similarity of specification requirements. The edition of the listed specification under which the pipe was manufactured must have substantially the same requirements with respect to the following properties as a later edition of that specification listed in section I of this Appendix: (1) Physical (mechanical) properties of pipe, including yield and tensile strength, elongation, and yield to tensile ratio, and testing requirements to verify those properties. (2) Chemical properties of pipe and testing requirements to verify those properties. C. Inspection or test of welded pipe. On pipe with welded seams, one of the following requirements must be met: (1) The edition of the listed specification to which the pipe was manufactured must have substantially the same requirements with respect to nondestructive inspection of welded seams and the standards for acceptance or rejection and repair as a later edition of the specification listed in section I of this Appendix. (2) The pipe must be tested in accordance with subpart J of this part to at least 1.25 times the maximum allowable operating pressure if it is to be installed in a Class 1 location and to at least 1.5 times the maximum allowable operating pressure if it is to be installed in a Class 2, 3, or 4 location. Notwithstanding any shorter time period permitted under subpart J of this part, the test pressure must be maintained for at least 8 hours. [Amdt. 192-3, 35 FR 17659, Nov. 17, 1970; Amdt. 192-12, 38 FR 4760, Feb. 22, 1973; Amdt. 192-19, 40 FR 10471, Mar. 6, 1975; Amdt. 192-22, 41 FR 13589, Mar. 31, 1976; Amdt. 192-32, 43 FR 18553, May 1, 1978; Amdt. 192-37, 46 FR 10157, Feb. 2, 1981; Amdt. 192-41, 47 FR 41381, Sept. 20, 1982; Amdt. 192-51, 51 FR 15333, Apr. 23, 1986; Amdt. 192-61, 53 FR 36793, Sept. 22, 1988; Amdt. 192-62, 54 FR 5625, Feb. 6, 1989; Amdt. 192-65, 54 FR 32344, Aug. 7, 1989; Amdt. 192-68, 58 FR 14519, Mar. 18, 1993; Amdt. 192-76 Correction, 61 FR 36825, July 15, 1996; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-94, 69 FR 32886, June 14, 2004 with Amdt. 192-94 Correction, 69 FR 54591, Sept. 9, 2004;



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Amdt. 192-103, 71 FR 33402, June 9, 2006]

GUIDE MATERIAL

This guide material is under review following Amendment 192-94. For the specified minimum yield strength of various grades of steel pipe covered by Part 192 and specifications listed in Section I of Appendix B to Part 192, see Guide Material Appendix G-192-2.



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Reserved



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INSTRUCTIONS FOR COMPLETING FORM PHMSA F 7100.1-1

ANNUAL REPORT FOR CALENDAR YEAR 2005 GAS DISTRIBUTION SYSTEM

GasDistAnnualInstructions 122005 Final 7100 1-1.doc 1

All references are to Title 49 of the Code of Federal Regulations. Reporting requirements are contained in Part 191, “Transportation of Natural and Other Gas by Pipeline; Annual Reports, Incident Reports and Safety Related Condition Reports.” Except as provided in §191.11(b), each operator of a natural gas distribution line (see definitions below) must submit an annual report Form PHMSA F 7100.1-1 for the preceding calendar year not later than March 15th. Be sure to report TOTAL miles of main pipeline and services in the system at the end of the reporting year, including additions to the system during the year. The annual reporting period is on a calendar basis ending on December 31st of each year. Reports for intrastate pipelines subject to the jurisdiction of a State agency pursuant to certification under 49 U.S.C. § 60105 may be submitted in duplicate to the State agency if the regulations of that agency require the submission of these reports and provide for further transmittal of one copy not later than March 15th to the Information Resources Manager, Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, Department of Transportation, 400 7th Street, S.W., Room 2103, PHP-10, Washington, DC 20590. Use one of the following methods to submit your report. We prefer online reporting over hardcopy submissions. If you prefer, then you can mail or fax your completed reports to DOT/PHMSA. Methods:

1. Online: a. Navigate to the OPS Home Page http://ops.dot.gov, click the ONLINE DATA

ENTRY box at the top right corner of the screen b. Click on the Annual Gas Distribution Systems Report name c. Enter Operator ID and PIN d. Click add to begin e. Click submit when finished. NOTE: For supplemental reports use steps 1a and 1b

then click on the report ID to make corrections. Click save when finished. f. A confirmation page will appear for you to print and save for your records

If you do file online, please do not mail or fax the completed report to DOT as this may cause data entry errors.

2. Mail to: DOT/PHMSA Office of Pipeline Safety Information Resources Manager, 400 7th Street SW Room 2103, PHP-10 Washington, DC 20590

3. Fax to: Information Resources Manager at (202) 366-4566.



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IMPORTANT: The Form PHMSA F 7100.1-1 has three total columns added to the form that we revised this year:

1) Part B- System Description Section 1 now has a Total column” for summarizing rows, 2) Part B- System Description Section 2 now has a Total column” for summarizing rows, 3) Part B- System Description Section 3 now has a Total column” for summarizing rows.

If you need copies of the Form PHMSA F 7100.1-1 and/or instructions they can be found on the Office of Pipeline Safety home page, http://ops.dot.gov, by clicking the FORMS tab or OPS FORMS section of the ONLINE LIBRARY. If you have questions about this report or these instructions, please call (202)366-8861 or (202)366-8075. Please type or print all entries when submitting forms by mail.

GENERAL INSTRUCTIONS

The following definitions are from § 192.3:

1. “Distribution line” means a pipeline other than a gathering or transmission line.

2. “Gathering line” means a pipeline that transports gas from a current production facility to a transmission line or main.

3. “Transmission line” means a pipeline, other than a gathering line, that: a. Transports gas from a gathering line or storage facility to a distribution center,

storage facility, or large volume customer that is not downstream from a distribution center;

b. Operates at a hoop stress of 20 percent or more of SMYS; or c. Transports gas within a storage field. A large volume customer may receive similar

volumes of gas as a distribution center, and includes factories, power plants, and institutional users of gas.

4. “Operator” means a person who engages in the transportation of gas.

Make an entry in each block for which data are available. Estimate data if necessary. Avoid entering mileage in the UNKNOWN columns, if possible. Some companies may have very old pipe for which installation records do not exist. Estimate the total of such mileage in the UNKNOWN section of item 4: “Miles of Main and Number of Services by Decade of Installation.” Please round all mileage to the nearest 3 decimal positions. DO NOT USE FRACTIONS. Examples of rounding are as follows: 3/8 should round to 0.375; 3/4 should round to 0.75 and ½ should round to 0.5. The total miles of main and services reported in Part B sections 1 through 4 MUST all sum to the same totals in the appropriate rows. Please do not to report miles of main in feet. If necessary, please convert feet into a decimal notation (e.g. 1,320 feet = .25 miles).

SPECIFIC INSTRUCTIONS



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Enter the Calendar Year for which the report is being filed. Check Initial Report if this is the original filing for this calendar year. Check Supplemental Report if this is a follow-up to a previously filed report to amend or correct information. On Supplemental Reports, please complete Part A and only amended, revised, or added information for Parts B, C, D, E and F.

PART A – OPERATOR INFORMATION The operator's five digit identification number appears on the PHMSA mailing label (without leading zeroes when less than 10000). If the person completing the report does not have the operator identification number, they should contact the Information Resources Manager or PHMSA at (202) 366-8075 for the five-digit operator identification number. Provide the address where you would like PHMSA to mail forms and the phone number where PHMSA can contact you regarding this report. The Pipeline and Hazardous Materials Safety Administration assigns the operator’s five-digit identification number. Contact PHMSA at (202) 366-8075 if you need assistance with determining your operator’s five-digit identification number. Enter the State for which information is being reported. Submit a separate report for each State in which the company operates a gas distribution pipeline system.

PART B – SYSTEM DESCRIPTION “Coated” means pipe coated with any effective hot or cold applied dielectric coating or wrapper. “PVC” means polyvinyl chloride plastic. “PE” means polyethylene plastic. “ABS” means acrylonitrile-butadiene-styrene plastic. “Cathodically protected” applies to both “bare” and “coated.” “Other” means a pipe of any material not specifically designated on the form. If you check “other pipe,” describe it in Part F. “Number of services” is the number of service lines, not the number of customers served. Provide miles of main and numbers of services by decade installed in Part B, section 4. If you do not know the decade of installation of the pipe because there are no records containing such information, enter an estimate in the UNKNOWN column. The sum total of mileage and numbers of services reported for Part B, section 4 should match total mileage and numbers of services reported in sections 1, 2, and 3 in Part B.

