398 Part 192—Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards

§ 191.27 49 CFR Ch. I (10–1–11 Edition)

(5) Date condition was discovered and tration, Department of Transportation, date condition was first determined to Information Resources Manager, PHP– exist. 10, 1200 New Jersey Avenue SE., Wash- (6) Location of condition, with ref- ington, DC 20590-0001. erence to the State (and town, city, or [Amdt. 191–9, 56 FR 63770, Dec. 5, 1991, as county) or offshore site, and as appro- amended by Amdt. 191–14, 63 FR 37501, July priate, nearest street address, offshore 13, 1998; 70 FR 11139, Mar. 8, 2005; 73 FR 16570, platform, survey station number, mile- Mar. 28, 2008; 74 FR 2894, Jan. 16, 2009] post, landmark, or name of pipeline. (7) Description of the condition, in- PART 192—TRANSPORTATION OF cluding circumstances leading to its NATURAL AND OTHER GAS BY discovery, any significant effects of the condition on safety, and the name of PIPELINE: MINIMUM FEDERAL the commodity transported or stored. SAFETY STANDARDS (8) The corrective action taken (including reduction of pressure or shut- Subpart A—General down) before the report is submitted Sec. and the planned follow-up or future 192.1 What is the scope of this part? corrective action, including the antici- 192.3 Definitions. pated schedule for starting and con- 192.5 Class locations. cluding such action. 192.7 What documents are incorporated by reference partly or wholly in this part? [Amdt. 191–6, 53 FR 24949, July 1, 1988; 53 FR 192.8 How are onshore gathering lines and 29800, Aug. 8, 1988, as amended by Amdt. 191– regulated onshore gathering lines deter- 7, 54 FR 32344, Aug. 7, 1989; Amdt. 191–8, 54 FR mined? 40878, Oct. 4, 1989; Amdt. 191–10, 61 FR 18516, 192.9 What requirements apply to gathering Apr. 26, 1996] lines? 192.10 Outer continental shelf pipelines. § 191.27 Filing offshore pipeline condi- 192.11 Petroleum gas systems. tion reports. 192.13 What general requirements apply to pipelines regulated under this part? (a) Each operator shall, within 60 192.14 Conversion to service subject to this days after completion of the inspection part. of all its underwater pipelines subject 192.15 Rules of regulatory construction. to § 192.612(a), report the following in- 192.16 Customer notification. formation: (1) Name and principal address of op- Subpart B—Materials erator. 192.51 Scope. (2) Date of report. 192.53 General. (3) Name, job title, and business tele- 192.55 Steel pipe. phone number of person submitting the 192.57 [Reserved] report. 192.59 Plastic pipe. (4) Total length of pipeline inspected. 192.61 [Reserved] (5) Length and date of installation of 192.63 Marking of materials. 192.65 Transportation of pipe. each exposed pipeline segment, and location, including, if available, the loca- Subpart C—Pipe Design tion according to the Minerals Manage- ment Service or state offshore area and 192.101 Scope. block number tract. 192.103 General. (6) Length and date of installation of 192.105 Design formula for steel pipe. 192.107 Yield strength (S) for steel pipe. each pipeline segment, if different from 192.109 Nominal wall thickness (t) for steel a pipeline segment identified under pipe. paragraph (a)(5) of this section, that is 192.111 Design factor (F) for steel pipe. a hazard to navigation, and the loca- 192.112 Additional design requirements for tion, including, if available, the loca- steel pipe using alternative maximum al- tion according to the Minerals Manage- lowable operating pressure. ment Service or state offshore area and 192.113 Longitudinal joint factor (E) for steel pipe. block number tract. 192.115 Temperature derating factor (T) for (b) The report shall be mailed to the steel pipe. Office of Pipeline Safety, Pipeline and 192.117 [Reserved] Hazardous Materials Safety Adminis- 192.119 [Reserved]

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192.121 Design of plastic pipe. 192.245 Repair or removal of defects. 192.123 Design limitations for plastic pipe. 192.125 Design of copper pipe. Subpart F—Joining of Materials Other Than by Welding Subpart D—Design of Pipeline Components 192.271 Scope. 192.141 Scope. 192.273 General. 192.143 General requirements. 192.275 Cast iron pipe. 192.144 Qualifying metallic components. 192.277 Ductile iron pipe. 192.145 Valves. 192.279 Copper pipe. 192.147 Flanges and flange accessories. 192.281 Plastic pipe. 192.149 Standard fittings. 192.283 Plastic pipe: Qualifying joining pro- 192.150 Passage of internal inspection de- cedures. vices. 192.285 Plastic pipe: Qualifying persons to 192.151 Tapping. make joints. 192.153 Components fabricated by welding. 192.287 Plastic pipe: Inspection of joints. 192.155 Welded branch connections. 192.157 Extruded outlets. Subpart G—General Construction Require- 192.159 Flexibility. ments for Transmission Lines and Mains 192.161 Supports and anchors. 192.163 Compressor stations: Design and 192.301 Scope. construction. 192.303 Compliance with specifications or 192.165 Compressor stations: Liquid re- standards. moval. 192.305 Inspection: General. 192.167 Compressor stations: Emergency 192.307 Inspection of materials. shutdown. 192.309 Repair of steel pipe. 192.169 Compressor stations: Pressure lim- 192.311 Repair of plastic pipe. iting devices. 192.313 Bends and elbows. 192.171 Compressor stations: Additional 192.315 Wrinkle bends in steel pipe. safety equipment. 192.317 Protection from hazards. 192.173 Compressor stations: Ventilation. 192.319 Installation of pipe in a ditch. 192.175 Pipe-type and bottle-type holders. 192.321 Installation of plastic pipe. 192.177 Additional provisions for bottle-type 192.323 Casing. holders. 192.325 Underground clearance. 192.179 Transmission line valves. 192.327 Cover. 192.181 Distribution line valves. 192.328 Additional construction require- 192.183 Vaults: Structural design requirements for steel pipe using alternative ments. maximum allowable operating pressure. 192.185 Vaults: Accessibility. 192.187 Vaults: Sealing, venting, and ven- Subpart H—Customer Meters, Service tilation. Regulators, and Service Lines 192.189 Vaults: Drainage and waterproofing. 192.191 Design pressure of plastic fittings. 192.351 Scope. 192.193 Valve installation in plastic pipe. 192.353 Customer meters and regulators: Lo- 192.195 Protection against accidental over- cation. pressuring. 192.355 Customer meters and regulators: 192.197 Control of the pressure of gas deliv- Protection from damage. ered from high-pressure distribution sys- 192.357 Customer meters and regulators: In- tems. stallation. 192.199 Requirements for design of pressure 192.359 Customer meter installations: Oper- relief and limiting devices. ating pressure. 192.201 Required capacity of pressure reliev- 192.361 Service lines: Installation. ing and limiting stations. 192.363 Service lines: Valve requirements. 192.203 Instrument, control, and sampling 192.365 Service lines: Location of valves. pipe and components. 192.367 Service lines: General requirements for connections to main piping. Subpart E—Welding of Steel in Pipelines 192.369 Service lines: Connections to cast iron or ductile iron mains. 192.221 Scope. 192.371 Service lines: Steel. 192.225 Welding procedures. 192.373 Service lines: Cast iron and ductile 192.227 Qualification of welders. iron. 192.229 Limitations on welders. 192.375 Service lines: Plastic. 192.231 Protection from weather. 192.377 Service lines: Copper. 192.233 Miter joints. 192.379 New service lines not in use. 192.235 Preparation for welding. 192.381 Service lines: Excess flow valve per- 192.241 Inspection and test of welds. formance standards. 192.243 Nondestructive testing. 192.383 Excess flow valve installation.

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Subpart I—Requirements for Corrosion 192.515 Environmental protection and safety Control requirements. 192.517 Records. 192.451 Scope. 192.452 How does this subpart apply to con- Subpart K—Uprating verted pipelines and regulated onshore gathering lines? 192.551 Scope. 192.453 General. 192.553 General requirements. 192.555 Uprating to a pressure that will 192.455 External corrosion control: Buried produce a hoop stress of 30 percent or or submerged pipelines installed after more of SMYS in steel pipelines. July 31, 1971. 192.557 Uprating: Steel pipelines to a pres- 192.457 External corrosion control: Buried sure that will produce a hoop stress less or submerged pipelines installed before than 30 percent of SMYS; plastic, cast August 1, 1971. iron, and ductile iron pipelines. 192.459 External corrosion control: Exam- ination of buried pipeline when exposed. Subpart L—Operations 192.461 External corrosion control: Protec- tive coating. 192.601 Scope. 192.463 External corrosion control: Cathodic 192.603 General provisions. protection. 192.605 Procedural manual for operations, 192.465 External corrosion control: Moni- maintenance, and emergencies. toring. 192.607 [Reserved] 192.467 External corrosion control: Elec- 192.609 Change in class location: Required trical isolation. study. 192.469 External corrosion control: Test sta- 192.611 Change in class location: Confirma- tions. tion or revision of maximum allowable 192.471 External corrosion control: Test operating pressure. leads. 192.612 Underwater inspection and reburial 192.473 External corrosion control: Inter- of pipelines in the Gulf of Mexico and its ference currents. inlets. 192.475 Internal corrosion control: General. 192.613 Continuing surveillance. 192.476 Internal corrosion control: Design 192.614 Damage prevention program. and construction of transmission line. 192.615 Emergency plans. 192.477 Internal corrosion control: Moni- 192.616 Public awareness. toring. 192.617 Investigation of failures. 192.479 Atmospheric corrosion control: Gen- 192.619 What is the maximum allowable op- eral. erating pressure for steel or plastic pipelines? 192.481 Atmospheric corrosion control: Mon- 192.620 Alternative maximum allowable op- itoring. erating pressure for certain steel pipe- 192.483 Remedial measures: General. lines. 192.485 Remedial measures: Transmission 192.621 Maximum allowable operating pres- lines. sure: High-pressure distribution systems. 192.487 Remedial measures: Distribution 192.623 Maximum and minimum allowable lines other than cast iron or ductile iron operating pressure; Low-pressure dis- lines. tribution systems. 192.489 Remedial measures: Cast iron and 192.625 Odorization of gas. ductile iron pipelines. 192.627 Tapping pipelines under pressure. 192.490 Direct assessment. 192.629 Purging of pipelines. 192.491 Corrosion control records. 192.631 Control room management.

Subpart J—Test Requirements Subpart M—Maintenance 192.501 Scope. 192.701 Scope. 192.503 General requirements. 192.703 General. 192.505 Strength test requirements for steel 192.705 Transmission lines: Patrolling. pipeline to operate at a hoop stress of 30 192.706 Transmission lines: Leakage sur- percent or more of SMYS. veys. 192.507 Test requirements for pipelines to 192.707 Line markers for mains and trans- operate at a hoop stress less than 30 per- mission lines. cent of SMYS and at or above 100 p.s.i. 192.709 Transmission lines: Record keeping. (689 kPa) gage. 192.711 Transmission lines: General require- 192.509 Test requirements for pipelines to ments for repair procedures. operate below 100 p.s.i. (689 kPa) gage. 192.713 Transmission lines: Permanent field 192.511 Test requirements for service lines. repair of imperfections and damages. 192.513 Test requirements for plastic pipe- 192.715 Transmission lines: Permanent field lines. repair of welds.

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192.717 Transmission lines: Permanent field 192.919 What must be in the baseline assess- repair of leaks. ment plan? 192.719 Transmission lines: Testing of re- 192.921 How is the baseline assessment to be pairs. conducted? 192.721 Distribution systems: Patrolling. 192.923 How is direct assessment used and 192.723 Distribution systems: Leakage sur- for what threats? veys. 192.925 What are the requirements for using 192.725 Test requirements for reinstating External Corrosion Direct Assessment service lines. (ECDA)? 192.727 Abandonment or deactivation of fa- 192.927 What are the requirements for using cilities. Internal Corrosion Direct Assessment 192.731 Compressor stations: Inspection and (ICDA)? testing of relief devices. 192.929 What are the requirements for using 192.735 Compressor stations: Storage of Direct Assessment for Stress Corrosion combustible materials. Cracking (SCCDA)? 192.736 Compressor stations: Gas detection. 192.931 How may Confirmatory Direct As- 192.739 Pressure limiting and regulating sessment (CDA) be used? stations: Inspection and testing. 192.933 What actions must be taken to ad- 192.741 Pressure limiting and regulating dress integrity issues? stations: Telemetering or recording 192.935 What additional preventive and gauges. mitigative measures must an operator 192.743 Pressure limiting and regulating take? stations: Capacity of relief devices. 192.937 What is a continual process of eval- 192.745 Valve maintenance: Transmission uation and assessment to maintain a lines. pipeline’s integrity? 192.747 Valve maintenance: Distribution 192.939 What are the required reassessment systems. intervals? 192.749 Vault maintenance. 192.941 What is a low stress reassessment? 192.751 Prevention of accidental ignition. 192.943 When can an operator deviate from 192.753 Caulked bell and spigot joints. these reassessment intervals? 192.755 Protecting cast-iron pipelines. 192.945 What methods must an operator use to measure program effectiveness? Subpart N—Qualification of Pipeline 192.947 What records must an operator Personnel keep? 192.949 How does an operator notify 192.801 Scope. PHMSA? 192.803 Definitions. 192.951 Where does an operator file a report? 192.805 Qualification Program. 192.807 Recordkeeping. Subpart P—Gas Distribution Pipeline 192.809 General. Integrity Management (IM)

Subpart O—Gas Transmission Pipeline 192.1001 What definitions apply to this sub- Integrity Management part? 192.1003 What do the regulations in this sub- 192.901 What do the regulations in this subpart cover? part cover? 192.1005 What must a gas distribution oper- 192.903 What definitions apply to this sub- ator (other than a master meter or small part? LPG operator) do to implement this sub- 192.905 How does an operator identify a high part? consequence area? 192.1007 What are the required elements of 192.907 What must an operator do to imple- an integrity management plan? ment this subpart? 192.1009 What must an operator report when 192.909 How can an operator change its in- a mechanical fitting fails? tegrity management program? 192.1011 What records must an operator 192.911 What are the elements of an integ- keep? rity management program? 192.1013 When may an operator deviate from 192.913 When may an operator deviate its required periodic inspections of this program from certain requirements of part? this subpart? 192.1015 What must a master meter or small 192.915 What knowledge and training must liquefied petroleum gas (LPG) operator personnel have to carry out an integrity do to implement this subpart? management program? APPENDIX A TO PART 192 [RESERVED] 192.917 How does an operator identify poten- APPENDIX B TO PART 192—QUALIFICATION OF tial threats to pipeline integrity and use PIPE the threat identification in its integrity APPENDIX C TO PART 192—QUALIFICATION OF program? WELDERS FOR LOW STRESS LEVEL PIPE

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APPENDIX D TO PART 192—CRITERIA FOR CA- (i) Through a pipeline that operates THODIC PROTECTION AND DETERMINATION at less than 0 psig (0 kPa); OF MEASUREMENTS (ii) Through a pipeline that is not a APPENDIX E TO PART 192—GUIDANCE ON DE- regulated onshore gathering line (as TERMINING HIGH CONSEQUENCE AREAS AND determined in § 192.8); and ON CARRYING OUT REQUIREMENTS IN THE (iii) Within inlets of the Gulf of Mex- INTEGRITY MANAGEMENT RULE ico, except for the requirements in AUTHORITY: 49 U.S.C. 5103, 60102, 60104, § 192.612; or 60108, 60109, 60110, 60113, 60116, 60118, and 60137; (5) Any pipeline system that trans- and 49 CFR 1.53. ports only petroleum gas or petroleum SOURCE: 35 FR 13257, Aug. 19, 1970, unless gas/air mixtures to— otherwise noted. (i) Fewer than 10 customers, if no portion of the system is located in a EDITORIAL NOTE: Nomenclature changes to part 192 appear at 71 FR 33406, June 9, 2006. public place; or (ii) A single customer, if the system is located entirely on the customer’s Subpart A—General premises (no matter if a portion of the system is located in a public place). § 192.1 What is the scope of this part? [35 FR 13257, Aug. 19, 1970, as amended by (a) This part prescribes minimum Amdt. 192–27, 41 FR 34605, Aug. 16, 1976; safety requirements for pipeline facili- Amdt. 192–67, 56 FR 63771, Dec. 5, 1991; Amdt. ties and the transportation of gas, in- 192–78, 61 FR 28782, June 6, 1996; Amdt. 192–81, cluding pipeline facilities and the 62 FR 61695, Nov. 19, 1997; Amdt. 192–92, 68 FR transportation of gas within the limits 46112, Aug. 5, 2003; 70 FR 11139, Mar. 8, 2005; of the outer continental shelf as that Amdt. 192–102, 71 FR 13301, Mar. 15, 2006; term is defined in the Outer Conti- Amdt. 192–103, 72 FR 4656, Feb. 1, 2007] nental Shelf Lands Act (43 U.S.C. 1331). § 192.3 Definitions. (b) This part does not apply to— (1) Offshore gathering of gas in State As used in this part: waters upstream from the outlet flange Abandoned means permanently removed from service. of each facility where hydrocarbons are Active corrosion means continuing produced or where produced hydro- corrosion that, unless controlled, could carbons are first separated, dehy- result in a condition that is detri- drated, or otherwise processed, which- mental to public safety. ever facility is farther downstream; Administrator means the Adminis- (2) Pipelines on the Outer Conti- trator, Pipeline and Hazardous Mate- nental Shelf (OCS) that are producer- rials Safety Administration or his or operated and cross into State waters her delegate. without first connecting to a trans- Alarm means an audible or visible porting operator’s facility on the OCS, means of indicating to the controller upstream (generally seaward) of the that equipment or processes are out- last valve on the last production facil- side operator-defined, safety-related ity on the OCS. Safety equipment pro- parameters. tecting PHMSA-regulated pipeline seg- Control room means an operations ments is not excluded. Producing oper- center staffed by personnel charged ators for those pipeline segments up- with the responsibility for remotely stream of the last valve of the last pro- monitoring and controlling a pipeline duction facility on the OCS may peti- facility. tion the Administrator, or designee, for Controller means a qualified indi- approval to operate under PHMSA reg- vidual who remotely monitors and con- ulations governing pipeline design, trols the safety-related operations of a construction, operation, and mainte- pipeline facility via a SCADA system nance under 49 CFR 190.9; from a control room, and who has oper- (3) Pipelines on the Outer Conti- ational authority and accountability nental Shelf upstream of the point at for the remote operational functions of which operating responsibility trans- the pipeline facility. fers from a producing operator to a Customer meter means the meter that transporting operator; measures the transfer of gas from an (4) Onshore gathering of gas— operator to a consumer.

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Distribution line means a pipeline the same as the pressure provided to other than a gathering or transmission the customer. line. Main means a distribution line that Electrical survey means a series of serves as a common source of supply closely spaced pipe-to-soil readings for more than one service line. over pipelines which are subsequently Maximum actual operating pressure analyzed to identify locations where a means the maximum pressure that oc- corrosive current is leaving the pipe- curs during normal operations over a line. period of 1 year. Exposed underwater pipeline means an Maximum allowable operating pressure underwater pipeline where the top of (MAOP) means the maximum pressure the pipe protrudes above the under- at which a pipeline or segment of a water natural bottom (as determined pipeline may be operated under this by recognized and generally accepted part. practices) in waters less than 15 feet Municipality means a city, county, or (4.6 meters) deep, as measured from any other political subdivision of a mean low water. State. Gas means natural gas, flammable Offshore means beyond the line of or- gas, or gas which is toxic or corrosive. dinary low water along that portion of Gathering line means a pipeline that the coast of the United States that is transports gas from a current produc- in direct contact with the open seas tion facility to a transmission line or and beyond the line marking the sea- main. ward limit of inland waters. Gulf of Mexico and its inlets means the Operator means a person who engages waters from the mean high water mark in the transportation of gas. of the coast of the Gulf of Mexico and Outer Continental Shelf means all sub- its inlets open to the sea (excluding merged lands lying seaward and out- rivers, tidal marshes, lakes, and ca- side the area of lands beneath navi- nals) seaward to include the territorial gable waters as defined in Section 2 of sea and Outer Continental Shelf to a the Submerged Lands Act (43 U.S.C. depth of 15 feet (4.6 meters), as meas- 1301) and of which the subsoil and sea- ured from the mean low water. bed appertain to the United States and Hazard to navigation means, for the are subject to its jurisdiction and con- purposes of this part, a pipeline where trol. the top of the pipe is less than 12 Person means any individual, firm, inches (305 millimeters) below the un- joint venture, partnership, corporation, derwater natural bottom (as deter- association, State, municipality, coop- mined by recognized and generally ac- erative association, or joint stock asso- cepted practices) in waters less than 15 ciation, and including any trustee, re- feet (4.6 meters) deep, as measured ceiver, assignee, or personal represent- from the mean low water. ative thereof. High-pressure distribution system Petroleum gas means propane, pro- means a distribution system in which pylene, butane, (normal butane or the gas pressure in the main is higher isobutanes), and butylene (including than the pressure provided to the cus- isomers), or mixtures composed pre- tomer. dominantly of these gases, having a Line section means a continuous run vapor pressure not exceeding 208 psi of transmission line between adjacent (1434 kPa) gage at 100 °F (38 °C). compressor stations, between a com- Pipe means any pipe or tubing used in pressor station and storage facilities, the transportation of gas, including between a compressor station and a pipe-type holders. block valve, or between adjacent block Pipeline means all parts of those valves. physical facilities through which gas Listed specification means a specifica- moves in transportation, including tion listed in section I of appendix B of pipe, valves, and other appurtenance this part. attached to pipe, compressor units, me- Low-pressure distribution system means tering stations, regulator stations, de- a distribution system in which the gas livery stations, holders, and fabricated pressure in the main is substantially assemblies.

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Pipeline environment includes soil re- customer that is not down-stream from sistivity (high or low), soil moisture a distribution center; (2) operates at a (wet or dry), soil contaminants that hoop stress of 20 percent or more of may promote corrosive activity, and SMYS; or (3) transports gas within a other known conditions that could af- storage field. fect the probability of active corrosion. NOTE: A large volume customer may re- Pipeline facility means new and exist- ceive similar volumes of gas as a distribu- ing pipelines, rights-of-way, and any tion center, and includes factories, power equipment, facility, or building used in plants, and institutional users of gas. the transportation of gas or in the Transportation of gas means the gath- treatment of gas during the course of ering, transmission, or distribution of transportation. gas by pipeline or the storage of gas, in Service line means a distribution line or affecting interstate or foreign com- that transports gas from a common merce. source of supply to an individual customer, to two adjacent or adjoining [Amdt. 192–13, 38 FR 9084, Apr. 10, 1973, as amended by Amdt. 192–27, 41 FR 34605, Aug. residential or small commercial cus- 16, 1976; Amdt. 192–58, 53 FR 1635, Jan. 21, tomers, or to multiple residential or 1988; Amdt. 192–67, 56 FR 63771, Dec. 5, 1991; small commercial customers served Amdt. 192–72, 59 FR 17281, Apr. 12, 1994; Amdt. through a meter header or manifold. A 192–78, 61 FR 28783, June 6, 1996; Amdt. 192–81, service line ends at the outlet of the 62 FR 61695, Nov. 19, 1997; Amdt. 192–85, 63 FR customer meter or at the connection to 37501, July 13, 1998; Amdt. 192–89, 65 FR 54443, a customer’s piping, whichever is fur- Sept. 8, 2000; 68 FR 11749, Mar. 12, 2003; Amdt. ther downstream, or at the connection 192–93, 68 FR 53900, Sept. 15, 2003; Amdt. 192– 98, 69 FR 48406, Aug. 10, 2004; Amdt. 192–94, 69 to customer piping if there is no meter. FR 54592, Sept. 9, 2004; 70 FR 3148, Jan. 21, Service regulator means the device on 2005; 70 FR 11139, Mar. 8, 2005; Amdt. 192–112, a service line that controls the pres- 74 FR 63326, Dec. 3, 2009; Amdt. 192–114, 75 FR sure of gas delivered from a higher 48601, Aug. 11, 2010] pressure to the pressure provided to the customer. A service regulator may § 192.5 Class locations. serve one customer or multiple cus- (a) This section classifies pipeline lo- tomers through a meter header or cations for purposes of this part. The manifold. following criteria apply to classifica- SMYS means specified minimum tions under this section. yield strength is: (1) A ‘‘class location unit’’ is an on- (1) For steel pipe manufactured in ac- shore area that extends 220 yards (200 cordance with a listed specification, meters) on either side of the centerline the yield strength specified as a min- of any continuous 1- mile (1.6 kilo- imum in that specification; or meters) length of pipeline. (2) For steel pipe manufactured in ac- (2) Each separate dwelling unit in a cordance with an unknown or unlisted multiple dwelling unit building is specification, the yield strength deter- counted as a separate building intended mined in accordance with § 192.107(b). for human occupancy. State means each of the several (b) Except as provided in paragraph States, the District of Columbia, and (c) of this section, pipeline locations the Commonwealth of Puerto Rico. are classified as follows: Supervisory Control and Data Acquisi- (1) A Class 1 location is: tion (SCADA) system means a computer- (i) An offshore area; or based system or systems used by a con- (ii) Any class location unit that has troller in a control room that collects 10 or fewer buildings intended for and displays information about a pipe- human occupancy. line facility and may have the ability (2) A Class 2 location is any class lo- to send commands back to the pipeline cation unit that has more than 10 but facility. fewer than 46 buildings intended for Transmission line means a pipeline, human occupancy. other than a gathering line, that: (1) (3) A Class 3 location is: Transports gas from a gathering line or (i) Any class location unit that has 46 storage facility to a distribution cen- or more buildings intended for human ter, storage facility, or large volume occupancy; or

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(ii) An area where the pipeline lies tion, the incorporated materials are within 100 yards (91 meters) of either a available from the respective organiza- building or a small, well-defined out- tions listed in paragraph (c) (1) of this side area (such as a playground, recre- section. ation area, outdoor theater, or other (c) The full titles of documents incor- place of public assembly) that is occu- porated by reference, in whole or in pied by 20 or more persons on at least part, are provided herein. The numbers 5 days a week for 10 weeks in any 12- in parentheses indicate applicable edi- month period. (The days and weeks tions. For each incorporated document, need not be consecutive.) citations of all affected sections are (4) A Class 4 location is any class lo- provided. Earlier editions of currently cation unit where buildings with four listed documents or editions of docu- or more stories above ground are prev- ments listed in previous editions of 49 alent. CFR part 192 may be used for materials (c) The length of Class locations 2, 3, and components designed, manufac- and 4 may be adjusted as follows: tured, or installed in accordance with (1) A Class 4 location ends 220 yards these earlier documents at the time (200 meters) from the nearest building they were listed. The user must refer with four or more stories above ground. to the appropriate previous edition of (2) When a cluster of buildings in- 49 CFR part 192 for a listing of the ear- tended for human occupancy requires a lier listed editions or documents. Class 2 or 3 location, the class location (1) Incorporated by reference (IBR). ends 220 yards (200 meters) from the nearest building in the cluster. List of Organizations and Addresses: [Amdt. 192–78, 61 FR 28783, June 6, 1996; 61 FR A. Pipeline Research Council Inter- 35139, July 5, 1996, as amended by Amdt. 192– national, Inc. (PRCI), c/o Technical 85, 63 FR 37502, July 13, 1998] Toolboxes, 3801 Kirby Drive, Suite 520, Houston, TX 77098. § 192.7 What documents are incor- B. American Petroleum Institute porated by reference partly or wholly in this part? (API), 1220 L Street, NW., Washington, DC 20005. (a) Any documents or portions there- C. American Society for Testing and of incorporated by reference in this Materials (ASTM), 100 Barr Harbor part are included in this part as though Drive, West Conshohocken, PA 19428. set out in full. When only a portion of D. ASME International (ASME), a document is referenced, the remain- Three Park Avenue, New York, NY der is not incorporated in this part. 10016–5990. (b) All incorporated materials are available for inspection in the Office of E. Manufacturers Standardization Pipeline Safety, Pipeline and Haz- Society of the Valve and Fittings In- ardous Materials Safety Administra- dustry, Inc. (MSS), 127 Park Street, tion, 1200 New Jersey Avenue, SE., NE., Vienna, VA 22180. Washington, DC, 20590–0001, 202–366– F. National Fire Protection Associa- 4595, or at the National Archives and tion (NFPA), 1 Batterymarch Park, Records Administration (NARA). For P.O. Box 9101, Quincy, MA 02269–9101. information on the availability of this G. Plastics Pipe Institute, Inc. (PPI), material at NARA, call 202–741–6030 or 1825 Connecticut Avenue, NW., Suite go to: http://www.archives.gov/ 680, Washington, DC 20009. federallregister/ H. NACE International (NACE), 1440 codeloflfederallregulations/ South Creek Drive, Houston, TX 77084. ibrllocations.html. These materials I. Gas Technology Institute (GTI), have been approved for incorporation 1700 South Mount Prospect Road, Des by reference by the Director of the Plaines, IL 60018. Federal Register in accordance with 5 (2) Documents incorporated by ref- U.S.C. 552(a) and 1 CFR part 51. In addi- erence.

Source and name of referenced material 49 CFR reference

A. Pipeline Research Council International (PRCI):

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Source and name of referenced material 49 CFR reference

(1) AGA Pipeline Research Committee, Project PR–3–805, ‘‘A Modi- §§ 192.485(c);.192.933(a)(1); 192.933(d)(1)(i). fied Criterion for Evaluating the Remaining Strength of Corroded Pipe,’’ (December 22, 1989). The RSTRENG program may be used for calculating remaining strength. B. American Petroleum Institute (API): (1) ANSI/API Specification 5L/ISO 3183 ‘‘Specification for Line Pipe’’ §§ 192.55(e); 192.112; 192.113; Item I, Appen- (44th edition, 2007), includes errata (January 2009) and addendum dix B to Part 192. (February 2009). (2) API Recommended Practice 5L1 ‘‘Recommended Practice for § 192.65(a)(1). Railroad Transportation of Line Pipe,’’ (6th Edition, July 2002). (3) API Recommended Practice 5LW, ‘‘Transportation of Line Pipe § 192.65(b). on Barges and Marine Vessels’’ (2nd edition, December 1996, effective March 1, 1997). (4) ANSI/API Specification 6D, ‘‘Specification for Pipeline Valves’’ § 192.145(a). (23rd edition (April 2008, effective October 1, 2008) and errata 3 (includes 1 and 2, February 2009)). (5) API Recommended Practice 80, ‘‘Guidelines for the Definition of §§ 192.8(a); 192.8(a)(1); 192.8(a)(2); Onshore Gas Gathering Lines,’’ (1st edition, April 2000). 192.8(a)(3); 192.8(a)(4). (6) API Standard 1104, ‘‘Welding of Pipelines and Related Facilities’’ §§ 192.225; 192.227(a); 192.229(c)(1); (20th edition, October 2005, errata/addendum, (July 2007) and er- 192.241(c); Item II, Appendix B. rata 2 (2008)). (7) API Recommended Practice 1162, ‘‘Public Awareness Programs §§ 192.616(a); 192.616(b); 192.616(c). for Pipeline Operators,’’ (1st edition, December 2003). (8) API Recommended Practice 1165 ‘‘Recommended Practice 1165 § 192.631(c)(1). ‘‘Recommended Practice for Pipeline SCADA Displays,’’ (API RP 1165) (First edition (January 2007)). C. American Society for Testing and Materials (ASTM): (1) ASTM A53/A53M–07, ‘‘Standard Specification for Pipe, Steel, §§ 192.113; Item I, Appendix B to Part 192. Black and Hot-Dipped, Zinc-Coated, Welded and Seamless’’ (Sep- tember 1, 2007). (2) ASTM A106/A106M–08, ‘‘Standard Specification for Seamless §§ 192.113; Item I, Appendix B to Part 192. Carbon Steel Pipe for High-Temperature Service’’ (July 15, 2008). (3) ASTM A333/A333M–05 (2005) ‘‘Standard Specification for Seam- §§ 192.113; Item I, Appendix B to Part 192. less and Welded Steel Pipe for Low-Temperature Service’’. (4) ASTM A372/A372M–03 (reapproved 2008), ‘‘Standard Specifica- § 192.177(b)(1). tion for Carbon and Alloy Steel Forgings for Thin-Walled Pressure Vessels’’ (March 1, 2008). (5) ASTM A381–96 (reapproved 2005), ‘‘Standard Specification for §§ 192.113; Item I, Appendix B to Part 192. Metal-Arc Welded Steel Pipe for Use With High-Pressure Trans- mission Systems’’ (October 1, 2005). (6) ASTM A578/A578M–96 (re-approved 2001) ‘‘Standard Specifica- §§ 192.112(c)(2)(iii). tion for Straight-Beam Ultrasonic Examination of Plain and Clad Steel Plates for Special Applications.’’. (7) ASTM A671–06, ‘‘Standard Specification for Electric-Fusion- §§ 192.113; Item I, Appendix B to Part 192. Welded Steel Pipe for Atmospheric and Lower Temperatures’’ (May 1, 2006). (8) ASTM A672–08, ‘‘Standard Specification for Electric-Fusion- §§ 192.113; Item I, Appendix B to Part 192. Welded Steel Pipe for High-Pressure Service at Moderate Tem- peratures’’ (May 1, 2008). (9) ASTM A691–98 (reapproved 2007), ‘‘Standard Specification for §§ 192.113; Item I, Appendix B to Part 192. Carbon and Alloy Steel Pipe, Electric-Fusion-Welded for High- Pressure Service at High Temperatures’’ (November 1, 2007). (10) ASTM D638–03 ‘‘Standard Test Method for Tensile Properties §§ 192.283(a)(3); 192.283(b)(1). of Plastics.’’. (11) ASTM D2513–87 ‘‘Standard Specification for Thermoplastic Gas § 192.63(a)(1). Pressure Pipe, Tubing, and Fittings.’’. (12) ASTM D2513–99 ‘‘Standard Specification for Thermoplastic Gas §§ 192.123(e)(2); 192.191(b); 192.281(b)(2); Pressure Pipe, Tubing, and Fittings.’’. 192.283(a)(1)(i); Item 1, Appendix B to Part 192. (13) ASTM D2517–00 ‘‘Standard Specification for Reinforced Epoxy §§ 192.191(a); 192.281(d)(1); 192.283(a)(1)(ii); Resin Gas Pressure Pipe and Fittings.’’. Item I, Appendix B to Part 192. (14) ASTM F1055–1998, ‘‘Standard Specification for Electrofusion § 192.283(a)(1)(iii). Type Polyethylene Fittings for Outside Diameter Controller Poly- ethylene Pipe and Tubing.’’. D. ASME International (ASME): (1) ASME/ANSI B16.1–2005, ‘‘Gray Iron Pipe Flanges and Flanged § 192.147(c). Fittings: (Classes 25, 125, and 250)’’ (August 31, 2006). (2) ASME/ANSI B16.5–2003, ‘‘Pipe Flanges and Flanged Fittings.’’ §§ 192.147(a); 192.279. (October 2004). (3) ASME/ANSI B31G–1991 (Reaffirmed, 2004), ‘‘Manual for Deter- §§ 192.485(c); 192.933(a). mining the Remaining Strength of Corroded Pipelines.’’. (4) ASME/ANSI B31.8–2007, ‘‘Gas Transmission and Distribution § 192.619(a)(1)(i). Piping Systems’’ (November 30, 2007).