PART C – TOTAL LEAKS ELIMINATED/REPAIRED DURING YEAR



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A leak is defined as an unintentional escape of gas from the pipeline. A non-hazardous release that can be eliminated by lubrication, adjustment, or tightening, is not a leak. Include all leaks eliminated by repair, replacement or other reason during the reporting year. Also include leaks reported on form PHMSA 7100.1, “Incident Report Gas Distribution Systems.” A reportable incident is one described in §191.3. Do not include test failures. Leaks are classified as: CORROSION: leak resulting from a hole in the pipe or other component that galvanic, bacterial, chemical, stray current, or other corrosive action causes. NATURAL FORCES: leak resulting from earth movements, earthquakes, landslides, subsidence, lightning, heavy rains/floods, washouts, flotation, mudslide, scouring, temperature, frost heave, frozen components, high winds, or similar natural causes. EXCAVATION: leak resulting from damage caused by earth moving or other equipment, tools, or vehicles. Include leaks from damage by operator's personnel or contractor or people not associated with the operator. OTHER OUTSIDE FORCE DAMAGE: Include leaks caused by fire or explosion and deliberate or willful acts, such as vandalism. MATERIAL AND WELDS: leak resulting from failure of original sound material from force applied during construction that caused a dent, gouge, excessive stress, or other defect that eventually resulted in a leak. This includes leaks due to faulty wrinkle bends, faulty field welds, and damage sustained in transportation to the construction or fabrication site. Also include leak resulting from a defect in the pipe material, component, or the longitudinal weld or seam due to faulty manufacturing procedures. Leaks from material deterioration, other then corrosion, after exceeding the reasonable service life, are reported under Other. EQUIPMENT AND OPERATIONS: leak resulting from malfunction of control/relief equipment including valves, regulators, or other instrumentation; stripped threads or broken pipe couplings on nipples, valves, or mechanical couplings; or seal failures on gaskets, O-rings, seal/pump packing, or similar leaks. Also include leaks resulting from inadequate procedures or safety practices, or failure to follow correct procedures, or other operator error. OTHER: leak resulting from any other cause, such as exceeding the service life, not attributable to the above causes.

PART D – TOTAL NUMBER OF LEAKS ON FEDERAL LAND REPAIRED/ELIMINATED OR SCHEDULED FOR REPAIR

Federal Lands: As defined in 30 U.S.C. §185, federal lands means “all lands owned by the United States except lands in the National Park System, lands held in trust for an Indian or Indian tribe, and



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lands on the Outer Continental Shelf.” Indicate only those leaks repaired, eliminated, or scheduled for repair during the reporting year, including those incidents reported on Form PHMSA F 7100.1.

PART E – PERCENT OF UNACCOUNTABLE FOR GAS “Unaccounted for gas” is gas lost; that is, gas that the operator cannot account for as usage or through appropriate adjustment. Adjustments are appropriately made for such factors as variations in temperature, pressure, meter-reading cycles, or heat content; calculable losses from construction, purging, line breaks, etc., where specific data are available to allow reasonable calculation or estimate; or other similar factors. State the amount of unaccounted for gas as a percent of total input for the 12 months ending June 30 of the reporting year. [(Purchased gas + produced gas) minus (customer use + company use + appropriate adjustments)] divided by (purchased gas + produced gas) equals percent unaccounted for. Do not report “gained” gas. If a net gain of gas is indicated by the calculations, report “0%” here. (Decimal or fractional percentages may be entered.)

PART F – ADDITIONAL INFORMATION

Include any additional information which will assist in clarifying or classifying the reported data.

PART G - PREPARER AND AUTHORIZED SIGNATURE PREPARER is the name of the person most knowledgeable about the report or the person to be contacted for more information. Please include the direct phone number and email address. AUTHORIZED SIGNATURE may be the preparer, an officer, or other person whom the operator has designated to review and sign reports. Please include the direct phone number and email address. If submitting via the Online Data Entry System your Operator ID and PIN take the place of the Authorized Signature.



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Blank Sheet



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Notice: This report is required by 49 CFR Part 191. Failure to report can result in a civil penalty not to exceed $1,000 for each violation Form Approved for each day that such violation persists except that the maximum civil penalty shall not exceed $200,000 as provided in 49 USC 1678. OMB No. 2137-0522

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

ANNUAL REPORT FOR CALENDAR YEAR 20___ GAS TRANSMISSION & GATHERING SYSTEMS

INITIAL REPORT SUPPLEMENTAL REPORT

INSTRUCTIONS Important: Please read the separate instructions for completing this form before you begin. They clarify the information

requested and provide specific examples. If you do not have a copy of the instructions, you can obtain one from the Office of Pipeline Safety Web Page at http://ops.dot.gov.

PART A - OPERATOR INFORMATION DOT USE ONLY

1. NAME AND COMPANY OR ESTABLISHMENT

4. OPERATOR'S 5 DIGIT IDENTIFICATION NUMBER / / / / / /

2. LOCATION OF OFFICE WHERE ADDITIONAL INFORMATION MAY BE OBTAINED

5. HEADQUARTERS NAME & ADDRESS, IF DIFFERENT

Number & Street Number & Street City & County City & County State & Zip Code State & Zip Code 3. STATE IN WHICH SYSTEM OPERATES: / / / (provide a separate report for each state in which system operates) PART B - SYSTEM DESCRIPTION Report miles of pipeline in system at end of year.

1. GENERAL - MILES OF PIPELINE IN THE SYSTEM AT END OF YEAR THAT ARE JURISDICTIONAL TO OPS STEEL CATHODICALLY

PROTECTED UNPROTECTED CAST IRON WROUGHT IRON PIPE

PLASTIC PIPE OTHER PIPE TOTAL

BARE COATED BARE COATED TRANSMISSION ONSHORE OFFSHORE GATHERING ONSHORE OFFSHORE SYSTEM TOTALS

2. MILES OF PIPE BY NOMINAL SIZE UNKNOWN 4” OR

LESS OVER 4” THRU 10”

OVER 10” THRU 20”

OVER 20” THRU 28”

OVER 28” TOTAL

TRANSMISSION ONSHORE OFFSHORE GATHERING ONSHORE OFFSHORE SYSTEM TOTALS

3. MILES OF PIPE BY DECADE OF INSTALLATION UNKNOWN PRE-

1940 1940-1949

1950-1959

1960-1969

1970-1979

1980-1989

1990-1999

2000-2009 TOTAL

TRANSMISSION ONSHORE OFFSHORE GATHERING ONSHORE OFFSHORE SYSTEM TOTALS

4. MILES OF PIPE BY CLASS LOCATION CLASS 1 CLASS 2 CLASS 3 CLASS 4 TOTAL TRANSMISSION ONSHORE OFFSHORE N/A N/A N/A GATHERING ONSHORE OFFSHORE N/A N/A N/A SYSTEM TOTALS Form PHMSA F 7100.2-1 (12/05) Continue on Next Page

Reproduction of this form is permitted.



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PART C – TOTAL LEAKS ELIMINATED/REPAIRED DURING YEAR

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

TRANSMISSION GATHERING CAUSE OF

LEAK ONSHORE OFFSHORE ONSHORE OFFSHORE 1. TRANSMISSION

CORROSION ONSHORE

NATURAL FORCES

OFFSHORE

EXCAVATION OUTER CONTINENTAL SHELF

OTHER OUTSIDE FORCE DAMAGE

2. GATHERING

MATERIAL AND WELDS

ONSHORE

EQUIPMENT AND OPERATIONS

OFFSHORE

OTHER OUTER CONTINENTAL SHELF

PART E - NUMBER OF KNOWN SYSTEM LEAKS AT END OF YEAR SCHEDULED FOR REPAIR

1. TRANSMISSION

2. GATHERING

PART F - PREPARER AND AUTHORIZED SIGNATURE

(type or print) Preparer's Name and Title

Area Code and Telephone Number

Preparer's E-mail Address

Area Code and Facsimile Number

Name and Title of Person Signing Authorized Signature (type or print) Name and Title

Date

Area Code and Telephone Number

Form PHMSA F 7100.2-1 (12/05)



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GasTransAnnualInstructions 122005 Final 7100 2-1.doc 1

INSTRUCTIONS FOR COMPLETING FORM PHMSA F 7100.2-1 (Rev.12/05) ANNUAL REPORT FOR CALENDAR YEAR 2005

GAS TRANSMISSION AND GATHERING SYSTEMS

GENERAL INSTRUCTIONS Reporting requirements are in Part 191 of Title 49 of the Code of Federal Regulations (CFR) Transportation of Natural and Other Gas by Pipeline: Annual Reports, Incident Reports, and Safety-Related Condition Reports. Annual reports must be submitted by March 15th for the preceding calendar year. Report TOTAL miles of pipeline in the system at the end of the reporting year, including additions to the system during that year. Please note that Operators operating less than one (1) mile of pipeline are not required to file an annual report. Each transmission system or non-rural gathering system operator is required to file an annual report. The terms operator, distribution line, gathering line, and transmission line are defined in '192.3 of the CFR. If an operator determines that pipelines fall under the definition for distribution lines, he or she should follow the instructions for Form PHMSA F 7100.1-1. Use one of the following methods to submit your report. We prefer online reporting over hardcopy submissions. If you prefer, then you can mail or fax your completed reports to DOT/PHMSA. Methods:

1. Online: a. Navigate to the OPS Home Page http://ops.dot.gov, click the ONLINE DATA

ENTRY box at the top right corner of the screen b. Click on the Annual Gas Transmission and Gathering Systems Report name c. Enter Operator ID and PIN d. Click add to begin e. Click submit when finished. NOTE: For supplemental reports use steps 1a and

1b then click on the report ID to make corrections. Click save when finished. f. A confirmation page will appear for you to print and save for your records

If you do file online, please do not mail or fax the completed report to DOT as this may cause data entry errors.