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Source and name of referenced material 49 CFR reference

(5) ASME/ANSI B31.8S–2004, ‘‘Supplement to B31.8 on Managing §§ 192.903(c); 192.907(b); 192.911 Introductory System Integrity of Gas Pipelines.’’. 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)(1); 192.923(b)(2); 192.923(b)(3); 192.925(b) In- troductory text; 192.925(b)(1); 192.925(b)(2); 192.925(b)(3); 192.925(b)(4); 192.927(b); 192.927(c)(1)(i); 192.929(b)(1); 192.929(b)(2); 192.933(a); 192.933(d)(1); 192.933(d)(1)(i); 192.935(a); 192.935(b)(1)(iv); 192.937(c)(1); 192.939(a)(1)(i); 192.939(a)(1)(ii); 192.939(a)(3); 192.945(a). (6) 2007 ASME Boiler & Pressure Vessel Code, Section I, ‘‘Rules for § 192.153(b). Construction of Power Boilers 2007’’ (2007 edition, July 1, 2007). (7) 2007 ASME Boiler & Pressure Vessel Code, Section VIII, Division §§ 192.153(a); 192.153(b); 192.153(d); 1, ‘‘Rules for Construction of Pressure Vessels 2’’ (2007 edition, 192.165(b)(3). July 1, 2007). (8) 2007 ASME Boiler & Pressure Vessel Code, Section VIII, Division §§ 192.153(b); 192.165(b)(3). 2, ‘‘Alternative Rules, Rules for Construction of Pressure Vessels’’ (2007 edition, July 1, 2007). (9) 2007 ASME Boiler & Pressure Vessel Code, Section IX, ‘‘Welding §§ 192.227(a); Item II, Appendix B to Part 192. and Brazing Procedures, Welders, Brazers, and Welding and Braz- ing Operators’’ (2007 edition, July 1, 2007). E. Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS): (1) MSS SP–44–2006, Standard Practice, ‘‘Steel Pipeline Flanges’’ § 192.147(a). (2006 edition). (2) [Reserved]. F. National Fire Protection Association (NFPA): (1) NFPA 30 (2008 edition, August 15, 2007), ‘‘Flammable and Com- § 192.735(b). bustible Liquids Code’’ (2008 edition; approved August 15, 2007). (2) NFPA 58 (2004), ‘‘Liquefied Petroleum Gas Code (LP-Gas §§ 192.11(a); 192.11(b); 192.11(c). Code).’’. (3) NFPA 59 (2004), ‘‘Utility LP-Gas Plant Code.’’ ...... §§ 192.11(a); 192.11(b); 192.11(c). (4) NFPA 70 (2008), ‘‘National Electrical Code’’ (NEC 2008) (Ap- §§ 192.163(e); 192.189(c). proved August 15, 2007). G. Plastics Pipe Institute, Inc. (PPI): (1) PPI TR–3/2008 HDB/HDS/PDB/SDB/MRS Policies (2008), ‘‘Poli- § 192.121. cies and Procedures for Developing Hydrostatic Design Basis (HDB), Pressure Design Basis (PDB), Strength Design Basis (SDB), and Minimum Required Strength (MRS) Ratings for Ther- moplastic Piping Materials or Pipe’’ (May 2008). H. NACE International (NACE): (1) NACE Standard SP0502–2008, Standard Practice, ‘‘Pipeline Ex- §§ 192.923(b)(1); 192.925(b) Introductory text; ternal Corrosion Direct Assessment Methodology’’ (reaffirmed 192.925(b)(1); 192.925(b)(1)(ii); 192.925(b)(2) March 20, 2008). Introductory text; 192.925(b)(3) Introductory text; 192.925(b)(3)(ii); 192.925(b)(3)(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 § 192.927(c)(2). Gas Transmission Pipelines Methodology.’’.

[35 FR 13257, Aug. 19, 1970] to determine if an onshore pipeline (or EDITORIAL NOTE: For FEDERAL REGISTER ci- part of a connected series of pipelines) tations affecting § 192.7, see the List of CFR is an onshore gathering line. The deter- Sections Affected, which appears in the mination is subject to the limitations Finding Aids section of the printed volume listed below. After making this deter- and at www.fdsys.gov. mination, an operator must determine if the onshore gathering line is a regu- § 192.8 How are onshore gathering lated onshore gathering line under lines and regulated onshore gathering lines determined? paragraph (b) of this section. (1) The beginning of gathering, under (a) An operator must use API RP 80 section 2.2(a)(1) of API RP 80, may not (incorporated by reference, see § 192.7),

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extend beyond the furthermost down- termined by the commingling of gas stream point in a production operation from separate production fields, the as defined in section 2.3 of API RP 80. fields may not be more than 50 miles This furthermost downstream point from each other, unless the Adminis- does not include equipment that can be trator finds a longer separation dis- used in either production or transpor- tance is justified in a particular case tation, such as separators or (see 49 CFR § 190.9). dehydrators, unless that equipment is (4) The endpoint of gathering, under involved in the processes of ‘‘produc- section 2.2(a)(1)(D) of API RP 80, may tion and preparation for transportation not extend beyond the furthermost or delivery of hydrocarbon gas’’ within downstream compressor used to in- the meaning of ‘‘production oper- crease gathering line pressure for de- ation.’’ livery to another pipeline. (2) The endpoint of gathering, under (b) For purposes of § 192.9, ‘‘regulated section 2.2(a)(1)(A) of API RP 80, may onshore gathering line’’ means: not extend beyond the first down- (1) Each onshore gathering line (or stream natural gas processing plant, segment of onshore gathering line) unless the operator can demonstrate, with a feature described in the second using sound engineering principles, column that lies in an area described in that gathering extends to a further the third column; and downstream plant. (2) As applicable, additional lengths (3) If the endpoint of gathering, under of line described in the fourth column section 2.2(a)(1)(C) of API RP 80, is de- to provide a safety buffer:

Type Feature Area Safety buffer

A ...... —Metallic and the MAOP produces a Class 2, 3, or 4 location (see § 192.5) None. 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). B ...... —Metallic and the MAOP produces a Area 1. Class 3 or 4 location ...... If the gathering line is in Area 2(b) or hoop stress of less than 20 percent Area 2. An area within a Class 2 lo- 2(c), the additional lengths of line of SMYS. If the stress level is un- cation the operator determines by extend upstream and downstream known, an operator must determine using any of the following three from the area to a point where the the stress level according to the methods: line is at least 150 feet (45.7 m) applicable provisions in subpart C (a) A Class 2 location...... from the nearest dwelling in the of this part. (b) An area extending 150 feet (45.7 area. However, if a cluster of dwell- —Non-metallic and the MAOP is 125 m) on each side of the centerline of ings in Area 2 (b) or 2(c) qualifies a psig (862 kPa) or less. any continuous 1 mile (1.6 km) of line as Type B, the Type B classi- pipeline and including more than 10 fication ends 150 feet (45.7 m) but fewer than 46 dwellings. from the nearest dwelling in the (c) An area extending 150 feet (45.7 cluster. m) on each side of the centerline of any continous 1000 feet (305 m) of pipeline and including 5 or more dwellings.

[Amdt. 192–102, 71 FR 13302, Mar. 15, 2006] quirements in § 192.150 and in subpart O of this part. § 192.9 What requirements apply to (c) Type A lines. An operator of a gathering lines? Type A regulated onshore gathering (a) Requirements. An operator of a line must comply with the require- gathering line must follow the safety ments of this part applicable to trans- requirements of this part as prescribed mission lines, except the requirements by this section. in § 192.150 and in subpart O of this (b) Offshore lines. An operator of an part. However, an operator of a Type A offshore gathering line must comply regulated onshore gathering line in a with requirements of this part applica- Class 2 location may demonstrate com- ble to transmission lines, except the re- pliance with subpart N by describing

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the processes it uses to determine the Requirement Compliance deadline qualification of persons performing op- Other provisions of this part April 15, 2009. erations and maintenance tasks. as required by paragraph (d) Type B lines. An operator of a (c) of this section for Type Type B regulated onshore gathering A lines. line must comply with the following requirements: (3) If, after April 14, 2006, a change in (1) If a line is new, replaced, relo- class location or increase in dwelling cated, or otherwise changed, the de- density causes an onshore gathering sign, installation, construction, initial line to be a regulated onshore gath- inspection, and initial testing must be ering line, the operator has 1 year for in accordance with requirements of Type B lines and 2 years for Type A this part applicable to transmission lines after the line becomes a regulated lines; onshore gathering line to comply with (2) If the pipeline is metallic, control this section. corrosion according to requirements of [Amdt. 192–102, 71 FR 13301, Mar. 15, 2006] subpart I of this part applicable to transmission lines; § 192.10 Outer continental shelf pipe- (3) Carry out a damage prevention lines. program under § 192.614; Operators of transportation pipelines (4) Establish a public education pro- on the Outer Continental Shelf (as de- gram under § 192.616; fined in the Outer Continental Shelf (5) Establish the MAOP of the line Lands Act; 43 U.S.C. 1331) must identify under § 192.619; and on all their respective pipelines the (6) Install and maintain line markers specific points at which operating re- according to the requirements for transmission lines in § 192.707. sponsibility transfers to a producing operator. For those instances in which (e) Compliance deadlines. An operator of a regulated onshore gathering line the transfer points are not identifiable must comply with the following dead- by a durable marking, each operator lines, as applicable. will have until September 15, 1998 to (1) An operator of a new, replaced, re- identify the transfer points. If it is not located, or otherwise changed line practicable to durably mark a transfer must be in compliance with the appli- point and the transfer point is located cable requirements of this section by above water, the operator must depict the date the line goes into service, un- the transfer point on a schematic lo- less an exception in § 192.13 applies. cated near the transfer point. If a (2) If a regulated onshore gathering transfer point is located subsea, then line existing on April 14, 2006 was not the operator must identify the transfer previously subject to this part, an op- point on a schematic which must be erator has until the date stated in the maintained at the nearest upstream fa- second column to comply with the ap- cility and provided to PHMSA upon re- plicable requirement for the line listed quest. For those cases in which adjoin- in the first column, unless the Admin- ing operators have not agreed on a istrator finds a later deadline is justi- transfer point by September 15, 1998 fied in a particular case: the Regional Director and the MMS Regional Supervisor will make a joint Requirement Compliance deadline determination of the transfer point. Control corrosion according to April 15, 2009. Subpart I requirements for [Amdt. 192–81, 62 FR 61695, Nov. 19, 1997, as transmission lines. amended at 70 FR 11139, Mar. 8, 2005] Carry out a damage preven- October 15, 2007. tion program under § 192.11 Petroleum gas systems. § 192.614. Establish MAOP under October 15, 2007. (a) Each plant that supplies petro- § 192.619. leum gas by pipeline to a natural gas Install and maintain line mark- April 15, 2008. distribution system must meet the re- ers under § 192.707. Establish a public education April 15, 2008. quirements of this part and ANSI/ program under § 192.616. NFPA 58 and 59.

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(b) Each pipeline system subject to § 192.14 Conversion to service subject this part that transports only petro- to this part. leum gas or petroleum gas/air mixtures (a) A steel pipeline previously used in must meet the requirements of this service not subject to this part quali- part and of ANSI/NFPA 58 and 59. fies for use under this part if the oper- (c) In the event of a conflict between ator prepares and follows a written this part and ANSI/NFPA 58 and 59, procedure to carry out the following ANSI/NFPA 58 and 59 prevail. requirements: (1) The design, construction, oper- [Amdt. 192–78, 61 FR 28783, June 6, 1996] ation, and maintenance history of the § 192.13 What general requirements pipeline must be reviewed and, where apply to pipelines regulated under sufficient historical records are not this part? available, appropriate tests must be performed to determine if the pipeline (a) No person may operate a segment is in a satisfactory condition for safe of pipeline listed in the first column operation. that is readied for service after the (2) The pipeline right-of-way, all date in the second column, unless: aboveground segments of the pipeline, (1) The pipeline has been designed, in- and appropriately selected under- stalled, constructed, initially in- ground segments must be visually inspected, and initially tested in accord- spected for physical defects and oper- ance with this part; or ating conditions which reasonably (2) The pipeline qualifies for use could be expected to impair the under this part according to the re- strength or tightness of the pipeline. quirements in § 192.14. (3) All known unsafe defects and conditions must be corrected in accord- Pipeline Date ance with this part. (4) The pipeline must be tested in ac- Offshore gathering line ...... July 31, 1977. Regulated onshore gathering March 15 2007. cordance with subpart J of this part to line to which this part did substantiate the maximum allowable not apply until April 14, operating pressure permitted by sub- 2006. part L of this part. All other pipelines ...... March 12, 1971. (b) Each operator must keep for the (b) No person may operate a segment life of the pipeline a record of the investigations, tests, repairs, replace- of pipeline listed in the first column ments, and alterations made under the that is replaced, relocated, or other- requirements of paragraph (a) of this wise changed after the date in the sec- section. ond column, unless the replacement, relocation or change has been made ac- [Amdt. 192–30, 42 FR 60148, Nov. 25, 1977] cording to the requirements in this § 192.15 Rules of regulatory construc- part. tion. Pipeline Date (a) As used in this part: Includes means including but not lim- Offshore gathering line ...... July 31, 1977. ited to. Regulated onshore gathering March 15, 2007. line to which this part did May means ‘‘is permitted to’’ or ‘‘is not apply until April 14, authorized to’’. 2006. May not means ‘‘is not permitted to’’ All other pipelines ...... November 12, 1970. or ‘‘is not authorized to’’. Shall is used in the mandatory and (c) Each operator shall maintain, imperative sense. modify as appropriate, and follow the (b) In this part: plans, procedures, and programs that it (1) Words importing the singular in- is required to establish under this part. clude the plural; [35 FR 13257, Aug. 19, 1970, as amended by (2) Words importing the plural in- Amdt. 192–27, 41 FR 34605, Aug. 16, 1976; clude the singular; and Amdt. 192–30, 42 FR 60148, Nov. 25, 1977; (3) Words importing the masculine Amdt. 192–102, 71 FR 13303, Mar. 15, 2006] gender include the feminine.

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§ 192.16 Customer notification. participating under 49 U.S.C. 60105 or 60106: (a) This section applies to each operator of a service line who does not (1) A copy of the notice currently in maintain the customer’s buried piping use; and up to entry of the first building down- (2) Evidence that notices have been stream, or, if the customer’s buried sent to customers within the previous 3 piping does not enter a building, up to years. the principal gas utilization equipment [Amdt. 192–74, 60 FR 41828, Aug. 14, 1995, as or the first fence (or wall) that sur- amended by Amdt. 192–74A, 60 FR 63451, Dec. rounds that equipment. For the pur- 11, 1995; Amdt. 192–83, 63 FR 7723, Feb. 17, pose of this section, ‘‘customer’s buried 1998] piping’’ does not include branch lines that serve yard lanterns, pool heaters, Subpart B—Materials or other types of secondary equipment. Also, ‘‘maintain’’ means monitor for § 192.51 Scope. corrosion according to § 192.465 if the This subpart prescribes minimum re- customer’s buried piping is metallic, quirements for the selection and quali- survey for leaks according to § 192.723, fication of pipe and components for use and if an unsafe condition is found, in pipelines. shut off the flow of gas, advise the customer of the need to repair the unsafe § 192.53 General. condition, or repair the unsafe condition. Materials for pipe and components must be: (b) Each operator shall notify each customer once in writing of the fol- (a) Able to maintain the structural lowing information: integrity of the pipeline under tem- (1) The operator does not maintain perature and other environmental con- the customer’s buried piping. ditions that may be anticipated; (2) If the customer’s buried piping is (b) Chemically compatible with any not maintained, it may be subject to gas that they transport and with any the potential hazards of corrosion and other material in the pipeline with leakage. which they are in contact; and (3) Buried gas piping should be— (c) Qualified in accordance with the applicable requirements of this sub- (i) Periodically inspected for leaks; part. (ii) Periodically inspected for corrosion if the piping is metallic; and § 192.55 Steel pipe. (iii) Repaired if any unsafe condition is discovered. (a) New steel pipe is qualified for use (4) When excavating near buried gas under this part if: piping, the piping should be located in (1) It was manufactured in accord- advance, and the excavation done by ance with a listed specification; hand. (2) It meets the requirements of— (5) The operator (if applicable), (i) Section II of appendix B to this plumbing contractors, and heating con- part; or tractors can assist in locating, inspect- (ii) If it was manufactured before No- ing, and repairing the customer’s bur- vember 12, 1970, either section II or III ied piping. of appendix B to this part; or (c) Each operator shall notify each (3) It is used in accordance with para- customer not later than August 14, graph (c) or (d) of this section. 1996, or 90 days after the customer first (b) Used steel pipe is qualified for use receives gas at a particular location, under this part if: whichever is later. However, operators (1) It was manufactured in accord- of master meter systems may continu- ance with a listed specification and it ously post a general notice in a promi- meets the requirements of paragraph nent location frequented by customers. II-C of appendix B to this part; (d) Each operator must make the fol- (2) It meets the requirements of: lowing records available for inspection (i) Section II of appendix B to this by the Administrator or a State agency part; or

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(ii) If it was manufactured before No- (4) Its dimensions are still within the vember 12, 1970, either section II or III tolerances of the specification to which of appendix B to this part; it was manufactured; and (3) It has been used in an existing (5) It is free of visible defects. line of the same or higher pressure and (c) For the purpose of paragraphs meets the requirements of paragraph (a)(1) and (b)(1) of this section, where II-C of appendix B to this part; or pipe of a diameter included in a listed (4) It is used in accordance with para- specification is impractical to use, pipe graph (c) of this section. of a diameter between the sizes in- (c) New or used steel pipe may be cluded in a listed specification may be used at a pressure resulting in a hoop used if it: stress of less than 6,000 p.s.i. (41 MPa) (1) Meets the strength and design cri- where no close coiling or close bending teria required of pipe included in that is to be done, if visual examination in- listed specification; and dicates that the pipe is in good condi- (2) Is manufactured from plastic com- tion and that it is free of split seams pounds which meet the criteria for ma- and other defects that would cause terial required of pipe included in that leakage. If it is to be welded, steel pipe listed specification. that has not been manufactured to a listed specification must also pass the [35 FR 13257, Aug. 19, 1970, as amended by weldability tests prescribed in para- Amdt. 192–19, 40 FR 10472, Mar. 6, 1975; Amdt. graph II-B of appendix B to this part. 192–58, 53 FR 1635, Jan. 21, 1988] (d) Steel pipe that has not been previously used may be used as replace- § 192.61 [Reserved] ment pipe in a segment of pipeline if it § 192.63 Marking of materials. has been manufactured prior to Novem- ber 12, 1970, in accordance with the (a) Except as provided in paragraph same specification as the pipe used in (d) of this section, each valve, fitting, constructing that segment of pipeline. length of pipe, and other component (e) New steel pipe that has been cold must be marked— expanded must comply with the man- (1) As prescribed in the specification datory provisions of API Specification or standard to which it was manufac- 5L. tured, except that thermoplastic fit- [35 FR 13257, Aug. 19, 1970, as amended by tings must be marked in accordance Amdt. 191–1, 35 FR 17660, Nov. 17, 1970; Amdt. with ASTM D2513–87 (incorporated by 192–12, 38 FR 4761, Feb. 22, 1973; Amdt. 192–51, reference, see § 192.7); 51 FR 15335, Apr. 23, 1986; 58 FR 14521, Mar. 18, (2) To indicate size, material, manu- 1993; Amdt. 192–85, 63 FR 37502, July 13, 1998] facturer, pressure rating, and temperature rating, and as appropriate, type, § 192.57 [Reserved] grade, and model. § 192.59 Plastic pipe. (b) Surfaces of pipe and components that are subject to stress from internal (a) New plastic pipe is qualified for pressure may not be field die stamped. use under this part if: (c) If any item is marked by die (1) It is manufactured in accordance stamping, the die must have blunt or with a listed specification; and rounded edges that will minimize (2) It is resistant to chemicals with stress concentrations. which contact may be anticipated. (d) Paragraph (a) of this section does (b) Used plastic pipe is qualified for not apply to items manufactured be- use under this part if: fore November 12, 1970, that meet all of (1) It was manufactured in accord- the following: ance with a listed specification; (1) The item is identifiable as to type, (2) It is resistant to chemicals with manufacturer, and model. which contact may be anticipated; (3) It has been used only in natural gas service;

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(2) Specifications or standards giving with adequate protection, to withstand pressure, temperature, and other ap- anticipated external pressures and propriate criteria for the use of items loads that will be imposed on the pipe are readily available. after installation.

[Amdt. 192–1, 35 FR 17660, Nov. 17, 1970, as § 192.105 Design formula for steel pipe. amended by Amdt. 192–31, 43 FR 883, Apr. 3, 1978; Amdt. 192–61, 53 FR 36793, Sept. 22, 1988; (a) The design pressure for steel pipe Amdt. 192–62, 54 FR 5627, Feb. 6, 1989; Amdt. is determined in accordance with the 192–61A, 54 FR 32642, Aug. 9, 1989; 58 FR 14521, following formula: Mar. 18, 1993; Amdt. 192–76, 61 FR 26122, May 24, 1996; 61 FR 36826, July 15, 1996; Amdt. 192– P=(2 St/D)×F×E×T 114, 75 FR 48603, Aug. 11, 2010] P=Design pressure in pounds per square inch § 192.65 Transportation of pipe. (kPa) gauge. S=Yield strength in pounds per square inch (a) Railroad. In a pipeline to be oper- (kPa) determined in accordance with ated at a hoop stress of 20 percent or § 192.107. more of SMYS, an operator may not D=Nominal outside diameter of the pipe in use pipe having an outer diameter to inches (millimeters). wall thickness ratio of 70 to 1, or more, t=Nominal wall thickness of the pipe in that is transported by railroad unless: inches (millimeters). If this is unknown, it (1) The transportation is performed is determined in accordance with § 192.109. in accordance with API Recommended Additional wall thickness required for con- current external loads in accordance with Practice 5L1 (incorporated by ref- § 192.103 may not be included in computing erence, see § 192.7). design pressure. (2) In the case of pipe transported be- F=Design factor determined in accordance fore November 12, 1970, the pipe is test- with § 192.111. ed in accordance with Subpart J of this E=Longitudinal joint factor determined in Part to at least 1.25 times the max- accordance with § 192.113. imum allowable operating pressure if it T=Temperature derating factor determined is to be installed in a class 1 location in accordance with § 192.115. and to at least 1.5 times the maximum (b) If steel pipe that has been sub- allowable operating pressure if it is to jected to cold expansion to meet the be installed in a class 2, 3, or 4 loca- SMYS is subsequently heated, other tion. Notwithstanding any shorter than by welding or stress relieving as a time period permitted under Subpart J part of welding, the design pressure is of this Part, the test pressure must be limited to 75 percent of the pressure de- maintained for at least 8 hours. termined under paragraph (a) of this (b) Ship or barge. In a pipeline to be section if the temperature of the pipe operated at a hoop stress of 20 percent exceeds 900 °F (482 °C) at any time or is or more of SMYS, an operator may not held above 600 °F (316 °C) for more than use pipe having an outer diameter to 1 hour. wall thickness ratio of 70 to 1, or more, that is transported by ship or barge on [35 FR 13257, Aug. 19, 1970, as amended by both inland and marine waterways un- Amdt. 192–47, 49 FR 7569, Mar. 1, 1984; Amdt. less the transportation is performed in 192–85, 63 FR 37502, July 13, 1998] accordance with API Recommended § 192.107 Yield strength (S) for steel Practice 5LW (incorporated by ref- pipe. erence, see § 192.7). (a) For pipe that is manufactured in [Amdt. 192–114, 75 FR 48603, Aug. 11, 2010] accordance with a specification listed in section I of appendix B of this part, Subpart C—Pipe Design the yield strength to be used in the design formula in § 192.105 is the SMYS § 192.101 Scope. stated in the listed specification, if This subpart prescribes the minimum that value is known. requirements for the design of pipe. (b) For pipe that is manufactured in accordance with a specification not § 192.103 General. listed in section I of appendix B to this Pipe must be designed with sufficient part or whose specification or tensile wall thickness, or must be installed properties are unknown, the yield

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strength to be used in the design for- Class location Design mula in § 192.105 is one of the following: factor (F) (1) If the pipe is tensile tested in ac- 1 ...... 0.72 cordance with section II-D of appendix 2 ...... 0.60 B to this part, the lower of the fol- 3 ...... 0.50 lowing: 4 ...... 0.40 (i) 80 percent of the average yield (b) A design factor of 0.60 or less strength determined by the tensile must be used in the design formula in tests. § 192.105 for steel pipe in Class 1 loca- (ii) The lowest yield strength deter- tions that: mined by the tensile tests. (1) Crosses the right-of-way of an un- (2) If the pipe is not tensile tested as improved public road, without a casing; provided in paragraph (b)(1) of this sec- (2) Crosses without a casing, or tion, 24,000 p.s.i. (165 MPa). makes a parallel encroachment on, the [35 FR 13257, Aug. 19, 1970, as amended by right-of-way of either a hard surfaced Amdt. 192–78, 61 FR 28783, June 6, 1996; Amdt. road, a highway, a public street, or a 192–83, 63 FR 7723, Feb. 17, 1998; Amdt. 192–85, railroad; 63 FR 37502, July 13, 1998] (3) Is supported by a vehicular, pedes- trian, railroad, or pipeline bridge; or § 192.109 Nominal wall thickness (t) for steel pipe. (4) Is used in a fabricated assembly, (including separators, mainline valve (a) If the nominal wall thickness for assemblies, cross-connections, and steel pipe is not known, it is deter- river crossing headers) or is used with- mined by measuring the thickness of in five pipe diameters in any direction each piece of pipe at quarter points on from the last fitting of a fabricated as- one end. sembly, other than a transition piece (b) However, if the pipe is of uniform or an elbow used in place of a pipe bend grade, size, and thickness and there are which is not associated with a fab- more than 10 lengths, only 10 percent ricated assembly. of the individual lengths, but not less (c) For Class 2 locations, a design fac- than 10 lengths, need be measured. The tor of 0.50, or less, must be used in the thickness of the lengths that are not design formula in § 192.105 for uncased measured must be verified by applying steel pipe that crosses the right-of-way a gauge set to the minimum thickness of a hard surfaced road, a highway, a found by the measurement. The nomi- public street, or a railroad. nal wall thickness to be used in the de- (d) For Class 1 and Class 2 locations, sign formula in § 192.105 is the next wall a design factor of 0.50, or less, must be thickness found in commercial speci- used in the design formula in § 192.105 fications that is below the average of for— all the measurements taken. However, (1) Steel pipe in a compressor station, the nominal wall thickness used may regulating station, or measuring sta- not be more than 1.14 times the small- tion; and est measurement taken on pipe less (2) Steel pipe, including a pipe riser, than 20 inches (508 millimeters) in out- on a platform located offshore or in inside diameter, nor more than 1.11 times land navigable waters. the smallest measurement taken on pipe 20 inches (508 millimeters) or more [35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192–27, 41 FR 34605, Aug. 16, 1976] in outside diameter. [35 FR 13257, Aug. 19, 1970, as amended by § 192.112 Additional design require- Amdt. 192–85, 63 FR 37502, July 13, 1998] ments for steel pipe using alternative maximum allowable oper- § 192.111 Design factor (F) for steel ating pressure. pipe. For a new or existing pipeline seg- (a) Except as otherwise provided in ment to be eligible for operation at the paragraphs (b), (c), and (d) of this sec- alternative maximum allowable oper- tion, the design factor to be used in the ating pressure (MAOP) calculated design formula in § 192.105 is deter- under § 192.620, a segment must meet mined in accordance with the following the following additional design require- table: ments. Records for alternative MAOP

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must be maintained, for the useful life of the pipeline, demonstrating compliance with these requirements:

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

(a) General standards for the (1) The plate, skelp, or coil used for the pipe must be micro-alloyed, fine grain, fully killed, con- steel pipe. tinuously cast steel with calcium treatment. (2) The carbon equivalents of the steel used for pipe must not exceed 0.25 percent by weight, as calculated by the Ito-Bessyo formula (Pcm formula) or 0.43 percent by weight, as calculated by the International Institute of Welding (IIW) formula. (3) The ratio of the specified outside diameter of the pipe to the specified wall thickness must be less than 100. The wall thickness or other mitigative measures must prevent denting and ovality anomalies during construction, strength testing and anticipated operational stresses. (4) The pipe must be manufactured using API Specification 5L, product specification level 2 (incorporated by reference, see § 192.7) for maximum operating pressures and minimum and maximum operating temperatures and other requirements under this section. (b) Fracture control ...... (1) The toughness properties for pipe must address the potential for initiation, propagation and arrest of fractures in accordance with: (i) API Specification 5L (incorporated by reference, see § 192.7); or (ii) American Society of Mechanical Engineers (ASME) B31.8 (incorporated by reference, see § 192.7); and (iii) Any correction factors needed to address pipe grades, pressures, temperatures, or gas compositions not expressly addressed in API Specification 5L, product specification level 2 or ASME B31.8 (incorporated by reference, see § 192.7). (2) Fracture control must: (i) Ensure resistance to fracture initiation while addressing the full range of operating temperatures, pressures, gas compositions, pipe grade and operating stress levels, including maximum pressures and minimum temperatures for shut-in conditions, that the pipeline is expected to experience. If these parameters change during operation of the pipeline such that they are outside the bounds of what was considered in the design evaluation, the evaluation must be reviewed and updated to assure continued resistance to fracture initiation over the operating life of the pipeline; (ii) Address adjustments to toughness of pipe for each grade used and the decompression be- havior of the gas at operating parameters; (iii) Ensure at least 99 percent probability of fracture arrest within eight pipe lengths with a probability of not less than 90 percent within five pipe lengths; and (iv) Include fracture toughness testing that is equivalent to that described in supplementary requirements SR5A, SR5B, and SR6 of API Specification 5L (incorporated by reference, see § 192.7) and ensures ductile fracture and arrest with the following exceptions: (A) The results of the Charpy impact test prescribed in SR5A must indicate at least 80 percent minimum shear area for any single test on each heat of steel; and (B) The results of the drop weight test prescribed in SR6 must indicate 80 percent average shear area with a minimum single test result of 60 percent shear area for any steel test samples. The test results must ensure a ductile fracture and arrest. (3) If it is not physically possible to achieve the pipeline toughness properties of paragraphs (b)(1) and (2) of this section, additional design features, such as mechanical or composite crack arrestors and/or heavier walled pipe of proper design and spacing, must be used to ensure fracture arrest as described in paragraph (b)(2)(iii) of this section. (c) Plate/coil quality control ...... (1) There must be an internal quality management program at all mills involved in producing steel, plate, coil, skelp, and/or rolling pipe to be operated at alternative MAOP. These programs must be structured to eliminate or detect defects and inclusions affecting pipe quality. (2) A mill inspection program or internal quality management program must include (i) and either (ii) or (iii): (i) An ultrasonic test of the ends and at least 35 percent of the surface of the plate/coil or pipe to identify imperfections that impair serviceability such as laminations, cracks, and inclusions. At least 95 percent of the lengths of pipe manufactured must be tested. For all pipelines designed after December 22, 2008, the test must be done in accordance with ASTM A578/A578M Level B, or API 5L Paragraph 7.8.10 (incorporated by reference, see § 192.7) or equivalent method, and either (ii) A macro etch test or other equivalent method to identify inclusions that may form centerline segregation during the continuous casting process. Use of sulfur prints is not an equivalent method. The test must be carried out on the first or second slab of each sequence graded with an acceptance criteria of one or two on the Mannesmann scale or equivalent; or (iii) A quality assurance monitoring program implemented by the operator that includes audits of: (a) all steelmaking and casting facilities, (b) quality control plans and manufacturing procedure specifications, (c) equipment maintenance and records of conformance, (d) applicable casting superheat and speeds, and (e) centerline segregation monitoring records to ensure mitigation of centerline segregation during the continuous casting process. (d) Seam quality control ...... (1) There must be a quality assurance program for pipe seam welds to assure tensile strength provided in API Specification 5L (incorporated by reference, see § 192.7) for appropriate grades. (2) There must be a hardness test, using Vickers (Hv10) hardness test method or equivalent test method, to assure a maximum hardness of 280 Vickers of the following:

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

(i) A cross section of the weld seam of one pipe from each heat plus one pipe from each welding line per day; and (ii) For each sample cross section, a minimum of 13 readings (three for each heat affected zone, three in the weld metal, and two in each section of pipe base metal). (3) All of the seams must be ultrasonically tested after cold expansion and mill hydrostatic testing. (e) Mill hydrostatic test ...... (1) All pipe to be used in a new pipeline segment must be hydrostatically tested at the mill at a test pressure corresponding to a hoop stress of 95 percent SMYS for 10 seconds. The test pressure may include a combination of internal test pressure and the allowance for end loading stresses imposed by the pipe mill hydrostatic testing equipment as allowed by API Specification 5L, Appendix K (incorporated by reference, see § 192.7). (2) Pipe in operation prior to December 22, 2008, must have been hydrostatically tested at the mill at a test pressure corresponding to a hoop stress of 90 percent SMYS for 10 seconds. (f) Coating ...... (1) The pipe must be protected against external corrosion by a non-shielding coating. (2) Coating on pipe used for trenchless installation must be non-shielding and resist abrasions and other damage possible during installation. (3) A quality assurance inspection and testing program for the coating must cover the surface quality of the bare pipe, surface cleanliness and chlorides, blast cleaning, application temperature control, adhesion, cathodic disbondment, moisture permeation, bending, coating thickness, holiday detection, and repair. (g) Fittings and flanges ...... (1) There must be certification records of flanges, factory induction bends and factory weld ells. Certification must address material properties such as chemistry, minimum yield strength and minimum wall thickness to meet design conditions. (2) If the carbon equivalents of flanges, bends and ells are greater than 0.42 percent by weight, the qualified welding procedures must include a pre-heat procedure. (3) Valves, flanges and fittings must be rated based upon the required specification rating class for the alternative MAOP. (h) Compressor stations ...... (1) A compressor station must be designed to limit the temperature of the nearest downstream segment operating at alternative MAOP to a maximum of 120 degrees Fahrenheit (49 degrees Celsius) or the higher temperature allowed in paragraph (h)(2) of this section unless a long-term coating integrity monitoring program is implemented in accordance with paragraph (h)(3) of this section. (2) If research, testing and field monitoring tests demonstrate that the coating type being used will withstand a higher temperature in long-term operations, the compressor station may be designed to limit downstream piping to that higher temperature. Test results and acceptance criteria addressing coating adhesion, cathodic disbondment, and coating condition must be provided to each PHMSA pipeline safety regional office where the pipeline is in service at least 60 days prior to operating above 120 degrees Fahrenheit (49 degrees Celsius). An operator must also notify a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State. (3) Pipeline segments operating at alternative MAOP may operate at temperatures above 120 degrees Fahrenheit (49 degrees Celsius) if the operator implements a long-term coating integrity monitoring program. The monitoring program must include examinations using direct current voltage gradient (DCVG), alternating current voltage gradient (ACVG), or an equivalent method of monitoring coating integrity. An operator must specify the periodicity at which these examinations occur and criteria for repairing identified indications. An operator must submit its long-term coating integrity monitoring program to each PHMSA pipeline safety regional office in which the pipeline is located for review before the pipeline segments may be operated at temperatures in excess of 120 degrees Fahrenheit (49 degrees Celsius). An operator must also notify a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State.