2. Mail to: DOT/PHMSA Office of Pipeline Safety Information Resources Manager, 400 7th Street SW Room 2103, PHP-10 Washington, DC 20590

3. Fax to: Information Resources Manager at (202) 366-4566.



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IMPORTANT: The Form PHMSA F 7100.2-1 has two total columns added to the form that we revised this year:

1) Part B- System Description Section 1 now has a Total column” for summarizing rows, 2) Part B- System Description Section 2 now has a Total column” for summarizing rows,

If you need copies of the Form PHMSA F 7100.2-1 and/or instructions they can be found on the Office of Pipeline Safety home page, http://ops.dot.gov, by clicking the FORMS tab or OPS FORMS section of the ONLINE LIBRARY. If you have questions about this report or these instructions, please call (202)366-8861 or (202)366-8075. Please type or print all entries when submitting forms by mail. Please round all mileage to the nearest 3 decimal positions. DO NOT USE FRACTIONS. Examples of rounding are as follows: 3/8 should round to 0.375; 3/4 should round to 0.75 and ½ should round to 0.5. The total mileage reported in Part B sections 1 through 4 MUST all sum to the same totals in the appropriate rows. Please do not to report miles of pipeline in feet. If necessary, please convert feet into a decimal notation (e.g. 1,320 feet = .25 miles). Make an entry in each block for which data is available. Estimate data if necessary. Please avoid entering mileage in the UNKNOWN columns where possible. We recognize that some companies may have very old pipe for which installation records may not exist. Enter estimate of the total of such mileage in the UNKNOWN section of item 3: “Miles of Pipe by Decade of Installation”.

SPECIFIC INSTRUCTIONS

Enter the Calendar Year for which the report is being filed. Check Initial Report if this is the original filing for this calendar year. Check Supplemental Report if this is a follow-up to a previously filed report to amend or correct information. On Supplemental Reports, please complete Part A and only amended, revised, or added information for Parts B, C, D and E.

PART A - OPERATOR INFORMATION Insert the operator name and address data. Report the address where additional information can be found. The operator's five digit identification number appears on the PHMSA mailing label (without leading zeroes when less than 10000). If the person completing the report does not have the operator identification number, they should contact the Information Resources Manager or PHMSA at (202) 366-8075 for the five-digit operator identification number. Enter the_State_for_which_information_is_being_reported. An operator should submit a separate report for all company transmission or non-rural gathering operations for each State in which it operates. A company may submit separate reports for subsidiaries or affiliate operations. Please do not report a pipeline facility more than once.



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http://ops.dot.gov.


PART B - SYSTEM DESCRIPTION The mileage of pipeline supplied in Part B, sections 1 and 2, will be used to better protect people and the environment. Mileage reported should accurately reflect miles of pipe meeting the PHMSA gas transmission and non-rural gathering line definitions. In the past, short segments of pipeline operated by distribution systems at less than 20 percent of the specified minimum yield strength (SMYS) have sometimes been inaccurately reported as transmission lines. Please carefully consider all reported pipelines classifications. COATED means pipe coated with an effective hot or cold applied dielectric coating or wrapper. OTHER PIPE means a pipe made of material not specifically designated on the form, such as copper, aluminum, etc. Enter the Other Pipe material, either in the column heading or by an attachment if mileage of Other Pipe is shown. Include Outer Continental Shelf pipelines under offshore in Part B, sections No. 1 and No. 2. Provide miles of pipe by decade installed in Part B, section 3. Estimate if exact totals aren’t known. Where decade of installation is not known because records do not exist for such information, enter an estimate of this mileage in the UNKNOWN column. The sum total of mileage reported for Part B, section 3 should match total mileage reported in Part B sections 1, 2, and 4. Provide miles of pipe by class location in Part B, section 4. Class location is defined in 49 Code of Federal Regulations (CFR) Part '192.5. These definitions are provided in Appendix A, below. All offshore mileage is Class 1.

PART C - TOTAL LEAKS ELIMINATED/REPAIRED DURING YEAR Include all reportable leaks or ruptures and non-reportable leaks or ruptures repaired or eliminated including replaced pipe or other component during the calendar year. Do not include test failures. Leaks are unintentional escapes of gas from the pipeline. A non-hazardous release that can be eliminated by lubrication, adjustment, or tightening is not a leak. A reportable leak is one that meets the specific criteria of '191.5 and is reported on Form PHMSA F 7100.2, Incident Report - Gas Transmission and Gathering Systems. A non-reportable leak is one that is not reported under '191.5. Leaks are classified as: CORROSION: leak resulting from a hole in the pipe or other component that galvanic, bacterial, chemical, stray current, or other corrosive action causes. NATURAL FORCES: leak resulting from earth movements, earthquakes, landslides, subsidence, lightning, heavy rains/floods, washouts, flotation, mudslide, scouring, temperature,



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frost heave, frozen components, high winds, or similar natural causes. EXCAVATION: leak resulting from damage caused by earth moving or other equipment, tools, or vehicles. Include leaks from damage by operator's personnel or contractor or people not associated with the operator. OTHER OUTSIDE FORCE DAMAGE: Include leaks caused by fire or explosion and deliberate or willful acts, such as vandalism. MATERIAL AND WELDS: leak resulting from failure of original sound material from force applied during construction that caused a dent, gouge, excessive stress, or other defect that eventually resulted in a leak. This includes leaks due to faulty wrinkle bends, faulty field welds, and damage sustained in transportation to the construction or fabrication site. Also include leak resulting from a defect in the pipe material, component, or the longitudinal weld or seam due to faulty manufacturing procedures. Leaks from material deterioration, other then corrosion, after exceeding the reasonable service life, are reported under Other. EQUIPMENT AND OPERATIONS: leak resulting from malfunction of control/relief equipment including valves, regulators, or other instrumentation; stripped threads or broken pipe couplings on nipples, valves, or mechanical couplings; or seal failures on gaskets, O-rings, seal/pump packing, or similar leaks. Also include leaks resulting from inadequate procedures or safety practices, or failure to follow correct procedures, or other operator error. OTHER: leak resulting from any other cause, such as exceeding the service life, not attributable to the above causes. OFFSHORE includes jurisdictional pipelines on the Outer Continental Shelf.

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

FEDERAL LANDS means All lands owned by the United States except lands in the National Park System, lands held in trust for an Indian or Indian tribe, and lands on the Outer Continental Shelf.", as defined in 30 USC Section 185. Enter all leaks repaired, eliminated, or scheduled for repair during the reporting year, including those reported as incidents on Form PHMSA F 7100.2. OUTER CONTINENTAL SHELF pipelines are separated to differentiate from other Federal offshore areas, which could be within a lake or river.

PART E - NUMBER OF KNOWN SYSTEM LEAKS AT END OF YEAR SCHEDULED FOR REPAIR

Include all known leaks scheduled for elimination by repairing or by replacing pipe or some other component.



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PART F - PREPARER AND AUTHORIZED SIGNATURE

PREPARER is the name of the person most knowledgeable about the report or the person to be contacted for more information. Please include the direct phone number and email address. AUTHORIZED SIGNATURE may be the preparer, an officer, or other person whom the operator has designated to review and sign reports. Please include the direct phone number and email address. If submitting via the Online Data Entry System your Operator ID and PIN take the place of the Authorized Signature.