[73 FR 62175, Oct. 17, 2008, as amended by Amdt. 192–111, 74 FR 62505, Nov. 30, 2009]

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

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

Longitudinal joint Specification Pipe class factor (E)

ASTM A 53/A53M ...... Seamless ...... 1.00 Electric resistance welded ...... 1.00 Furnace butt welded ...... 60 ASTM A 106 ...... Seamless ...... 1.00 ASTM A 333/A 333M ...... Seamless ...... 1.00 Electric resistance welded ...... 1.00

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Longitudinal joint Specification Pipe class factor (E)

ASTM A 381 ...... Double submerged arc welded ...... 1.00 ASTM A 671 ...... Electric-fusion-welded ...... 1.00 ASTM A 672 ...... Electric-fusion-welded ...... 1.00 ASTM A 691 ...... Electric-fusion-welded ...... 1.00 API 5 L ...... Seamless ...... 1.00 Electric resistance welded ...... 1.00 Electric flash welded ...... 1.00 Submerged arc welded ...... 1.00 Furnace butt welded ...... 60 Other ...... Pipe over 4 inches (102 millimeters) ...... 80 Other ...... Pipe 4 inches (102 millimeters) or less ...... 60

If the type of longitudinal joint cannot Gas temperature in degrees Temperature be determined, the joint factor to be Fahrenheit (Celsius) derating factor (T) used must not exceed that designated 400 °F (204 °C) ...... 0.900 for ‘‘Other.’’ 450 °F (232 °C) ...... 0.867 [Amdt. 192–37, 46 FR 10159, Feb. 2, 1981, as amended by Amdt. 192–51, 51 FR 15335, Apr. For intermediate gas temperatures, the 23, 1986; Amdt. 192–62, 54 FR 5627, Feb. 6, 1989; derating factor is determined by inter- 58 FR 14521, Mar. 18, 1993; Amdt. 192–85, 63 FR polation. 37502, July 13, 1998; Amdt. 192–94, 69 FR 32894, June 14, 2004] [35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192–85, 63 FR 37502, July 13, 1998] § 192.115 Temperature derating factor (T) for steel pipe. § 192.117 [Reserved] The temperature derating factor to be used in the design formula in § 192.119 [Reserved] § 192.105 is determined as follows: § 192.121 Design of plastic pipe. Gas temperature in degrees Temperature Fahrenheit (Celsius) derating factor (T) Subject to the limitations of § 192.123, the design pressure for plastic pipe is 250 °F (121 °C) or less ...... 1.000 300 °F (149 °C) ...... 0.967 determined by either of the following 350 °F (177 °C) ...... 0.933 formulas:

t P2S= ()DF (D− t)

2S P = ()DF (SDR−1 )

Where: porated by reference, see § 192.7). For rein- P = Design pressure, gauge, psig (kPa). forced thermosetting plastic pipe, 11,000 psig S = For thermoplastic pipe, the HDB is de- (75,842 kPa). [Note: Arithmetic interpolation termined in accordance with the listed speci- is not allowed for PA–11 pipe.] fication at a temperature equal to 73 °F (23 t = Specified wall thickness, inches (mm). °C), 100 °F (38 °C), 120 °F (49 °C), or 140 °F (60 D = Specified outside diameter, inches (mm). °C). In the absence of an HDB established at SDR = Standard dimension ratio, the ratio of the specified temperature, the HDB of a the average specified outside diameter to the higher temperature may be used in deter- minimum specified wall thickness, cor- mining a design pressure rating at the speci- responding to a value from a common num- fied temperature by arithmetic interpolation bering system that was derived from the using the procedure in Part D.2 of PPI TR–3/ American National Standards Institute pre- 2008, HDB/PDB/SDB/MRS Policies (incor- ferred number series 10.

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D F = 0.32 or D2513–99 (incorporated by reference, see = 0.40 for PA–11 pipe produced after January § 192.7); 23, 2009 with a nominal pipe size (IPS or CTS) 4-inch or less, and a SDR of 11 or greater (i.e. (3) The pipe size is nominal pipe size thicker pipe wall). (IPS) 12 or less; and (4) The design pressure is determined [Amdt. 192–111, 74 FR 62505, Nov. 30, 2009, as amended by Amdt. 192–114, 75 FR 48603, Aug. in accordance with the design equation 11, 2010] defined in § 192.121. (f) The design pressure for poly- § 192.123 Design limitations for plastic amide-11 (PA–11) pipe produced after pipe. January 23, 2009 may exceed a gauge (a) Except as provided in paragraph pressure of 100 psig (689 kPa) provided (e) and paragraph (f) of this section, that: the design pressure may not exceed a (1) The design pressure does not ex- gauge pressure of 100 psig (689 kPa) for ceed 200 psig (1379 kPa); plastic pipe used in: (2) The pipe size is nominal pipe size (1) Distribution systems; or (IPS or CTS) 4-inch or less; and (2) Classes 3 and 4 locations. (b) Plastic pipe may not be used (3) The pipe has a standard dimension where operating temperatures of the ratio of SDR–11 or greater (i.e., thicker pipe will be: pipe wall). ¥ ° ¥ ° ¥ ° (1) Below 20 F ( 20 C), or 40 F [35 FR 13257, Aug. 19, 1970, as amended by (¥40 °C) if all pipe and pipeline compo- Amdt. 192–31, 43 FR 13883, Apr. 3, 1978; Amdt. nents whose operating temperature 192–78, 61 FR 28783, June 6, 1996; Amdt. 192–85, will be below ¥29 °C (¥20 °F) have a 63 FR 37502, July 13, 1998; Amdt. 192–93, 68 FR temperature rating by the manufac- 53900, Sept. 15, 2003; 69 FR 32894, June 14, 2004; turer consistent with that operating Amdt. 192–94, 69 FR 54592, Sept. 9, 2004; Amdt. temperature; or 192–103, 71 FR 33407, June 9, 2006; 73 FR 79005, (2) Above the following applicable Dec. 24, 2008; Amdt. 192–114, 75 FR 48603, Aug. temperatures: 11, 2010] (i) For thermoplastic pipe, the temperature at which the HDB used in the § 192.125 Design of copper pipe. design formula under § 192.121 is deter- (a) Copper pipe used in mains must mined. have a minimum wall thickness of 0.065 (ii) For reinforced thermosetting inches (1.65 millimeters) and must be plastic pipe, 150 °F (66 °C). hard drawn. (c) The wall thickness for thermo- (b) Copper pipe used in service lines plastic pipe may not be less than 0.062 must have wall thickness not less than inches (1.57 millimeters). that indicated in the following table: (d) The wall thickness for reinforced thermosetting plastic pipe may not be Standard Nominal Wall thickness inch (milli- less than that listed in the following size inch O.D. inch meter) table: (millimeter) (millimeter) Nominal Tolerance

Minimum 1⁄2 (13) .625 (16) .040 (1.06) .0035 (.0889) wall thick- 5 Nominal size in inches (millimeters). ness inches ⁄8 (16) .750 (19) .042 (1.07) .0035 (.0889) (millime- 3⁄4 (19) .875 (22) .045 (1.14) .004 (.102) ters). 1 (25) 1.125 (29) .050 (1.27) .004 (.102) 11⁄4 (32) 1.375 (35) .055 (1.40) .0045 (.1143) 2 (51) ...... 0.060 (1.52) 11⁄2 (38) 1.625 (41) .060 (1.52) .0045 (.1143) 3 (76) ...... 0.060 (1.52) 4 (102) ...... 0.070 (1.78) 6 (152) ...... 0.100 (2.54) (c) Copper pipe used in mains and service lines may not be used at pres- (e) The design pressure for thermo- sures in excess of 100 p.s.i. (689 kPa) plastic pipe produced after July 14, 2004 gage. may exceed a gauge pressure of 100 psig (d) Copper pipe that does not have an (689 kPa) provided that: internal corrosion resistant lining may (1) The design pressure does not exceed 125 psig (862 kPa); not be used to carry gas that has an av- (2) The material is a PE2406 or a erage hydrogen sulfide content of more 3 3 PE3408 as specified within ASTM than 0.3 grains/100 ft (6.9/m ) under

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standard conditions. Standard condi- factured has equal or more stringent tions refers to 60 °F and 14.7 psia (15.6 requirements for the following as an °C and one atmosphere) of gas. edition of that document currently or previously listed in § 192.7 or appendix [35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192–62, 54 FR 5628, Feb. 6, 1989; Amdt. B of this part: 192–85, 63 FR 37502, July 13, 1998] (1) Pressure testing; (2) Materials; and Subpart D—Design of Pipeline (3) Pressure and temperature ratings. Components [Amdt. 192–45, 48 FR 30639, July 5, 1983, as amended by Amdt. 192–94, 69 FR 32894, June § 192.141 Scope. 14, 2004] This subpart prescribes minimum requirements for the design and installa- § 192.145 Valves. tion of pipeline components and facili- (a) Except for cast iron and plastic ties. In addition, it prescribes require- valves, each valve must meet the min- ments relating to protection against imum requirements of API 6D (incor- accidental overpressuring. porated by reference, see § 192.7), or to a national or international standard that § 192.143 General requirements. provides an equivalent performance (a) Each component of a pipeline level. A valve may not be used under must be able to withstand operating operating conditions that exceed the pressures and other anticipated load- applicable pressure-temperature ratings without impairment of its service- ings contained in those requirements. ability with unit stresses equivalent to (b) Each cast iron and plastic valve those allowed for comparable material must comply with the following: in pipe in the same location and kind (1) The valve must have a maximum of service. However, if design based service pressure rating for tempera- upon unit stresses is impractical for a tures that equal or exceed the max- particular component, design may be imum service temperature. based upon a pressure rating estab- (2) The valve must be tested as part lished by the manufacturer by pressure of the manufacturing, as follows: testing that component or a prototype (i) With the valve in the fully open of the component. position, the shell must be tested with (b) The design and installation of no leakage to a pressure at least 1.5 pipeline components and facilities times the maximum service rating. must meet applicable requirements for (ii) After the shell test, the seat must corrosion control found in subpart I of be tested to a pressure not less than 1.5 this part. times the maximum service pressure [Amdt. 48, 49 FR 19824, May 10, 1984 as rating. Except for swing check valves, amended at 72 FR 20059, Apr. 23, 2007] test pressure during the seat test must be applied successively on each side of § 192.144 Qualifying metallic compo- the closed valve with the opposite side nents. open. No visible leakage is permitted. Notwithstanding any requirement of (iii) After the last pressure test is this subpart which incorporates by ref- completed, the valve must be operated erence an edition of a document listed through its full travel to demonstrate in § 192.7 or Appendix B of this part, a freedom from interference. metallic component manufactured in (c) Each valve must be able to meet accordance with any other edition of the anticipated operating conditions. that document is qualified for use (d) No valve having shell (body, bon- under this part if— net, cover, and/or end flange) compo- (a) It can be shown through visual in- nents made of ductile iron may be used spection of the cleaned component that at pressures exceeding 80 percent of the no defect exists which might impair pressure ratings for comparable steel the strength or tightness of the compo- valves at their listed temperature. nent; and However, a valve having shell compo- (b) The edition of the document nents made of ductile iron may be used under which the component was manu- at pressures up to 80 percent of the

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pressure ratings for comparable steel for the pipeline to which it is being valves at their listed temperature, if: added. (1) The temperature-adjusted service pressure does not exceed 1,000 p.s.i. (7 § 192.150 Passage of internal inspec- Mpa) gage; and tion devices. (2) Welding is not used on any ductile (a) Except as provided in paragraphs iron component in the fabrication of (b) and (c) of this section, each new the valve shells or their assembly. transmission line and each replace- (e) No valve having shell (body, bon- ment of line pipe, valve, fitting, or net, cover, and/or end flange) compo- other line component in a transmission nents made of cast iron, malleable line must be designed and constructed iron, or ductile iron may be used in the to accommodate the passage of instru- gas pipe components of compressor sta- mented internal inspection devices. tions. (b) This section does not apply to: (1) [35 FR 13257, Aug. 19, 1970, as amended by Manifolds; Amdt. 192–62, 54 FR 5628, Feb. 6, 1989; Amdt. (2) Station piping such as at com- 192–85, 63 FR 37502, July 13, 1998; Amdt. 192– 94, 69 FR 32894, June 14, 2004; Amdt. 192–114, pressor stations, meter stations, or 75 FR 48603, Aug. 11, 2010] regulator stations; (3) Piping associated with storage fa- § 192.147 Flanges and flange acces- cilities, other than a continuous run of sories. transmission line between a com- (a) Each flange or flange accessory pressor station and storage facilities; (other than cast iron) must meet the (4) Cross-overs; minimum requirements of ASME/ANSI (5) Sizes of pipe for which an instru- B16.5, MSS SP–44, or the equivalent. mented internal inspection device is (b) Each flange assembly must be not commercially available; able to withstand the maximum pres- (6) Transmission lines, operated in sure at which the pipeline is to be oper- conjunction with a distribution system ated and to maintain its physical and which are installed in Class 4 locations; chemical properties at any tempera- (7) Offshore transmission lines, ex- ture to which it is anticipated that it cept transmission lines 103⁄4 inches (273 might be subjected in service. millimeters) or more in outside diame- (c) Each flange on a flanged joint in ter on which construction begins after cast iron pipe must conform in dimen- December 28, 2005, that run from plat- sions, drilling, face and gasket design to ASME/ANSI B16.1 and be cast inte- form to platform or platform to shore grally with the pipe, valve, or fitting. unless— (i) Platform space or configuration is [35 FR 13257, Aug. 19, 1970, as amended by incompatible with launching or re- Amdt. 192–62, 54 FR 5628, Feb. 6, 1989; 58 FR trieving instrumented internal inspec- 14521, Mar. 18, 1993] tion devices; or § 192.149 Standard fittings. (ii) If the design includes taps for lat- (a) The minimum metal thickness of eral connections, the operator can threaded fittings may not be less than demonstrate, based on investigation or specified for the pressures and tem- experience, that there is no reasonably peratures in the applicable standards practical alternative under the design referenced in this part, or their equiva- circumstances to the use of a tap that lent. will obstruct the passage of instru- (b) Each steel butt-welding fitting mented internal inspection devices; must have pressure and temperature and ratings based on stresses for pipe of the (8) Other piping that, under § 190.9 of same or equivalent material. The ac- this chapter, the Administrator finds tual bursting strength of the fitting in a particular case would be impracti- must at least equal the computed cable to design and construct to ac- bursting strength of pipe of the des- commodate the passage of instru- ignated material and wall thickness, as mented internal inspection devices. determined by a prototype that was (c) An operator encountering emer- tested to at least the pressure required gencies, construction time constraints