APPENDIX A

Sec. '192.5 Class locations. (a) This section classifies pipeline locations for purposes of this part. The following criteria apply to classifications under this section. (1) A ``class location unit'' is an onshore area that extends 220 yards (200 meters) on either side of the centerline of any continuous 1- mile (1.6 kilometers) length of pipeline. (2) Each separate dwelling unit in a multiple dwelling unit building is counted as a separate building intended for human occupancy. (b) Except as provided in paragraph (c) of this section, pipeline locations are classified as follows: (1) A Class 1 location is: (i) An offshore area; or (ii) Any class location unit that has 10 or fewer buildings intended for human occupancy. (2) A Class 2 location is: (i) Any class location unit that has more than 10 but fewer than 46 buildings intended for human occupancy. (3) A Class 3 location is: (i) Any class location unit that has 46 or more buildings intended for human occupancy; or (ii) An area where the pipeline lies within 100 yards (91 meters) of either a building or a small, well-defined outside area (such as a playground, recreation area, outdoor theater, or other place of public assembly) that is occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12-month period. (The days and weeks need not be consecutive.) (4) A Class 4 location is any class location unit where buildings with four or more stories above ground are prevalent. (c) The length of Class locations 2, 3, and 4 may be adjusted as follows: (1) A Class 4 location ends 220 yards (200 meters) from the nearest building with four or more stories above ground. (2) When a cluster of buildings intended for human occupancy requires a Class 2 or 3 location, the class location ends 220 yards (200 meters) from the nearest building in the cluster.



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Blank Sheet



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GPTC GUIDE FOR GAS TRANSMISSION AND Guide Material Appendix G-192-1 DISTRIBUTION PIPING SYSTEMS: 2003 Edition

GUIDE MATERIAL APPENDIX G-192-1

SUMMARY OF REFERENCES AND RELATED SOURCES (Reorganized and updated for 2003 Edition, Addendum No. 2)

1 MATERIAL SPECIFICATIONS, CODES, STANDARDS, AND OTHER DOCUMENTS

The publications listed below provide information on pipe, components, specifications, and topics other than those covered currently or previously by Part 192. The list is intended to include all such publications referenced throughout the guide material. For some publication titles, certain initial words have been omitted for brevity, e.g., ASTM B 43, "Standard Specification for Seamless Red Brass Pipe, Standard Sizes" is presented here as "Seamless Red Brass Pipe, Standard Sizes." Under some conditions, the application of the information is limited by provisions of Part 192 and this Guide. See Editorial Conventions of the Guide for explanation of "Discontinued." Most material specifications, codes, standards, and many other documents have been developed and approved in accordance with American National Standards Institute (ANSI) procedures and typically carry added identification referencing ANSI. Such identification is not routinely shown in the Guide. The appropriate guide material section is listed for each publication where applicable. Unless otherwise noted, the publications listed below are the latest available editions.

1.1 PIPE - METALLIC

ANSI A21.52 Ductile – Iron Pipe, Centrifugally Cast for Gas (Discontinued)

§192.557

API RP 5LW Transportation of Line Pipe on Barges and Marine Vessels §192.65 §192.103

ASME I00396 History of Line Pipe Manufacturing in North America §192.3

ASTM A120 Pipe, Steel, Black and Hot-Dipped, Zinc-Coated (Galvanized) Welded and Seamless for Ordinary Uses (Discontinued - Withdrawn 1987)

ASTM A155 Electric-Fusion Welded Steel Pipe for High-Pressure Service (Discontinued - Withdrawn 1978 - and replaced by ASTM A 671)

ASTM B43 Seamless Red Brass Pipe, Standard Sizes

AWWA C101 Thickness Design of Cast Iron Pipe (Discontinued) §192.557

AWWA C150 Thickness Design of Ductile-Iron Pipe §192.557

1.2 PIPE - PLASTIC [See 1.11 Plastic Related]



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1.3 VALVES [See other related references under 1.4 Fittings-Flanged and 1.7 Fittings-Miscellaneous]

API Std 600 Bolted Bonnet Steel Gate Valves for Petroleum and Natural Gas Industries

§192.145

ASME B16.33 Manually Operated Metallic Gas Valves for Use in Gas Piping Systems Up to 125 psig (Sizes NPS ½ - NPS 2)

§192.145

ASME B16.34 Valves - Flanged, Threaded, and Welding End §192.145

ASME B16.38 Large Metallic Valves for Gas Distribution (Manually Operated, NPS 2½ to 12, 125 psig Max)

§192.145

1.4 FITTINGS - FLANGED

ASME B16.47 Large Diameter Steel Flanges (NPS 26 through NPS 60) §192.147

AWWA C207 Steel Pipe Flanges for Waterwork Service, Sizes 4 Inch Through 144 Inch

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

§192.147

1.5 FITTINGS - THREADED

ASME B16.3 Malleable Gray Iron Threaded Fittings §192.149

ASME B16.4 Gray Iron Threaded Fittings §192.149

ASME B16.14 Ferrous Pipe Plugs, Bushings and Locknuts with Pipe Threads

ASME B16.15 Cast Bronze Threaded Fittings, Classes 125 and 250 §192.149

1.6 FITTINGS - WELDED

ASME B16.9 Factory-Made Wrought Steel Buttwelding Fittings §192.149 App. G-192-3

ASME B16.25 Buttwelding Ends

ASME B16.28 Wrought Steel Buttwelding Short Radius Elbows and Returns

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

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

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



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1.7 FITTINGS - MISCELLANEOUS

ANSI A21.14 Ductile Iron Fittings, 3-Inch Through 24-Inch for Gas §192.557

ASME B16.11 Forged Fittings, Socket-Welding and Threaded §192.149 App.G-192-5

ASME B16.18 Cast Copper Alloy Solder Joint Pressure Fittings

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

ASME B16.36 Orifice Flanges

ASME B16.48 Steel Line Blanks

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

ASTM A105 Carbon Steel Forgings for Piping Applications

ASTM A181 Carbon Steel Forgings for General-Purpose Piping

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

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

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

§192.149

MSS SP-79 Socket-Welding Reducer Inserts §192.149

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

§192.149

1.8 BOLTS & GASKETS

AGA CPR-83-4-1 Threaded Fastener Torquing §192.147

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

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

§192.147

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

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

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

ASTM A193 Alloy Steel and Stainless Steel Bolting Materials for High-Temperature Service

§192.147

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

§192.147



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1.8 BOLTS & GASKETS (Continued)

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

ASTM A320 Alloy Steel Bolting Materials for Low-Temperature Service §192.147

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

§192.147

ASTM A449 Quenched and Tempered Steel Bolts and Studs §192.147

1.9 CORROSION RELATED

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

§192.53 §192.475

NACE RP0102 In-Line Inspection of Pipelines §192.150

NACE RP0169 Control of External Corrosion on Underground or Submerged Metallic Piping Systems

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

NACE RP0173 Collection and Identification of Corrosion Products (Discontinued)

§192.617

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

§192.475

NACE RP0177 Mitigation of Alternating Current and Lightning Effects on Metallic Structures and Corrosion Control Systems

§192.467

NACE RP0200 Steel-Cased Pipeline Practices §192.323 §192.467

NACE RP0274 High-Voltage Electrical Inspection of Pipeline Coatings §192.461

NACE RP0375 Wax Coating Systems for Underground Piping Systems §192.461

NACE 3D170 Technical Committee Report, Electrical and Electrochemical Methods for Determining Corrosion Rates (Discontinued)

§192.475

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

§192.150

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

§192.479



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1.10 DIMENSIONAL STANDARDS

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

ASME B1.20.1 Pipe Threads, General Purpose, Inch

ASME B1.20.3 Dryseal Pipe Threads, Inch

1.11 PLASTIC RELATED

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

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

App. G-192-21

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

§192.281

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

§192.281

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

§192.281

ASTM D2657 Heat Fusion Joining of Polyolefin Pipe and Fittings §192.281

ASTM D2837 Standard Test Method for Obtaining Hydrostatic Design Basis for Thermoplastic Pipe Materials or Pressure Design Basis for Thermoplastic Pipe Products

§192.3 §192.63 §192.121

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

§192.281

ASTM F689 Determination of the Temperature of Above-Ground Plastic Gas Pressure Pipe Within Metallic Casings

ASTM F1041 Guide for Squeeze-Off of Polyolefin Gas Pressure Pipe and Tubing

§192.321

ASTM F1290 Electrofusion Joining of Polyolefin Pipe and Fittings §192.281

ASTM F1563 Tools to Squeeze-Off Polyethylene (PE) Gas Pipe or Tubing

§192.321

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

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

§192.321

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

§192.123



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1.11 PLASTIC RELATED (Continued)

PPI - Handbook of PE Pipe

Above Ground Applications for Polyethylene Pipe Note: Available as individual chapter of the PPI Handbook of Polyethylene Pipe

§192.321 App. G-192-21

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

§192.281 §192.283

PPI TR-4 PPI Listing of Hydrostatic Design Basis (HDB), Strength Design Basis (SDB), Pressure Design Basis (PDB) and Minimum Required Strength (MRS) Ratings for Thermoplastic Piping Materials or Pipe

§192.121

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

§192.123

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

§192.121 §192.123

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

§192.281 §192.283

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

§192.281 §192.283

PPI Tech. Comm. Project 141

Standard Practice for Electrofusion Joining Polyolefin Pipe and Fittings

§192.281

1.12 PRESSURE & FLOW DEVICES

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

§192.201

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

§192.743

ASTM F1802 Test Method for Performance Testing of Excess Flow Valves

§192.381

MSS SP-115 Excess Flow Valves for Natural Gas Service §192.381

NBBI Relieving Capacities of Safety Valves and Relief Valves Approved by the National Board (Discontinued)

§192.201

1.13 STRUCTURAL STEEL & SUPPORTS

ASTM A36 Carbon Structural Steel

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

§192.357

MSS SP-69 Pipe Hangers and Supports - Selection and Application §192.357



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1.14 OTHER DOCUMENTS

AGA X69804 Historical Collection of Natural Gas Pipeline Safety Regulations

Forward Editorial Notes

AGA XF0277 Classification of Gas Utility Areas for Electrical Installations §192.163

AGA XK0101 Purging Principles and Practice §192.629 §192.727

AGA XL8920 Attention Prioritizing and Pipe Replacement/Renewal Decisions

§192.457 §192.703

App. G-192-18

AGA XQ0005 Odorization Manual §192.625

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

§192.163

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

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

APWA Excavator's Damage Prevention Guide and One-Call Systems International Directory (includes Uniform Color Code)

§192.614

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

App. G-192-15

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

§192.103

ASME B31.1 Power Piping §192.141

ASME B31.2 Fuel Gas Piping

ASME B31.3 Process Piping §192.141

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

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

ASME B31.9 Building Services Piping

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

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

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

ASTM E84 Test Method for Surface Burning Characteristics of Building Materials

§192.163



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1.14 OTHER DOCUMENTS (Continued)

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

CoGDEM Gas Detection and Calibration Guide App. G-192-11 App. G-192-11A

GPTC-Z380-TR-1 Review of Integrity Management for Natural Gas Transmission Pipelines

§192.907

GRI-91/0283 Guidelines for Pipelines Crossing Railroads §192.103 App. G-192-15

GRI-91/0284 Guidelines for Pipelines Crossing Highways §192.103 App. G-192-15

GRI-91/0285 Technical Summary and Database for Guidelines for Pipelines Crossing Railroads and Highways

App. G-192-15

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

App. G-192-15

IAPMO Uniform Plumbing Code §192.141

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

App. G-192-13

NFPA 10 Portable Fire Extinguishers

NFPA 14 Installation of Standpipe and Hose Systems §192.141

NFPA 24 Installation of Private Fire Service Mains and Their Appurtenances

§192.141

NFPA 54/ANSI Z223.1 National Fuel Gas Code Fig. 192.11A Fig. 192.11B

NFPA 220 Types of Building Construction

NFPA 224 Homes and Camps in Forest Areas (Discontinued) §192.163

NFPA 921 Guide for Fire and Explosion Investigations §192.617

PRCI L22279 Further Studies of Two Methods for Repairing Defects in Line Pipe

§192.713

PRCI L51406 Pipeline Response to Buried Explosive Detonations App. G-192-16

PRCI L51574 Non-Conventional Means for Monitoring Pipelines in Areas of Soil Subsidence or Soil Movement

App. G-192-13

PRCI L51717 Pipeline In-Service Relocation Engineering Manual §192.703



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1.14 OTHER DOCUMENTS (Continued)

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

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

App. G-192-15

UL 723 Test for Surface Burning Characteristics of Building Materials

§192.163

2 GOVERNMENTAL DOCUMENTS

NTSB Report PAB-98-02

Pipeline Accident Brief -- Fire and Explosion, Midwest Gas Company, Waterloo, Iowa, October 17, 1994

§192.613

NTSB Report SIR-98-01

Special Investigation Report -- Brittle-Like Cracking in Plastic Pipe for Gas Service

§192.613

OPS Common Ground -- Study of One-Call Systems and Damage Prevention Best Practices, August 1999

§192.614

OPS ADB-99-01 Advisory Bulletin -- Susceptibility of Certain Polyethylene Pipe Manufactured by Century Utility Products, Inc. to Premature Failure Due to Brittle-Like Cracking (64 FR 12211, Mar. 11, 1999)

§192.613

OPS ADB-99-02 Advisory Bulletin -- Potential Susceptibility of Plastic Pipe Installed Between the [Years] 1960 and the Early 1980s to Premature Failure Due to Brittle-Like Cracking (64 FR 12212, Mar. 11, 1999)

§192.613

OPS ADB-02-06 Advisory Bulletin -- Definition of Onshore Gas Gathering Lines (67 FR 64447, Oct. 18, 2002)

§192.9

OPS ADB-02-07 Advisory Bulletin -- Notification of the Susceptibility to Premature Brittle-Like Cracking of Older Plastic Pipe (67 FR 70806, Nov. 26, 2002 with Correction, 67 FR 72027, Dec. 3, 2002)

§192.613

OPS ADB-04-01 Advisory Bulletin -- Hazards Associated with De-Watering of Pipelines (69 FR 58225, Sept. 29, 2004)

§192.515

OPS ADB-05-04 Advisory Bulletin - Notification Required by the Integrity Management Regulations in 49 CFR Part 192, Subpart O (70 FR 43939, July 29, 2005)

§192.949

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

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

§192.1



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3 TECHNICAL PAPERS & PUBLICATIONS

3.1 EMERGENCY RELATED

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

§192.617

"How to Protect the Company at the Scene of an Incident" by Robert E. Kennedy, Director of Claims, Claim & Security Department, The Brooklyn Union Gas Company; AGA Operating Section Proceedings - 1983.

§192.617

3.2 PLASTIC RELATED

“An Evaluation of Polyamide 11 for Use in High Pressure/High Temperature Gas Piping Systems,” T.J. Pitzi et al., 15th Plastic Fuel Gas Pipe Symposium Proceedings - 1997, p. 107.

§192.123

"Correlating Aldyl 'A' and Century PE Pipe Rate Process Method Projections With Actual Field Performance," E.F. Palermo, Ph.D., Plastics Pipes XII Conference, April 2004.

§192.613

“Mechanical Integrity of Fusion Joints Made from Polyethylene Pipe Exposed to Heavy Hydrocarbons,” S.M. Pimputkar, 14th Plastic Fuel Gas Pipe Symposium Proceedings - 1995, p. 141.

§192.123

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

§192.123

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

§192.123

“Strength of Fusion Joints Made from Polyethylene Pipe Exposed to Heavy Hydrocarbons,” S.M. Pimputkar, 15th Plastic Fuel Gas Pipe Symposium Proceedings - 1997, p. 309.

§192.123

3.3 UNCASED PIPE AND DIRECTIONAL DRILLING RELATED "Drilling Fluids in Pipeline Installation by Horizontal Directional Drilling - A Practical Applications Manual," J.D. Hair & Associates, Inc., Cebo Holland B.V., 1994.

App. G-192-15A

"Guidelines For A Successful Directional Crossing Bid Package," 1996 Directory of the North American Trenchless Technology Contractors.

App. G-192-15A

"Installation of Pipelines by Horizontal Directional Drilling, An Engineering Design Guide, " Prepared for the Offshore and Onshore Design Applications Supervisory Committee, of the PRCI, at the American Gas Association, J.D. Hair and Associates, Louis J. Cappozzolli and Associates, Inc., Stress Engineering Services, Inc., January 15, 1995.

App. G-192-15A

"Measurement Techniques in Horizontal Directional Drilling," Ir. J. Gorter, N.V. Nederlandse Gasunie, The Netherlands, February 1993.

App. G-192-15A

"Piping Handbook," Fourth Edition, J.H. Walker and Sabin Crocker, 1930, McGraw-Hill Inc., New York, NY; data re-affirmed in Sixth Edition, published 1992.