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or other unforeseen construction prob- § 192.153 Components fabricated by lems need not construct a new or re- welding. placement segment of a transmission (a) Except for branch connections line to meet paragraph (a) of this sec- and assemblies of standard pipe and fit- tion, if the operator determines and tings joined by circumferential welds, documents why an impracticability the design pressure of each component prohibits compliance with paragraph fabricated by welding, whose strength (a) of this section. Within 30 days after cannot be determined, must be estab- discovering the emergency or construc- lished in accordance with paragraph tion problem the operator must peti- UG–101 of section VIII, Division 1, of tion, under § 190.9 of this chapter, for the ASME Boiler and Pressure Vessel approval that design and construction Code. to accommodate passage of instru- (b) Each prefabricated unit that uses mented internal inspection devices plate and longitudinal seams must be would be impracticable. If the petition designed, constructed, and tested in ac- is denied, within 1 year after the date cordance with section I, section VIII, of the notice of the denial, the operator Division 1, or section VIII, Division 2 of must modify that segment to allow the ASME Boiler and Pressure Vessel passage of instrumented internal in- Code, except for the following: spection devices. (1) Regularly manufactured butt- welding fittings. [Amdt. 192–72, 59 FR 17281, Apr. 12, 1994, as (2) Pipe that has been produced and amended by Amdt. 192–85, 63 FR 37502, July tested under a specification listed in 13, 1998; Amdt. 192–97, 69 FR 36029, June 28, appendix B to this part. 2004] (3) Partial assemblies such as split § 192.151 Tapping. rings or collars. (4) Prefabricated units that the man- (a) Each mechanical fitting used to ufacturer certifies have been tested to make a hot tap must be designed for at at least twice the maximum pressure least the operating pressure of the to which they will be subjected under pipeline. the anticipated operating conditions. (b) Where a ductile iron pipe is (c) Orange-peel bull plugs and or- tapped, the extent of full-thread en- ange-peel swages may not be used on gagement and the need for the use of pipelines that are to operate at a hoop outside-sealing service connections, stress of 20 percent or more of the tapping saddles, or other fixtures must SMYS of the pipe. be determined by service conditions. (d) Except for flat closures designed (c) Where a threaded tap is made in in accordance with section VIII of the cast iron or ductile iron pipe, the di- ASME Boiler and Pressure Code, flat ameter of the tapped hole may not be closures and fish tails may not be used more than 25 percent of the nominal di- on pipe that either operates at 100 p.s.i. ameter of the pipe unless the pipe is re- (689 kPa) gage, or more, or is more inforced, except that than 3 inches (76 millimeters) nominal (1) Existing taps may be used for re- diameter. placement service, if they are free of [35 FR 13257, Aug. 19, 1970, as amended by cracks and have good threads; and Amdt. 192–1, 35 FR 17660, Nov. 17, 1970; 58 FR (2) A 11⁄4-inch (32 millimeters) tap 14521, Mar. 18, 1993; Amdt. 192–68, 58 FR 45268, may be made in a 4-inch (102 millime- Aug. 27, 1993; Amdt. 192–85, 63 FR 37502, July ters) cast iron or ductile iron pipe, 13, 1998] without reinforcement. § 192.155 Welded branch connections. However, in areas where climate, soil, Each welded branch connection made and service conditions may create un- to pipe in the form of a single connec- usual external stresses on cast iron tion, or in a header or manifold as a se- pipe, unreinforced taps may be used ries of connections, must be designed only on 6-inch (152 millimeters) or larg- to ensure that the strength of the pipe- er pipe. line system is not reduced, taking into [35 FR 13257, Aug. 19, 1970, as amended by account the stresses in the remaining Amdt. 192–85, 63 FR 37502, July 13, 1998] pipe wall due to the opening in the pipe

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or header, the shear stresses produced (1) A structural support may not be by the pressure acting on the area of welded directly to the pipe. the branch opening, and any external (2) The support must be provided by a loadings due to thermal movement, member that completely encircles the weight, and vibration. pipe. (3) If an encircling member is welded § 192.157 Extruded outlets. to a pipe, the weld must be continuous Each extruded outlet must be suit- and cover the entire circumference. able for anticipated service conditions (e) Each underground pipeline that is and must be at least equal to the de- connected to a relatively unyielding sign strength of the pipe and other fit- line or other fixed object must have tings in the pipeline to which it is at- enough flexibility to provide for pos- tached. sible movement, or it must have an anchor that will limit the movement of § 192.159 Flexibility. the pipeline. Each pipeline must be designed with (f) Except for offshore pipelines, each enough flexibility to prevent thermal underground pipeline that is being con- expansion or contraction from causing nected to new branches must have a excessive stresses in the pipe or compo- firm foundation for both the header nents, excessive bending or unusual and the branch to prevent detrimental loads at joints, or undesirable forces or lateral and vertical movement. moments at points of connection to [35 FR 13257, Aug. 19, 1970, as amended by equipment, or at anchorage or guide Amdt. 192–58, 53 FR 1635, Jan. 21, 1988] points. § 192.163 Compressor stations: Design § 192.161 Supports and anchors. and construction. (a) Each pipeline and its associated (a) Location of compressor building. Ex- equipment must have enough anchors cept for a compressor building on a or supports to: platform located offshore or in inland (1) Prevent undue strain on con- navigable waters, each main com- nected equipment; pressor building of a compressor sta- (2) Resist longitudinal forces caused tion must be located on property under by a bend or offset in the pipe; and the control of the operator. It must be (3) Prevent or damp out excessive vi- far enough away from adjacent prop- bration. erty, not under control of the operator, (b) Each exposed pipeline must have to minimize the possibility of fire enough supports or anchors to protect being communicated to the compressor the exposed pipe joints from the max- building from structures on adjacent imum end force caused by internal property. There must be enough open pressure and any additional forces space around the main compressor caused by temperature expansion or building to allow the free movement of contraction or by the weight of the fire-fighting equipment. pipe and its contents. (b) Building construction. Each build- (c) Each support or anchor on an ex- ing on a compressor station site must posed pipeline must be made of dura- be made of noncombustible materials if ble, noncombustible material and must it contains either— be designed and installed as follows: (1) Pipe more than 2 inches (51 milli- (1) Free expansion and contraction of meters) in diameter that is carrying the pipeline between supports or an- gas under pressure; or chors may not be restricted. (2) Gas handling equipment other (2) Provision must be made for the than gas utilization equipment used for service conditions involved. domestic purposes. (3) Movement of the pipeline may not (c) Exits. Each operating floor of a cause disengagement of the support main compressor building must have at equipment. least two separated and unobstructed (d) Each support on an exposed pipe- exits located so as to provide a conven- line operated at a stress level of 50 per- ient possibility of escape and an unob- cent or more of SMYS must comply structed passage to a place of safety. with the following: Each door latch on an exit must be of

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a type which can be readily opened tion must have an emergency shut- from the inside without a key. Each down system that meets the following: swinging door located in an exterior (1) It must be able to block gas out of wall must be mounted to swing out- the station and blow down the station ward. piping. (d) Fenced areas. Each fence around a (2) It must discharge gas from the compressor station must have at least blowdown piping at a location where two gates located so as to provide a the gas will not create a hazard. convenient opportunity for escape to a (3) It must provide means for the place of safety, or have other facilities shutdown of gas compressing equip- affording a similarly convenient exit ment, gas fires, and electrical facilities from the area. Each gate located within the vicinity of gas headers and in in 200 feet (61 meters) of any com- the compressor building, except that: pressor plant building must open out- (i) Electrical circuits that supply ward and, when occupied, must be emergency lighting required to assist openable from the inside without a station personnel in evacuating the key. compressor building and the area in (e) Electrical facilities. Electrical the vicinity of the gas headers must re- equipment and wiring installed in com- main energized; and pressor stations must conform to the (ii) Electrical circuits needed to pro- National Electrical Code, ANSI/NFPA tect equipment from damage may re- 70, so far as that code is applicable. main energized. [35 FR 13257, Aug. 19, 1970, as amended by (4) It must be operable from at least Amdt. 192–27, 41 FR 34605, Aug. 16, 1976; two locations, each of which is: Amdt. 192–37, 46 FR 10159, Feb. 2, 1981; 58 FR (i) Outside the gas area of the sta- 14521, Mar. 18, 1993; Amdt. 192–85, 63 FR 37502, tion; 37503, July 13, 1998] (ii) Near the exit gates, if the station § 192.165 Compressor stations: Liquid is fenced, or near emergency exits, if removal. not fenced; and (a) Where entrained vapors in gas (iii) Not more than 500 feet (153 me- may liquefy under the anticipated pres- ters) from the limits of the station. sure and temperature conditions, the (b) If a compressor station supplies compressor must be protected against gas directly to a distribution system the introduction of those liquids in with no other adequate source of gas quantities that could cause damage. available, the emergency shutdown (b) Each liquid separator used to re- system must be designed so that it will move entrained liquids at a compressor not function at the wrong time and station must: cause an unintended outage on the dis- (1) Have a manually operable means tribution system. of removing these liquids. (c) On a platform located offshore or (2) Where slugs of liquid could be car- in inland navigable waters, the emer- ried into the compressors, have either gency shutdown system must be de- automatic liquid removal facilities, an signed and installed to actuate auto- automatic compressor shutdown de- matically by each of the following vice, or a high liquid level alarm; and events: (3) Be manufactured in accordance (1) In the case of an unattended com- with section VIII of the ASME Boiler pressor station: and Pressure Vessel Code, except that (i) When the gas pressure equals the liquid separators constructed of pipe maximum allowable operating pressure and fittings without internal welding plus 15 percent; or must be fabricated with a design factor (ii) When an uncontrolled fire occurs of 0.4, or less. on the platform; and (2) In the case of a compressor sta- § 192.167 Compressor stations: Emer- tion in a building: gency shutdown. (i) When an uncontrolled fire occurs (a) Except for unattended field com- in the building; or pressor stations of 1,000 horsepower (746 (ii) When the concentration of gas in kilowatts) or less, each compressor sta- air reaches 50 percent or more of the

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lower explosive limit in a building § 192.173 Compressor stations: Ventila- which has a source of ignition. tion. For the purpose of paragraph (c)(2)(ii) Each compressor station building of this section, an electrical facility must be ventilated to ensure that em- which conforms to Class 1, Group D, of ployees are not endangered by the ac- the National Electrical Code is not a cumulation of gas in rooms, sumps, at- source of ignition. tics, pits, or other enclosed places. [35 FR 13257, Aug. 19, 1970, as amended by § 192.175 Pipe-type and bottle-type Amdt. 192–27, 41 FR 34605, Aug. 16, 1976; holders. Amdt. 192–85, 63 FR 37503, July 13, 1998] (a) Each pipe-type and bottle-type § 192.169 Compressor stations: Pres- holder must be designed so as to pre- sure limiting devices. vent the accumulation of liquids in the holder, in connecting pipe, or in auxil- (a) Each compressor station must iary equipment, that might cause cor- have pressure relief or other suitable rosion or interfere with the safe oper- protective devices of sufficient capac- ation of the holder. ity and sensitivity to ensure that the (b) Each pipe-type or bottle-type maximum allowable operating pressure holder must have minimum clearance of the station piping and equipment is from other holders in accordance with not exceeded by more than 10 percent. the following formula: (b) Each vent line that exhausts gas from the pressure relief valves of a C=(D×P×F)/48.33) (C=(3D×P×F/1,000)) compressor station must extend to a in which: location where the gas may be dis- C=Minimum clearance between pipe con- charged without hazard. tainers or bottles in inches (millimeters). D=Outside diameter of pipe containers or § 192.171 Compressor stations: Addi- bottles in inches (millimeters). tional safety equipment. P=Maximum allowable operating pressure, p.s.i. (kPa) gage. (a) Each compressor station must F=Design factor as set forth in § 192.111 of have adequate fire protection facilities. this part. If fire pumps are a part of these facilities, their operation may not be af- [35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192–85, 63 FR 37503, July 13, 1998] fected by the emergency shutdown system. § 192.177 Additional provisions for bot- (b) Each compressor station prime tle-type holders. mover, other than an electrical induc- (a) Each bottle-type holder must be— tion or synchronous motor, must have (1) Located on a site entirely sur- an automatic device to shut down the rounded by fencing that prevents ac- unit before the speed of either the cess by unauthorized persons and with prime mover or the driven unit exceeds minimum clearance from the fence as a maximum safe speed. follows: (c) Each compressor unit in a compressor station must have a shutdown Minimum clear- Maximum allowable operating pressure ance feet (me- or alarm device that operates in the ters) event of inadequate cooling or lubrica- Less than 1,000 p.s.i. (7 MPa) gage ...... 25 (7.6) tion of the unit. 1,000 p.s.i. (7 MPa) gage or more ...... 100 (31) (d) Each compressor station gas engine that operates with pressure gas in- (2) Designed using the design factors jection must be equipped so that stop- set forth in § 192.111; and page of the engine automatically shuts (3) Buried with a minimum cover in off the fuel and vents the engine dis- accordance with § 192.327. tribution manifold. (b) Each bottle-type holder manufac- (e) Each muffler for a gas engine in a tured from steel that is not weldable compressor station must have vent under field conditions must comply slots or holes in the baffles of each with the following: compartment to prevent gas from (1) A bottle-type holder made from being trapped in the muffler. alloy steel must meet the chemical and

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tensile requirements for the various tween main line valves must have a grades of steel in ASTM A 372/A 372M. blowdown valve with enough capacity (2) The actual yield-tensile ratio of to allow the transmission line to be the steel may not exceed 0.85. blown down as rapidly as practicable. (3) Welding may not be performed on Each blowdown discharge must be lo- the holder after it has been heat treat- cated so the gas can be blown to the ated or stress relieved, except that cop- mosphere without hazard and, if the per wires may be attached to the small transmission line is adjacent to an diameter portion of the bottle end clo- overhead electric line, so that the gas sure for cathodic protection if a local- is directed away from the electrical ized thermit welding process is used. conductors. (4) The holder must be given a mill (d) Offshore segments of transmission hydrostatic test at a pressure that pro- lines must be equipped with valves or duces a hoop stress at least equal to 85 other components to shut off the flow percent of the SMYS. of gas to an offshore platform in an (5) The holder, connection pipe, and emergency. components must be leak tested after installation as required by subpart J of [35 FR 13257, Aug. 19, 1970, as amended by this part. Amdt. 192–27, 41 FR 34606, Aug. 16, 1976; Amdt. 192–78, 61 FR 28784, June 6, 1996; Amdt. [35 FR 13257, Aug. 19, 1970, as amended by 192–85, 63 FR 37503, July 13, 1998] Amdt. 192–58, 53 FR 1635, Jan. 21, 1988; Amdt 192–62, 54 FR 5628, Feb. 6, 1989; 58 FR 14521, § 192.181 Distribution line valves. Mar. 18, 1993; Amdt. 192–85, 63 FR 37503, July (a) Each high-pressure distribution 13, 1998] system must have valves spaced so as § 192.179 Transmission line valves. to reduce the time to shut down a section of main in an emergency. The (a) Each transmission line, other valve spacing is determined by the op- than offshore segments, must have sec- erating pressure, the size of the mains, tionalizing block valves spaced as fol- and the local physical conditions. lows, unless in a particular case the Administrator finds that alternative (b) Each regulator station control- spacing would provide an equivalent ling the flow or pressure of gas in a dis- level of safety: tribution system must have a valve in- (1) Each point on the pipeline in a stalled on the inlet piping at a distance from the regulator station sufficient to Class 4 location must be within 21⁄2 miles (4 kilometers)of a valve. permit the operation of the valve dur- (2) Each point on the pipeline in a ing an emergency that might preclude Class 3 location must be within 4 miles access to the station. (6.4 kilometers) of a valve. (c) Each valve on a main installed for (3) Each point on the pipeline in a operating or emergency purposes must comply with the following: Class 2 location must be within 71⁄2 miles (12 kilometers) of a valve. (1) The valve must be placed in a (4) Each point on the pipeline in a readily accessible location so as to fa- Class 1 location must be within 10 cilitate its operation in an emergency. miles (16 kilometers) of a valve. (2) The operating stem or mechanism (b) Each sectionalizing block valve must be readily accessible. on a transmission line, other than off- (3) If the valve is installed in a buried shore segments, must comply with the box or enclosure, the box or enclosure following: must be installed so as to avoid trans- (1) The valve and the operating de- mitting external loads to the main. vice to open or close the valve must be readily accessible and protected from § 192.183 Vaults: Structural design re- tampering and damage. quirements. (2) The valve must be supported to (a) Each underground vault or pit for prevent settling of the valve or move- valves, pressure relieving, pressure ment of the pipe to which it is at- limiting, or pressure regulating sta- tached. tions, must be able to meet the loads (c) Each section of a transmission which may be imposed upon it, and to line, other than offshore segments, be- protect installed equipment.