App. G-192-15

3.4 SAFETY AND INTEGRITY MANAGEMENT RELATED

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

§192.907



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4 PUBLISHING ORGANIZATIONS The specifications, codes, standards, and other documents listed in Sections 1 and 2 are published by

the following organizations: AGA American Gas Association 400 North Capitol Street, NW Publications: Washington, DC 20001 See Techstreet Phone: 202/824-7000 FAX: 202/824-7115 On line: www.aga.org ANSI American National Standards Institute 25 West 43rd Street New York, NY 10036 Phone: 212/642-4900 FAX: 212/302-1286 On line: www.ansi.org Search: www.nssn.org API American Petroleum Institute 1220 L Street, NW Publications: Washington, D.C. 20005-4070 See Global Engineering Documents Phone: 202/682-8417 FAX: 202/682-8154 On line: www.api.org APWA American Public Works Association Note: Free download available at

2345 Grand Boulevard, Suite 500 www.apwa.net/About/PET/RightOfWay/One-Call Kansas City, MO 64108-2641 for: Phone: 816/472-6100 • One-call Directory FAX: 816/472-1610 • Marking Guidelines On line: www.apwa.net • Color Code & Marking Guidelines AREMA American Railway Engineering and Maintenance of Way Association 8201 Corporate Drive, Suite 1125 Landover, MD 20785 Phone: 301-459-3200 FAX: 301-459-8077 On line: www.arema.org ASCE The American Society of Civil Engineers 1801 Alexander Bell Drive Reston, VA 20191-4400 Phone: 800/548-2723 FAX: 703/295-6222 On line: www.asce.org



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ASME The American Society of Mechanical Engineers International & Information Central Center for Research and Technology ASME/ Orders and Inquiries Development: CRTD P.O. Box 2900 1828 L Street, NW, Suite 906 Fairfield, NJ 07007-2900 Washington, DC 20036-5104 Phone: 800/843-2763 Phone: 202/785-3756 FAX: 973/882-1717 FAX: 202/785-8120 On line: www.asme.org On line: www.asme.org/research

ASNT American Society for Nondestructive Testing P.O. Box 28518 1711 Arlingate Lane Columbus, OH 43228-0518 Phone: 800-222-2768 Fax: 614-274-6899 On line: www.asnt.org ASTM ASTM International (Formerly American Society for Testing and Materials)

100 Barr Harbor Drive West Conshohocken, PA 19428-2959 Phone: 610/832-9585 FAX: 610/832-9555 On line: www.astm.org AWS American Welding Society 550 NW LeJune Road Miami, FL 33126 Phone: 305/443-9353 FAX: 305/443-5951 On line: www.aws.org AWWA American Water Works Association 6666 W. Quincy Avenue Denver, CO 80235 Phone: 303/794-7711 FAX: 303/347-0804 On line: www.awwa.org CoGDEM The Council of Gas Detection and Environmental Monitoring Unit 11, Theobald Business Park Knowl Piece, Wilbury Way Hitchin, Herts, SG4 0TY, UK Phone: +44(0) 1462 434322 FAX: +44(0) 1462 434488 On line: www.cogdem.org.uk DIPRA Ductile Iron Pipe Research Association 245 Riverchase Parkway East, Suite O Birmingham, AL 35244 Phone: 205/402-8700 FAX: 205/402-8730 On line: www.dipra.org



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GTI Gas Technology Institute (Formerly 1700 S. Mount Prospect Road GRI) Des Plaines, IL 60018-1804 Phone: 847/768-0500 Orders: 630/406-5994 FAX: 630/403-5995 On line: www.gastechnology.org IAPMO International Association of Plumbing and Mechanical Officials 5001 E. Philadelphia Street Ontario, CA 91761 Phone: 909/472-4100 Orders: 800/854-2766 FAX: 909/472-4150 On line: www.iapmo.org/iapmo MSS Manufacturers Standardization Society of the Valve and Fittings Industry 127 Park Street, N.E. Vienna, VA 22180 Phone: 703/281-6613 FAX: 703/281-6671 On line: www.normas.com/MSS NACE NACE International 1440 South Creek Drive Houston, TX 77084-4906 Phone: 281/228-6223 FAX: 281/228-6329 On line: www.nace.org NBBI National Board of Boiler and Pressure Vessel Inspectors 1055 Crupper Avenue Columbus, Ohio 43229-1183 Phone: 614/888-8320 FAX: 614/848-3474 On line: www.nationalboard.org NCB National Coal Board (Replaced by The Coal Authority in 1994)

The Coal Authority 200 Lichfield Lane Mansfield, Nottinghamshire NG18 4RG Phone: 01623-427-162 On line: www.coal.gov.uk

NFPA National Fire Protection Association 1 Batterymarch Park Quincy, MA 02169-7471 Phone: 800/344-3555 FAX: 800/593-6372 On line: www.nfpa.org

Addendum No. 6, September 2006 326(a)Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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OPS DOT/PHMSA/Office of Pipeline Safety Attn: Freedom of Information Act Request 400 7th Street, SW, Room 2103 Washington, DC 20590 Phone: 202/366-4595 FAX: 202/366-4566 On line: ops.dot.gov PPI Plastics Pipe Institute 1825 Connecticut Avenue, NW, Suite 680 Washington, D.C. 20009 Phone: 202/462-9607 FAX: 202/462-9779 On line: www.plasticpipe.org PRCI Pipeline Research Council International Home Office: Publications: 1401 Wilson Boulevard; Suite 1101 See TTI Arlington, VA 22209-2505 Phone: 703/387-0190 Fax: 703/387-0192 On line: www.prci.org SSPC Steel Structures Painting Council (Name changed in 1997 to SSPC: The Society for Protective Coatings) SSPC: The Society for Protective Coatings 40 24th Street, 6th Floor Pittsburgh, PA 15222-4656 Phone: 877/281-7772 FAX: 412/281-9992 On line: www.sspc.org UL Underwriters Laboratories 333 Pfingsten Road Northbrook, IL 60062-2096 Phone: 847/272-8800 FAX: 847/272-8129 On line: www.ul.com 5 ADDITIONAL INFORMATION RESOURCES ACGIH American Conference of Governmental Industrial Hygienists 1330 Kemper Meadow Drive Cincinnati, Ohio 45240 Phone: 513/742-2020 Fax: 513/742-3355 On line: www.ACGIH.org



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ASHRAE American Society of Heating, Refrigerating and Air-Conditioning Engineers, Inc. 1791 Tullie Circle, N.E. Atlanta, GA 30329 Phone: 404/636-8400 FAX: 404/321-5478 On line: www.ashrae.com Battelle Battelle 505 King Avenue Columbus, OH 43201-2693 Phone: 614/424-6393 FAX: 614/424-3819 On line: www.battelle.org BOCA Building Officials and Code Administrators International, Inc. (Replaced in 1994 by the or International Codes Council) ICC International Codes Council 5203 Leesburg Pike, Suite 600 Falls Church, VA 22041 Phone: 888/422-7233 FAX: Birmingham, AL 205-592-7001 Chicago, IL 708/799-4981 Wittier, CA 562/699-4522 On line: www.iccsafe.org Federal U.S. Government Printing Office Register 732 North Capitol Street, NW Washington, DC 20401 On line: www.gpoaccess.gov/fr/advanced.html Global Global Engineering Documents 15 Inverness Way East Englewood, CO 80112 Phone: 800/854-7179 (Local: 303/397-7956) FAX: 303/397-2740 On line: www.global.ihs.com ILI ILI Infodisk, Inc. 610 Winters Avenue Paramus, NJ 07652 Phone: 866/816-9444 Publications & Sales Phone: 888/454-2688 FAX: 201/986-7886 On line: www.ili-info.com ILS International Library Service 2722 North 650 Street P.O. Box 735 Provo, Utah 84603 Phone: 801/374-6214 FAX: 801/374-0634 On line: www.normas.com

Addendum No. 6, September 2006 326(c) Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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http://www.global.ihs.com/


NTIS National Technical Information Service Technology Administration U.S. Department of Commerce 5285 Port Royal Road Springfield, VA 22161 Phone: 703/605-6000 Fax: 703/605-6900 On line: www.ntis.gov NTSB National Transportation Safety Board 490 L'Enfant Plaza, SW Washington, DC 20594 Phone: 800/877-6799 (Local: 202/314-6551) Fax: 202/314-6132 On line: www.ntsb.gov Techstreet Techstreet 777 East Eisenhower Parkway Ann Arbor, MI 48108 Phone: 800/699-9277 Fax: 734/913-3946 On line: www.techstreet.com TTI Technical Toolboxes, Inc. 3801 Kirby Drive, Suite 520 P.O. Box 980550 Houston, TX 77098-0550 Phone: 713/630-0505 Fax: 713/630-0560 On line: www.ttoolboxes.com

Addendum No. 6, September 2006 326(d) Copyright American Gas Association Provided by IHS under license with AGA Licensee=BP International/5928366101


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GPTC GUIDE FOR GAS TRANSMISSION AND Guide Material Appendix G-192-1A DISTRIBUTION PIPING SYSTEMS: 2003 Edition

GUIDE MATERIAL APPENDIX G-192-1A (See guide material under §§192.7 and 192.144)

EDITIONS OF MATERIAL SPECIFICATIONS, CODES AND STANDARDS PREVIOUSLY INCORPORATED BY REFERENCE IN THE REGULATIONS

Asterisk (*) marked entries show documents no longer included for reference in §192.7. A American Petroleum Institute (API) (1) API RP 5L1, Recommended Practice for Railroad Transportation of Line Pipe (1967, 1972, 1990). (2)* API Spec 5A, API Specification for Casing, Tubing, and Drill Pipe (1968, 1971, 1973, + Supp. 1,

1979). (3) API Spec 5L, Specification for Line Pipe (1967, 1970, 1971 + Supp. 1, 1975, 1980, 1985, 1988,

1992, 1995, 2000). (4)* API Spec 5LS, API Specification for Spiral-Weld Line Pipe (1967, 1970, 1971 + Supp. 1, 1973 +

Supp. 1, 1975 + Supp. 1, 1977, 1980). (Combined with 5L 3/31/82). (5)* API Spec 5LX, API Specification for High-Test Line Pipe (1967, 1970, 1971 + Supp. 1, 1973 +

Supp. 1, 1975 + Supp. 1, 1977, 1980). (Combined with 5L 3/31/82). (6)* API Spec 6A, API Specification for Wellhead and Christmas Tree Equipment (1968, 1974, 1979). (7) API Spec 6D, Specification for Pipeline Valves (Gate, Plug, Ball and Check Valves) (1968, 1974,

1977, 1991, 1994). (8) API Std 1104, Welding of Pipelines and Related Facilities (1968, 1973, 1980, 1988, 1994). Editorial Note: Based on Amdt. 192-103, API RP80, Guide Lines for the Definition of Onshore Gas

Gathering Lines (1st edition, April 2000) was deleted from §192.7, being no longer incorporated by reference. Therefore, it is to be added herein; however, it is still referenced in §192.8. Resolution pending.