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(b) There must be enough working and there must be a means for testing space so that all of the equipment re- the internal atmosphere before remov- quired in the vault or pit can be prop- ing the cover; erly installed, operated, and main- (2) If the vault or pit is vented, there tained. must be a means of preventing external (c) Each pipe entering, or within, a sources of ignition from reaching the regulator vault or pit must be steel for vault atmosphere; or sizes 10 inch (254 millimeters), and less, (3) If the vault or pit is ventilated, except that control and gage piping paragraph (a) or (c) of this section ap- may be copper. Where pipe extends plies. through the vault or pit structure, pro- (c) If a vault or pit covered by para- vision must be made to prevent the graph (b) of this section is ventilated passage of gases or liquids through the by openings in the covers or gratings opening and to avert strains in the and the ratio of the internal volume, in pipe. cubic feet, to the effective ventilating [35 FR 13257, Aug. 19, 1970, as amended by area of the cover or grating, in square Amdt. 192–85, 63 FR 37503, July 13, 1998] feet, is less than 20 to 1, no additional ventilation is required. § 192.185 Vaults: Accessibility. [35 FR 13257, Aug. 19, 1970, as amended by Each vault must be located in an ac- Amdt. 192–85, 63 FR 37503, July 13, 1998] cessible location and, so far as practical, away from: § 192.189 Vaults: Drainage and water- (a) Street intersections or points proofing. where traffic is heavy or dense; (a) Each vault must be designed so as (b) Points of minimum elevation, to minimize the entrance of water. catch basins, or places where the access cover will be in the course of sur- (b) A vault containing gas piping face waters; and may not be connected by means of a (c) Water, electric, steam, or other drain connection to any other under- facilities. ground structure. (c) Electrical equipment in vaults § 192.187 Vaults: Sealing, venting, and must conform to the applicable re- ventilation. quirements of Class 1, Group D, of the Each underground vault or closed top National Electrical Code, ANSI/NFPA pit containing either a pressure regu- 70. lating or reducing station, or a pres- [35 FR 13257, Aug. 19, 1970, as amended by sure limiting or relieving station, must Amdt. 192–76, 61 FR 26122, May 24, 1996] be sealed, vented or ventilated as follows: § 192.191 Design pressure of plastic fit- (a) When the internal volume exceeds tings. 200 cubic feet (5.7 cubic meters): (a) Thermosetting fittings for plastic (1) The vault or pit must be venti- pipe must conform to ASTM D 2517, lated with two ducts, each having at (incorporated by reference, see § 192.7). least the ventilating effect of a pipe 4 (b) Thermoplastic fittings for plastic inches (102 millimeters) in diameter; pipe must conform to ASTM D 2513–99, (2) The ventilation must be enough to (incorporated by reference, see § 192.7). minimize the formation of combustible atmosphere in the vault or pit; and [Amdt. 192–114, 75 FR 48603, Aug. 11, 2010] (3) The ducts must be high enough above grade to disperse any gas-air § 192.193 Valve installation in plastic mixtures that might be discharged. pipe. (b) When the internal volume is more Each valve installed in plastic pipe than 75 cubic feet (2.1 cubic meters) but must be designed so as to protect the less than 200 cubic feet (5.7 cubic me- plastic material against excessive tor- ters): sional or shearing loads when the valve (1) If the vault or pit is sealed, each or shutoff is operated, and from any opening must have a tight fitting cover other secondary stresses that might be without open holes through which an exerted through the valve or its enclo- explosive mixture might be ignited, sure.

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§ 192.195 Protection against accidental of any connected and properly adjusted overpressuring. gas utilization equipment. (a) General requirements. Except as (6) A self-contained service regulator provided in § 192.197, each pipeline that with no external static or control lines. is connected to a gas source so that the (b) If the maximum actual operating maximum allowable operating pressure pressure of the distribution system is could be exceeded as the result of pres- 60 p.s.i. (414 kPa) gage, or less, and a sure control failure or of some other service regulator that does not have all type of failure, must have pressure re- of the characteristics listed in para- lieving or pressure limiting devices graph (a) of this section is used, or if that meet the requirements of §§ 192.199 the gas contains materials that seri- and 192.201. ously interfere with the operation of (b) Additional requirements for distribu- service regulators, there must be suit- tion systems. Each distribution system able protective devices to prevent un- that is supplied from a source of gas safe overpressuring of the customer’s that is at a higher pressure than the appliances if the service regulator maximum allowable operating pressure fails. for the system must— (c) If the maximum actual operating (1) Have pressure regulation devices pressure of the distribution system ex- capable of meeting the pressure, load, ceeds 60 p.s.i. (414 kPa) gage, one of the and other service conditions that will following methods must be used to reg- be experienced in normal operation of ulate and limit, to the maximum safe the system, and that could be activated value, the pressure of gas delivered to in the event of failure of some portion the customer: of the system; and (1) A service regulator having the (2) Be designed so as to prevent acci- characteristics listed in paragraph (a) dental overpressuring. of this section, and another regulator located upstream from the service reg- § 192.197 Control of the pressure of gas ulator. The upstream regulator may delivered from high-pressure dis- not be set to maintain a pressure high- tribution systems. er than 60 p.s.i. (414 kPa) gage. A device (a) If the maximum actual operating must be installed between the up- pressure of the distribution system is stream regulator and the service regu- 60 p.s.i. (414 kPa) gage, or less and a lator to limit the pressure on the inlet service regulator having the following of the service regulator to 60 p.s.i. (414 characteristics is used, no other pres- kPa) gage or less in case the upstream sure limiting device is required: regulator fails to function properly. (1) A regulator capable of reducing This device may be either a relief valve distribution line pressure to pressures or an automatic shutoff that shuts, if recommended for household appliances. the pressure on the inlet of the service (2) A single port valve with proper regulator exceeds the set pressure (60 orifice for the maximum gas pressure p.s.i. (414 kPa) gage or less), and re- at the regulator inlet. mains closed until manually reset. (3) A valve seat made of resilient ma- (2) A service regulator and a moni- terial designed to withstand abrasion toring regulator set to limit, to a max- of the gas, impurities in gas, cutting by imum safe value, the pressure of the the valve, and to resist permanent de- gas delivered to the customer. formation when it is pressed against (3) A service regulator with a relief the valve port. valve vented to the outside atmos- (4) Pipe connections to the regulator phere, with the relief valve set to open not exceeding 2 inches (51 millimeters) so that the pressure of gas going to the in diameter. customer does not exceed a maximum (5) A regulator that, under normal safe value. The relief valve may either operating conditions, is able to regu- be built into the service regulator or it late the downstream pressure within may be a separate unit installed down- the necessary limits of accuracy and to stream from the service regulator. This limit the build-up of pressure under no- combination may be used alone only in flow conditions to prevent a pressure those cases where the inlet pressure on that would cause the unsafe operation the service regulator does not exceed

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the manufacturer’s safe working pres- (h) Except for a valve that will iso- sure rating of the service regulator, late the system under protection from and may not be used where the inlet its source of pressure, be designed to pressure on the service regulator ex- prevent unauthorized operation of any ceeds 125 p.s.i. (862 kPa) gage. For high- stop valve that will make the pressure er inlet pressures, the methods in para- relief valve or pressure limiting device graph (c) (1) or (2) of this section must inoperative. be used. [35 FR 13257, Aug. 19, 1970, as amended by (4) A service regulator and an auto- Amdt. 192–1, 35 FR 17660, Nov. 17, 1970] matic shutoff device that closes upon a rise in pressure downstream from the § 192.201 Required capacity of pres- regulator and remains closed until sure relieving and limiting stations. manually reset. (a) Each pressure relief station or [35 FR 13257, Aug. 19, 1970, as amended by pressure limiting station or group of Amdt. 192–1, 35 FR 17660, Nov. 7, 1970; Amdt those stations installed to protect a 192–85, 63 FR 37503, July 13, 1998; Amdt. 192– pipeline must have enough capacity, 93, 68 FR 53900, Sept. 15, 2003] and must be set to operate, to insure the following: § 192.199 Requirements for design of (1) In a low pressure distribution sys- pressure relief and limiting devices. tem, the pressure may not cause the Except for rupture discs, each pres- unsafe operation of any connected and sure relief or pressure limiting device properly adjusted gas utilization equip- must: ment. (a) Be constructed of materials such (2) In pipelines other than a low pres- that the operation of the device will sure distribution system: not be impaired by corrosion; (i) If the maximum allowable oper- (b) Have valves and valve seats that ating pressure is 60 p.s.i. (414 kPa) gage are designed not to stick in a position or more, the pressure may not exceed that will make the device inoperative; the maximum allowable operating (c) Be designed and installed so that pressure plus 10 percent, or the pres- it can be readily operated to determine sure that produces a hoop stress of 75 if the valve is free, can be tested to de- percent of SMYS, whichever is lower; termine the pressure at which it will (ii) If the maximum allowable oper- operate, and can be tested for leakage ating pressure is 12 p.s.i. (83 kPa) gage when in the closed position; or more, but less than 60 p.s.i. (414 kPa) (d) Have support made of noncombus- gage, the pressure may not exceed the tible material; maximum allowable operating pressure (e) Have discharge stacks, vents, or plus 6 p.s.i. (41 kPa) gage; or outlet ports designed to prevent accu- (iii) If the maximum allowable oper- mulation of water, ice, or snow, located ating pressure is less than 12 p.s.i. (83 where gas can be discharged into the kPa) gage, the pressure may not exceed atmosphere without undue hazard; the maximum allowable operating (f) Be designed and installed so that pressure plus 50 percent. the size of the openings, pipe, and fit- (b) When more than one pressure reg- tings located between the system to be ulating or compressor station feeds protected and the pressure relieving de- into a pipeline, relief valves or other vice, and the size of the vent line, are protective devices must be installed at adequate to prevent hammering of the each station to ensure that the com- valve and to prevent impairment of re- plete failure of the largest capacity lief capacity; regulator or compressor, or any single (g) Where installed at a district regu- run of lesser capacity regulators or lator station to protect a pipeline sys- compressors in that station, will not tem from overpressuring, be designed impose pressures on any part of the and installed to prevent any single in- pipeline or distribution system in ex- cident such as an explosion in a vault cess of those for which it was designed, or damage by a vehicle from affecting or against which it was protected, the operation of both the overpressure whichever is lower. protective device and the district regu- (c) Relief valves or other pressure lator; and limiting devices must be installed at or

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near each regulator station in a low- suitable for the anticipated pressure pressure distribution system, with a and temperature condition. Slip type capacity to limit the maximum pres- expansion joints may not be used. Ex- sure in the main to a pressure that will pansion must be allowed for by pro- not exceed the safe operating pressure viding flexibility within the system for any connected and properly ad- itself. justed gas utilization equipment. (9) Each control line must be protected from anticipated causes of dam- [35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192–9, 37 FR 20827, Oct. 4, 1972; Amdt age and must be designed and installed 192–85, 63 FR 37503, July 13, 1998] to prevent damage to any one control line from making both the regulator § 192.203 Instrument, control, and sam- and the over-pressure protective device pling pipe and components. inoperative. (a) Applicability. This section applies [35 FR 13257, Aug. 19, 1970, as amended by to the design of instrument, control, Amdt. 192–78, 61 FR 28784, June 6, 1996; Amdt. and sampling pipe and components. It 192–85, 63 FR 37503, July 13, 1998] does not apply to permanently closed systems, such as fluid-filled tempera- Subpart E—Welding of Steel in ture-responsive devices. Pipelines (b) Materials and design. All materials employed for pipe and components § 192.221 Scope. must be designed to meet the par- (a) This subpart prescribes minimum ticular conditions of service and the requirements for welding steel mate- following: rials in pipelines. (1) Each takeoff connection and at- (b) This subpart does not apply to taching boss, fitting, or adapter must welding that occurs during the manu- be made of suitable material, be able to facture of steel pipe or steel pipeline withstand the maximum service pres- components. sure and temperature of the pipe or equipment to which it is attached, and § 192.225 Welding procedures. be designed to satisfactorily withstand (a) Welding must be performed by a all stresses without failure by fatigue. qualified welder in accordance with (2) Except for takeoff lines that can welding procedures qualified under sec- be isolated from sources of pressure by tion 5 of API 1104 (incorporated by ref- other valving, a shutoff valve must be erence, see § 192.7) or section IX of the installed in each takeoff line as near as ASME Boiler and Pressure Vessel Code practicable to the point of takeoff. ‘‘ Welding and Brazing Qualifications’’ Blowdown valves must be installed (incorporated by reference, see § 192.7) where necessary. to produce welds meeting the require- (3) Brass or copper material may not ments of this subpart. The quality of be used for metal temperatures greater the test welds used to qualify welding than 400 °F (204°C). procedures shall be determined by de- (4) Pipe or components that may con- structive testing in accordance with tain liquids must be protected by heat- the applicable welding standard(s). ing or other means from damage due to (b) Each welding procedure must be freezing. recorded in detail, including the results (5) Pipe or components in which liq- of the qualifying tests. This record uids may accumulate must have drains must be retained and followed when- or drips. (6) Pipe or components subject to ever the procedure is used. clogging from solids or deposits must [Amdt. 192–52, 51 FR 20297, June 4, 1986; have suitable connections for cleaning. Amdt. 192–94, 69 FR 32894, June 14, 2004] (7) The arrangement of pipe, components, and supports must provide safe- § 192.227 Qualification of welders. ty under anticipated operating (a) Except as provided in paragraph stresses. (b) of this section, each welder must be (8) Each joint between sections of qualified in accordance with section 6 pipe, and between pipe and valves or of API 1104 (incorporated by reference, fittings, must be made in a manner see § 192.7) or section IX of the ASME

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Boiler and Pressure Vessel Code (incor- stress of less than 20 percent of SMYS porated by reference, see § 192.7). How- unless the welder is tested in accord- ever, a welder qualified under an ear- ance with paragraph (c)(1) of this sec- lier edition than listed in § 192.7 of this tion or requalifies under paragraph part may weld but may not requalify (d)(1) or (d)(2) of this section. under that earlier edition. (d) A welder qualified under (b) A welder may qualify to perform § 192.227(b) may not weld unless— welding on pipe to be operated at a (1) Within the preceding 15 calendar pressure that produces a hoop stress of months, but at least once each cal- less than 20 percent of SMYS by per- endar year, the welder has requalified forming an acceptable test weld, for under § 192.227(b); or the process to be used, under the test (2) Within the preceding 71⁄2 calendar set forth in section I of Appendix C of months, but at least twice each cal- this part. Each welder who is to make endar year, the welder has had— a welded service line connection to a (i) A production weld cut out, tested, main must first perform an acceptable and found acceptable in accordance test weld under section II of Appendix with the qualifying test; or C of this part as a requirement of the (ii) For welders who work only on qualifying test. service lines 2 inches (51 millimeters) or smaller in diameter, two sample [35 FR 13257, Aug. 19, 1970, as amended by welds tested and found acceptable in Amdt. 192–43, 47 FR 46851, Oct. 21, 1982; Amdt. 192–52, 51 FR 20297, June 4, 1986; Amdt. 192–78, accordance with the test in section III 61 FR 28784, June 6, 1996; Amdt. 192–94, 69 FR of Appendix C of this part. 32894, June 14, 2004; Amdt. 192–103, 72 FR 4656, [35 FR 13257, Aug. 19, 1970, as amended by Feb. 1, 2007] Amdt. 192–37, 46 FR 10159, Feb. 2, 1981; Amdt. 192–78, 61 FR 28784, June 6, 1996; Amdt. 192–85, § 192.229 Limitations on welders. 63 FR 37503, July 13, 1998; Amdt. 192–94, 69 FR (a) No welder whose qualification is 32895, June 14, 2004] based on nondestructive testing may weld compressor station pipe and com- § 192.231 Protection from weather. ponents. The welding operation must be pro- (b) No welder may weld with a par- tected from weather conditions that ticular welding process unless, within would impair the quality of the com- the preceding 6 calendar months, he pleted weld. has engaged in welding with that process. § 192.233 Miter joints. (c) A welder qualified under (a) A miter joint on steel pipe to be § 192.227(a)— operated at a pressure that produces a (1) May not weld on pipe to be oper- hoop stress of 30 percent or more of ated at a pressure that produces a hoop SMYS may not deflect the pipe more stress of 20 percent or more of SMYS than 3°. unless within the preceding 6 calendar (b) A miter joint on steel pipe to be months the welder has had one weld operated at a pressure that produces a tested and found acceptable under the hoop stress of less than 30 percent, but sections 6 or 9 of API Standard 1104 (in- more than 10 percent, of SMYS may corporated by reference, see § 192.7). Al- not deflect the pipe more than 121⁄2° and ternatively, welders may maintain an must be a distance equal to one pipe di- ongoing qualification status by per- ameter or more away from any other forming welds tested and found accept- miter joint, as measured from the able under the above acceptance cri- crotch of each joint. teria at least twice each calendar year, (c) A miter joint on steel pipe to be but at intervals not exceeding 71⁄2 operated at a pressure that produces a months. A welder qualified under an hoop stress of 10 percent or less of earlier edition of a standard listed in SMYS may not deflect the pipe more § 192.7 of this part may weld but may than 90°. not requalify under that earlier edition; and § 192.235 Preparation for welding. (2) May not weld on pipe to be oper- Before beginning any welding, the ated at a pressure that produces a hoop welding surfaces must be clean and free