B American Society for Testing and Materials (ASTM) (1) ASTM A53, Standard Specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated, Welded

and Seamless (1965, 1968, 1973, 1979, 1990b, 1995a, 1996, 1999). (2)* ASTM A72, Standard Specification for Welded Wrought-Iron Pipe (1964T, 1968) (Discontinued

and not replaced). (3) ASTM A106, Standard Specification for Seamless Carbon Steel Pipe for High-Temperature

Service, (1966, 1968, 1972a, 1979b, 1991, 1994a, 1995, 1999). (4)* ASTM A134, Standard Specification for Pipe, Steel, Electric-Fusion (Arc)-Welded (Sizes NPS 16

and Over) (1964, 1968, 1973, 1974). (5)* ASTM A135, Standard Specification for Electric-Resistance-Welded Steel Pipe (1963T, 1968,

1973a, 1979). (6)* ASTM A139, Standard Specification for Electric-Fusion (Arc)-Welded Steel Pipe (NPS 4 and

Over) (1964, 1968, 1973, 1974). (7)* ASTM A155, Standard Specification for Electric-Fusion-Welded Steel Pipe for High-Pressure

Service (1965, 1968, 1972a). (Discontinued and replaced by A671, A672 and A 691). (8)* ASTM A211, Standard Specification for Spiral-Welded Steel or Iron Pipe (1963, 1968, 1973, 1975)

(Discontinued and not replaced). (9) ASTM A333, Standard Specification for Seamless and Welded Steel Pipe for Low-Temperature

Service (1964, 1967, 1973, 1979, 1991a, 1994, 1999). (10) ASTM A372, Standard Specification for Carbon and Alloy Steel Forgings for Thin-Walled Pressure

Vessels (1967, 1971, 1978, 1991a, 1995, 1999). (11)* ASTM A377, Standard Index of Specifications for Grey Iron and Ductile Iron Pressure Pipe (1966,

1973, 1979). (12) ASTM A381, Standard Specification for Metal-Arc-Welded Steel Pipe for Use with High-Pressure

Transmission Systems (1966, 1968, 1973, 1979, 1989, 1993. 1996).



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(13)* ASTM A539, Standard Specification for Electric-Resistance-Welded Coiled Steel Tubing for Gas and Fuel Oil Lines (1965, 1973, 1979) (Discontinued and replaced by ASTM A 450).

(14) ASTM A671, Standard Specification for Electric-Fusion-Welded Steel Pipe for Atmospheric and Lower Temperatures (1977, 1989a, 1994, 1996).

(15) ASTM A672, Standard Specification for Electric-Fusion-Welded Steel Pipe for High-Pressure Service at Moderate Temperatures (1979, 1989b, 1994, 1996).

(16) ASTM A691, Standard Specification for Carbon and Alloy Steel Pipe, Electric-Fusion-Welded for High-Pressure Service at High Temperatures (1979, 1989a, 1993, 1998).

(17)* ASTM B42, Standard Specification for Seamless Copper Pipe, Standard Sizes (1962, 1966, 1972, 1980).

(18)* ASTM B68, Standard Specification for Seamless Copper Tube, Bright Annealed (1965, 1968, 1973, 1980).

(19)* ASTM B75, Standard Specification for Seamless Copper Tube (1965, 1968, 1973, 1980). (20)* ASTM B88, Standard Specification for Seamless Copper Water Tube (1966, 1972, 1980, 1999). (21)* ASTM B251, Standard Specification for General Requirements for Wrought Seamless Copper and

Copper-Alloy Tube (1966, 1968, 1972, 1976). (22) ASTM D638, Standard Test Method for Tensile Properties of Plastics (1977a, 1991, 1995, 1996,

1999). (23) ASTM D2513, Standard Specification for Thermoplastic Gas Pressure Pipe, Tubing, and Fittings

(1966T, 1968, 1970, 1971, 1973, 1974a, 1978ES, 1981, 1987 except for §192.63(a)(1), 1990c, 1995c, 1996).

(24) ASTM D2517, Standard Specification for Reinforced Epoxy Resin Gas Pressure Pipe and Fittings (1966T, 1967, 1973, 1981-reapproved 1987, 1994).

(25) ASTM F1055, Standard Specification for Electrofusion Type Polyethylene Fittings for Outside Diameter Controlled Polyethylene Pipe and Tubing (1995).

C American National Standards Institute, Inc. (ANSI) or ANSI/The American Society of Mechanical

Engineers (ASME) (1)* ANSI A21.1, Thickness Design of Cast-Iron Pipe (1967, 1972) (Discontinued and not replaced). (2)* ANSI A21.3, Specification for Cast-Iron Pit Cast Pipe for Gas (1953) (Discontinued and not

replaced). (3)* ANSI A21.7, Cast-Iron Pipe Centrifugally Cast in Metal Molds for Gas (1962) (Discontinued and

not replaced). (4)* ANSI A21.9, Cast-Iron Pipe Centrifugally Cast in Sand-Lined Molds for Gas (1962) (Discontinued

and not replaced). (5)* ANSI A21.11, Rubber-Gasket Joints for Ductile-Iron Pressure Pipe and Fittings (1964, 1972,

1979) (Discontinued and not replaced). (6)* ANSI A21.50, Thickness Design of Ductile-Iron Pipe (1965, 1971, 1976) (Discontinued and not

replaced). (7)* ANSI A21.52, Ductile-Iron Pipe, Centrifugally Cast for Gas (1965, 1971, 1976) (Discontinued and

not replaced). (8) ANSI B16.1, Cast-Iron Pipe Flanges and Flanged Fittings (1967, 1975, 1989). (9) ANSI B16.5, Steel Pipe Flanges and Flanged Fittings (1968, 1973, 1977, 1988 with October 1988

Errata and B16.5a-1992 Addenda, 1996 and B16.5a-1998 Addenda). (10)* ANSI B16.24, Cast Copper Alloy Pipe Flanges and Flanged Fittings (1962, 1971, 1979) (Source:

ASME B16.24). (11)* ANSI B36.10, Welded and Seamless Wrought Steel Pipe (1959, 1970, 1979). (12)* ANSI C1, National Electrical Code (1968, 1975). (13)* ANSI C101-67, Thickness Design of Cast-Iron Pipe (1977) (Discontinued and not identified by

ANSI or ASME).



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D American National Standards Institute, Inc. (ANSI)/National Fire Protection Association (NFPA) (1) ANSI/NFPA 30, Flammable and Combustible Liquids Code (1969, 1973, 1977, 1990, 1993, 1996). (2) ANSI/NFPA 58, Liquefied Petroleum Gas Code (1969, 1972, 1979, 1992, 1995, 1998). (3) ANSI/NFPA 59, Standard for the Storage and Handling of Liquefied Petroleum Gases at Utility

Gas Plants (1968, 1979, 1992, 1995, 1998). (4)* ANSI/NFPA 59A, Production, Storage and Handling of Liquefied Natural Gas (1971, 1972, 1979). (5) ANSI/NFPA 70, National Electrical Code (1978, 1993, 1996). E The American Society of Mechanical Engineers (ASME) (1) ASME Boiler and Pressure Vessel Code, Section I, Power Boilers (1992 with Interpretations, 1995

with Addenda, 1998). (2) ASME Boiler and Pressure Vessel Code, Section VIII, Pressure Vessels, Division 1 (1968, 1974,

1977, 1992 with Interpretations, 1995 with Addenda, 2001). (3) ASME Boiler and Pressure Vessel Code, Section VIII, Pressure Vessels, Division 2 Alternative

Rules (1992 with Interpretations, 1995 with Addenda, 2001). (4) ASME Boiler and Pressure Vessel Code, Section IX, Welding and Brazing Qualifications (1968,

1974, 1977, 1992 with Interpretations, 1995 with Addenda, 2001). (5) ASME B31.8, Gas Transmission and Distribution Piping Systems (1995). (6) ASME B31.8S, Supplement to B31.8 on Managing System Integrity of Gas Pipelines (2002). F Manufacturers Standardization Society of the Valves and Fittings Industry, Inc. (MSS) (1)* MSS SP-25, Standard Marking System for Valves, Fittings, Flanges, and Unions (1964, 1978). (2) MSS SP-44, Steel Pipeline Flanges (1955, 1972, 1975, 1991). (3)* MSS SP-52, Cast-Iron Pipe Line Valves (1957) (Discontinued and not replaced). (4)* MSS SP-70, Cast-Iron Gate Valves, Flanged and Threaded Ends (1970, 1976). (5)* MSS SP-71, Cast-Iron Swing Check Valves, Flanged and Threaded Ends (1970, 1976). (6)* MSS SP-78, Cast-Iron Plug Valves, Flanged and Threaded Ends (1972, 1977). G Plastic Pipe Institute , Inc. (PPI) (1) PPI TR-3, 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 (2000).



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Reserved



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GUIDE MATERIAL APPENDIX G-192-15 (See guide material under §192.111)

DESIGN OF UNCASED PIPELINE CROSSINGS OF HIGHWAYS AND RAILROADS

1 INTRODUCTION These guidelines provide references for contemporary techniques (PC-PISCES and API RP 1102) and

the historical "Spangler Method" to design uncased pipeline crossings. Reference is also provided to a specifications manual by the American Railway Engineering and Maintenance of Way Association.

2 CONTEMPORARY TECHNIQUES In 1985, the Gas Research Institute funded a research project to develop an improved method for the

design of uncased pipelines beneath railroads and highways. The study provided a more accurate method (i.e., PC-PISCES) for design of uncased crossings. The findings of this study are incorporated into the following publications.

(a) GRI-91/0283, "Guidelines for Pipelines Crossing Railroads." (b) GRI-91/0284, "Guidelines for Pipelines Crossing Highways." (c) GRI-91/0285, "Technical Summary and Database for Guidelines for Pipelines Crossing Railroads

and Highways." (d) GRI-91/0285.1, "Executive Summary: Technical Summary and Database for Guidelines for

Pipelines Crossing Railroads and Highways." (e) PRCI PC-PISCES, "Personal Computer - Pipeline Soil Crossing Evaluation System (PC-PISCES),"

Version 2.0 (Related to API RP 1102) (f) API RP 1102, "Steel Pipelines Crossing Railroads and Highways." 3 HISTORICAL METHOD Prior to the GRI study, the “Spangler Method” was used to design uncased crossings. This procedure

uses the design factors for uncased crossings specified in §192.111(b) and (c) along with various factors applicable to the determination of external loading on the pipe resulting from both live and dead loads. The factors used in determining the calculated external loading are variable and provide the designer with flexibility to consider various soil and highway loading conditions.

The end result of the calculation procedure is a determination of the total hoop stress imposed on the

uncased pipeline by the operating pressure and the external loading from the soil and traffic over the pipe. The calculation of total hoop stress may be used to confirm that the uncased pipeline will not be subject to an excessive calculated stress level in service. The total calculated combined stress, ST, should not exceed 100 percent SMYS.

T I Eb

3z

3S = S + S = PD2t

+ 3K WEDt

E t + 3K P D

W = 83.3 C B 10 + 10.4 LDI

H 10d D2 -3

2 3δπ



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GPTC GUIDE FOR GAS TRANSMISSION AND Guide Material Appendix G-192-15 DISTRIBUTION PIPING SYSTEMS: 2003 Edition Where: ST = total calculated combined stress, psi (≤ 100 percent SMYS) SI = hoop stress due to internal pressure, psi (as determined from the formula in §192.105

using design temperature derating and joint factors equal to 1) SE = hoop stress due to external loading, psi (as determined based on the procedure

developed by Dr. M. G. Spangler, lowa State University) P = internal pipeline pressure, psi (may not exceed the pressure determined from §192.105

using the design factors specified in §192.111) D = outside pipe diameter, inches t = nominal wall thickness, inches Kb = bending parameter (See Table 192.111ii) W = total external load, pounds/lineal inch of pipe (includes soil dead load and vehicular live

load) E = modulus of elasticity of steel = 30 x 106 psi Kz = deflection parameter (See Table 192.111ii) Cd = load coefficient (See Table 192.111iii) δ = unit weight of soil (120 pounds/cubic foot should be used unless the unit weight of

highway subsoil material is known) BD = width of pipe trench or diameter of bored hole, feet L = wheel load, pounds (the maximum wheel loading allowed by the governing authority

should be used) I = impact factor (1.5 should be used for nonrigid pavement and 1.0 for rigid pavement) H = height of soil over pipe, feet

DEFLECTION AND BENDING MOMENT PARAMETERS FOR CIRCULAR PIPE WITH LOAD UNIFORMLY DISTRIBUTED OVER TOP 180 DEGREES AND

BOTTOM SUPPORT DISTRIBUTED OVER VARIOUS WIDTHS1

Width of Uniform Support Under Pipe (Degrees)

Crossing Conditions

Parameters

Deflection Kz

Moment Kb

0 30 60 90 120 150 180

Consolidated Rock Open Trench ---- Bored ---- ---- ----

0.110 0.108 0.103 0.096 0.089 0.085 0.083

0.294 0.235 0.189 0.157 0.138 0.128 0.125

1Suggested parameters for various soil conditions are conservative. If width of support under pipe is known to be different from examples shown in the first column, then appropriate parameters may be used. Use parameter values for consolidated rock if bottom of the trench or bore is a mixture of soil and rock, but is predominantly rock.

TABLE 192.111ii



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SAFE WORKING VALUES FOR THE COEFFICIENT Cd FOR CALCULATING LOADS ON PIPES IN TRENCHES1

H/B

Minimum possible without cohesion. These values give the loads generally

imposed by granular filling

materials before tamping or

setting. (1)

Maximum for ordinary sand.

These values are safe for all

ordinary cases of sand filling.

(2)

Completely saturated

topsoil (3)

Ordinary maximum for

clay (thoroughly wet). These

values are safe for all ordinary cases of clay

filling. (4)

Extreme

maximum for clay (completely

saturated). These values are

only for extremely

unfavorable conditions.

(5)

0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0 8.5 9.0 9.5 10.0 11.0 12.0 13.0 14.0 15.0 Very Great

0.455 0.830 1.140 1.395 1.606 1.780 1.923 2.041 2.136 2.219 2.286 2.340 2.386 2.423 2.454 2.479 2.500 2.518 2.532 2.543 2.561 2.573 2.581 2.587 2.591 2.599

0.461 0.852 1.183 1.464 1.702 1.904 2.075 2.221 2.344 2.448 2.537 2.612 2.675 2.729 2.775 2.814 2.847 2.875 2.898 2.918 2.950 2.972 2.989 3.000 3.009 3.030

0.464 0.864 1.208 1.504 1.764 1.978 2.167 2.329 2.469 2.590 2.693 2.782 2.859 2.925 2.982 3.031 3.073 3.109 3.141 3.167 3.210 3.242 3.266 3.283 3.296 3.333

0.469 0.881 1.242 1.560 1.838 2.083 2.298 2.487 2.650 2.798 2.926 3.038 3.137 3.223 3.299 3.366 3.424 3.476 3.521 3.560 3.626 3.676 3.715 3.745 3.768 3.846

0.474 0.898 1.278 1.618 1.923 2.196 2.441 2.660 2.856 3.032 3.190 3.331 3.458 3.571 3.673 3.764 3.845 3.918 3.983 4.042 4.141 4.221 4.285 4.336 4.378 4.545

1 Data from Column (4) should be used unless highway subsoil is known to be material specified in Columns (1), (2), (3) or (5).

TABLE 192.111iii Reprinted from Piping Handbook, Fourth Edition, J.H. Walker and Sabin Crocker, 1930, McGraw-Hill Inc., New York, NY; data re-affirmed in Sixth Edition, published 1992. 4 AMERICAN RAILWAY ENGINEERING AND MAINTENANCE OF WAY ASSOCIATION (AREMA) (a) AREMA provides specifications for pipelines installed within railroad rights-of-way. These specifications are contained in Part

5 – Pipelines of Chapter 1 – Roadway and Ballast in the AREMA Manual for Railway Engineering and are written for the chief engineer (or authorized representative) of the railroad company.

(b) In accordance with the above manual, casing pipe for gas pipelines within the railroad right-of-way may be omitted provided that the specifications provided in the manual are met by the operator and approved by the railroad.



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Reserved



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