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of any material that may be detri- (b) Nondestructive testing of welds mental to the weld, and the pipe or must be performed: component must be aligned to provide (1) In accordance with written proce- the most favorable condition for depos- dures; and iting the root bead. This alignment (2) By persons who have been trained must be preserved while the root bead and qualified in the established proce- is being deposited. dures and with the equipment employed in testing. § 192.241 Inspection and test of welds. (c) Procedures must be established (a) Visual inspection of welding must for the proper interpretation of each be conducted by an individual qualified nondestructive test of a weld to ensure by appropriate training and experience the acceptability of the weld under to ensure that: § 192.241(c). (1) The welding is performed in ac- (d) When nondestructive testing is re- cordance with the welding procedure; quired under § 192.241(b), the following and percentages of each day’s field butt (2) The weld is acceptable under para- welds, selected at random by the oper- graph (c) of this section. ator, must be nondestructively tested (b) The welds on a pipeline to be op- over their entire circumference: erated at a pressure that produces a (1) In Class 1 locations, except off- hoop stress of 20 percent or more of shore, at least 10 percent. SMYS must be nondestructively tested (2) In Class 2 locations, at least 15 in accordance with § 192.243, except that percent. welds that are visually inspected and (3) In Class 3 and Class 4 locations, at approved by a qualified welding inspec- crossings of major or navigable rivers, tor need not be nondestructively tested offshore, and within railroad or public if: highway rights-of-way, including tun- (1) The pipe has a nominal diameter nels, bridges, and overhead road cross- of less than 6 inches (152 millimeters); ings, 100 percent unless impracticable, or in which case at least 90 percent. Non- (2) The pipeline is to be operated at a destructive testing must be impracti- pressure that produces a hoop stress of cable for each girth weld not tested. less than 40 percent of SMYS and the (4) At pipeline tie-ins, including tie- welds are so limited in number that ins of replacement sections, 100 per- nondestructive testing is impractical. (c) The acceptability of a weld that is cent. nondestructively tested or visually in- (e) Except for a welder whose work is spected is determined according to the isolated from the principal welding ac- standards in Section 9 of API Standard tivity, a sample of each welder’s work 1104 (incorporated by reference, see for each day must be nondestructively § 192.7). However, if a girth weld is un- tested, when nondestructive testing is acceptable under those standards for a required under § 192.241(b). reason other than a crack, and if Ap- (f) When nondestructive testing is re- pendix A to API 1104 applies to the quired under § 192.241(b), each operator weld, the acceptability of the weld may must retain, for the life of the pipeline, be further determined under that ap- a record showing by milepost, engi- pendix. neering station, or by geographic feature, the number of girth welds made, [35 FR 13257, Aug. 19, 1970, as amended by the number nondestructively tested, Amdt. 192–37, 46 FR 10160, Feb. 2, 1981; Amdt. the number rejected, and the disposi- 192–78, 61 FR 28784, June 6, 1996; Amdt. 192–85, tion of the rejects. 63 FR 37503, July 13, 1998; Amdt. 192–94, 69 FR 32894, June 14, 2004] [35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192–27, 41 FR 34606, Aug. 16, 1976; § 192.243 Nondestructive testing. Amdt. 192–50, 50 FR 37192, Sept. 12, 1985; (a) Nondestructive testing of welds Amdt. 192–78, 61 FR 28784, June 6, 1996] must be performed by any process, other than trepanning, that will clear- § 192.245 Repair or removal of defects. ly indicate defects that may affect the (a) Each weld that is unacceptable integrity of the weld. under § 192.241(c) must be removed or

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repaired. Except for welds on an off- dium. Each gasket must be suitably shore pipeline being installed from a confined and retained under compres- pipeline vessel, a weld must be re- sion by a separate gland or follower moved if it has a crack that is more ring. than 8 percent of the weld length. (c) Cast iron pipe may not be joined (b) Each weld that is repaired must by threaded joints. have the defect removed down to sound (d) Cast iron pipe may not be joined metal and the segment to be repaired by brazing. must be preheated if conditions exist [35 FR 13257, Aug. 19, 1970, as amended by which would adversely affect the qual- Amdt. 192–62, 54 FR 5628, Feb. 6, 1989] ity of the weld repair. After repair, the segment of the weld that was repaired § 192.277 Ductile iron pipe. must be inspected to ensure its accept- (a) Ductile iron pipe may not be ability. joined by threaded joints. (c) Repair of a crack, or of any defect (b) Ductile iron pipe may not be in a previously repaired area must be joined by brazing. in accordance with written weld repair procedures that have been qualified [35 FR 13257, Aug. 19, 1970, as amended by under § 192.225. Repair procedures must Amdt. 192–62, 54 FR 5628, Feb. 6, 1989] provide that the minimum mechanical § 192.279 Copper pipe. properties specified for the welding procedure used to make the original Copper pipe may not be threaded ex- weld are met upon completion of the cept that copper pipe used for joining final weld repair. screw fittings or valves may be threaded if the wall thickness is equivalent to [Amdt. 192–46, 48 FR 48674, Oct. 20, 1983] the comparable size of Schedule 40 or heavier wall pipe listed in Table C1 of Subpart F—Joining of Materials ASME/ANSI B16.5. Other Than by Welding [Amdt. 192–62, 54 FR 5628, Feb. 6, 1989, as amended at 58 FR 14521, Mar. 18, 1993] § 192.271 Scope. (a) This subpart prescribes minimum § 192.281 Plastic pipe. requirements for joining materials in (a) General. A plastic pipe joint that pipelines, other than by welding. is joined by solvent cement, adhesive, (b) This subpart does not apply to or heat fusion may not be disturbed joining during the manufacture of pipe until it has properly set. Plastic pipe or pipeline components. may not be joined by a threaded joint or miter joint. § 192.273 General. (b) Solvent cement joints. Each solvent (a) The pipeline must be designed and cement joint on plastic pipe must com- installed so that each joint will sustain ply with the following: the longitudinal pullout or thrust (1) The mating surfaces of the joint forces caused by contraction or expan- must be clean, dry, and free of material sion of the piping or by anticipated ex- which might be detrimental to the ternal or internal loading. joint. (b) Each joint must be made in ac- (2) The solvent cement must conform cordance with written procedures that to ASTM D2513–99, (incorporated by have been proven by test or experience reference, see § 192.7). to produce strong gastight joints. (3) The joint may not be heated to ac- (c) Each joint must be inspected to celerate the setting of the cement. insure compliance with this subpart. (c) Heat-fusion joints. Each heat-fusion joint on plastic pipe must comply § 192.275 Cast iron pipe. with the following: (a) Each caulked bell and spigot joint (1) A butt heat-fusion joint must be in cast iron pipe must be sealed with joined by a device that holds the heater mechanical leak clamps. element square to the ends of the pip- (b) Each mechanical joint in cast ing, compresses the heated ends to- iron pipe must have a gasket made of a gether, and holds the pipe in proper resilient material as the sealing me- alignment while the plastic hardens.

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(2) A socket heat-fusion joint must be drostatic Burst Pressure) or paragraph joined by a device that heats the mat- 8.9 (Sustained Static Pressure Test) of ing surfaces of the joint uniformly and ASTM D2517 (incorporated by ref- simultaneously to essentially the same erence, see § 192.7); or temperature. (iii) In the case of electrofusion fit- (3) An electrofusion joint must be tings for polyethylene (PE) pipe and joined utilizing the equipment and tubing, paragraph 9.1 (Minimum Hy- techniques of the fittings manufacturer draulic Burst Pressure Test), para- or equipment and techniques shown, by graph 9.2 (Sustained Pressure Test), testing joints to the requirements of paragraph 9.3 (Tensile Strength Test), § 192.283(a)(1)(iii), to be at least equiva- or paragraph 9.4 (Joint Integrity Tests) lent to those of the fittings manufac- of ASTM Designation F1055 (incor- turer. porated by reference, see § 192.7). (4) Heat may not be applied with a (2) For procedures intended for lat- torch or other open flame. eral pipe connections, subject a speci- (d) Adhesive joints. Each adhesive men joint made from pipe sections joint on plastic pipe must comply with joined at right angles according to the the following: procedure to a force on the lateral pipe (1) The adhesive must conform to until failure occurs in the specimen. If ASTM Designation D 2517. failure initiates outside the joint area, (2) The materials and adhesive must the procedure qualifies for use; and be compatible with each other. (3) For procedures intended for non- (e) Mechanical joints. Each compres- lateral pipe connections, follow the sion type mechanical joint on plastic tensile test requirements of ASTM pipe must comply with the following: D638 (incorporated by reference, see (1) The gasket material in the cou- § 192.7), except that the test may be pling must be compatible with the conducted at ambient temperature and plastic. humidity If the specimen elongates no (2) A rigid internal tubular stiffener, less than 25 percent or failure initiates other than a split tubular stiffener, outside the joint area, the procedure must be used in conjunction with the qualifies for use. coupling. (b) Mechanical joints. Before any writ- [35 FR 13257, Aug. 19, 1970, as amended by ten procedure established under Amdt. 192–34, 44 FR 42973, July 23, 1979; § 192.273(b) is used for making mechan- Amdt. 192–58, 53 FR 1635, Jan. 21, 1988; Amdt. ical plastic pipe joints that are de- 192–61, 53 FR 36793, Sept. 22, 1988; 58 FR 14521, signed to withstand tensile forces, the Mar. 18, 1993; Amdt. 192–78, 61 FR 28784, June 6, 1996; Amdt. 192–114, 75 FR 48603, Aug. 11, procedure must be qualified by sub- 2010] jecting 5 specimen joints made according to the procedure to the following § 192.283 Plastic pipe: Qualifying join- tensile test: ing procedures. (1) Use an apparatus for the test as (a) Heat fusion, solvent cement, and ad- specified in ASTM D 638 (except for hesive joints. Before any written proce- conditioning), (incorporated by ref- dure established under § 192.273(b) is erence, see § 192.7). used for making plastic pipe joints by a (2) The specimen must be of such heat fusion, solvent cement, or adhe- length that the distance between the sive method, the procedure must be grips of the apparatus and the end of qualified by subjecting specimen joints the stiffener does not affect the joint made according to the procedure to the strength. following tests: (3) The speed of testing is 0.20 in (5.0 (1) The burst test requirements of— mm) per minute, plus or minus 25 per- (i) In the case of thermoplastic pipe, cent. paragraph 6.6 (sustained pressure test) (4) Pipe specimens less than 4 inches or paragraph 6.7 (Minimum Hydrostatic (102 mm) in diameter are qualified if Burst Test) or paragraph 8.9 (Sustained the pipe yields to an elongation of no Static pressure Test) of ASTM D2513–99 less than 25 percent or failure initiates (incorporated by reference, see § 192.7); outside the joint area. (ii) In the case of thermosetting plas- (5) Pipe specimens 4 inches (102 mm) tic pipe, paragraph 8.5 (Minimum Hy- and larger in diameter shall be pulled

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until the pipe is subjected to a tensile cable to the type of joint and material stress equal to or greater than the being tested; maximum thermal stress that would be (ii) Examined by ultrasonic inspec- produced by a temperature change of tion and found not to contain flaws 100 °F (38 °C) or until the pipe is pulled that would cause failure; or from the fitting. If the pipe pulls from (iii) Cut into at least 3 longitudinal the fitting, the lowest value of the five straps, each of which is: test results or the manufacturer’s rat- (A) Visually examined and found not ing, whichever is lower must be used in to contain voids or discontinuities on the design calculations for stress. the cut surfaces of the joint area; and (6) Each specimen that fails at the (B) Deformed by bending, torque, or grips must be retested using new pipe. impact, and if failure occurs, it must (7) Results obtained pertain only to not initiate in the joint area. the specific outside diameter, and ma- (c) A person must be requalified terial of the pipe tested, except that under an applicable procedure, if dur- testing of a heavier wall pipe may be ing any 12-month period that person: used to qualify pipe of the same mate- (1) Does not make any joints under rial but with a lesser wall thickness. that procedure; or (c) A copy of each written procedure being used for joining plastic pipe must (2) Has 3 joints or 3 percent of the be available to the persons making and joints made, whichever is greater, inspecting joints. under that procedure that are found (d) Pipe or fittings manufactured be- unacceptable by testing under § 192.513. fore July 1, 1980, may be used in ac- (d) Each operator shall establish a cordance with procedures that the method to determine that each person manufacturer certifies will produce a making joints in plastic pipelines in joint as strong as the pipe. the operator’s system is qualified in accordance with this section. [Amdt. 192–34A, 45 FR 9935, Feb. 14, 1980, as amended by Amdt. 192–34B, 46 FR 39, Jan. 2, [Amdt. 192–34A, 45 FR 9935, Feb. 14, 1980, as 1981; 47 FR 32720, July 29, 1982; 47 FR 49973, amended by Amdt. 192–34B, 46 FR 39, Jan. 2, Nov. 4, 1982; 58 FR 14521, Mar. 18, 1993; Amdt. 1981; Amdt. 192–93, 68 FR 53900, Sept. 15, 2003] 192–78, 61 FR 28784, June 6, 1996; Amdt. 192–85, 63 FR 37503, July 13, 1998; Amdt. 192–94, 69 FR § 192.287 Plastic pipe: Inspection of 32895, June 14, 2004; Amdt. 192–94, 69 FR 54592, joints. Sept. 9, 2004; Amdt. 192–114, 75 FR 48603, Aug. No person may carry out the inspec- 11, 2010] tion of joints in plastic pipes required § 192.285 Plastic pipe: Qualifying per- by §§ 192.273(c) and 192.285(b) unless that sons to make joints. person has been qualified by appro- (a) No person may make a plastic priate training or experience in evalu- pipe joint unless that person has been ating the acceptability of plastic pipe qualified under the applicable joining joints made under the applicable join- procedure by: ing procedure. (1) Appropriate training or experi- [Amdt. 192–34, 44 FR 42974, July 23, 1979] ence in the use of the procedure; and (2) Making a specimen joint from Subpart G—General Construction pipe sections joined according to the procedure that passes the inspection Requirements for Transmission and test set forth in paragraph (b) of Lines and Mains this section. § 192.301 Scope. (b) The specimen joint must be: (1) Visually examined during and This subpart prescribes minimum re- after assembly or joining and found to quirements for constructing trans- have the same appearance as a joint or mission lines and mains. photographs of a joint that is acceptable under the procedure; and § 192.303 Compliance with specifica- (2) In the case of a heat fusion, sol- tions or standards. vent cement, or adhesive joint: Each transmission line or main must (i) Tested under any one of the test be constructed in accordance with com- methods listed under § 192.283(a) appli- prehensive written specifications or

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standards that are consistent with this the lowest point of the dent and a pro- part. longation of the original contour of the pipe. § 192.305 Inspection: General. (c) Each arc burn on steel pipe to be Each transmission line or main must operated at a pressure that produces a be inspected to ensure that it is con- hoop stress of 40 percent, or more, of structed in accordance with this part. SMYS must be repaired or removed. If a repair is made by grinding, the arc § 192.307 Inspection of materials. burn must be completely removed and Each length of pipe and each other the remaining wall thickness must be component must be visually inspected at least equal to either: at the site of installation to ensure (1) The minimum wall thickness re- that it has not sustained any visually quired by the tolerances in the speci- determinable damage that could im- fication to which the pipe was manu- pair its serviceability. factured; or (2) The nominal wall thickness re- § 192.309 Repair of steel pipe. quired for the design pressure of the (a) Each imperfection or damage that pipeline. impairs the serviceability of a length (d) A gouge, groove, arc burn, or dent of steel pipe must be repaired or re- may not be repaired by insert patching moved. If a repair is made by grinding, or by pounding out. the remaining wall thickness must at (e) Each gouge, groove, arc burn, or least be equal to either: dent that is removed from a length of (1) The minimum thickness required pipe must be removed by cutting out by the tolerances in the specification the damaged portion as a cylinder. to which the pipe was manufactured; or [35 FR 13257, Aug. 19, 1970, as amended by (2) The nominal wall thickness re- Amdt. 192–1, 35 FR 17660, Nov. 17, 1970; Amdt. quired for the design pressure of the 192–85, 63 FR 37503, July 13, 1998; Amdt. 192– pipeline. 88, 64 FR 69664, Dec. 14, 1999] (b) Each of the following dents must be removed from steel pipe to be oper- § 192.311 Repair of plastic pipe. ated at a pressure that produces a hoop Each imperfection or damage that stress of 20 percent, or more, of SMYS, would impair the serviceability of plas- unless the dent is repaired by a method tic pipe must be repaired or removed. that reliable engineering tests and [Amdt. 192–93, 68 FR 53900, Sept. 15, 2003] analyses show can permanently restore the serviceability of the pipe: § 192.313 Bends and elbows. (1) A dent that contains a stress con- (a) Each field bend in steel pipe, centrator such as a scratch, gouge, other than a wrinkle bend made in ac- groove, or arc burn. cordance with § 192.315, must comply (2) A dent that affects the longitu- with the following: dinal weld or a circumferential weld. (1) A bend must not impair the serv- (3) In pipe to be operated at a pres- iceability of the pipe. sure that produces a hoop stress of 40 (2) Each bend must have a smooth percent or more of SMYS, a dent that contour and be free from buckling, has a depth of: cracks, or any other mechanical dam- (i) More than 1⁄4 inch (6.4 millimeters) age. in pipe 123⁄4 inches (324 millimeters) or (3) On pipe containing a longitudinal less in outer diameter; or weld, the longitudinal weld must be as (ii) More than 2 percent of the nomi- near as practicable to the neutral axis nal pipe diameter in pipe over 123⁄4 of the bend unless: inches (324 millimeters) in outer di- (i) The bend is made with an internal ameter. bending mandrel; or For the purpose of this section a (ii) The pipe is 12 inches (305 millime- ‘‘dent’’ is a depression that produces a ters) or less in outside diameter or has gross disturbance in the curvature of a diameter to wall thickness ratio less the pipe wall without reducing the than 70. pipe-wall thickness. The depth of a (b) Each circumferential weld of steel dent is measured as the gap between pipe which is located where the stress

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during bending causes a permanent de- distance from the traffic or by install- formation in the pipe must be non- ing barricades. destructively tested either before or (c) Pipelines, including pipe risers, on after the bending process. each platform located offshore or in in- (c) Wrought-steel welding elbows and land navigable waters must be pro- transverse segments of these elbows tected from accidental damage by ves- may not be used for changes in direc- sels. tion on steel pipe that is 2 inches (51 [Amdt. 192–27, 41 FR 34606, Aug. 16, 1976, as millimeters) or more in diameter un- amended by Amdt. 192–78, 61 FR 28784, June less the arc length, as measured along 6, 1996] the crotch, is at least 1 inch (25 millimeters). § 192.319 Installation of pipe in a ditch. [Amdt. No. 192–26, 41 FR 26018, June 24, 1976, as amended by Amdt. 192–29, 42 FR 42866, (a) When installed in a ditch, each Aug. 25, 1977; Amdt. 192–29, 42 FR 60148, Nov. transmission line that is to be operated 25, 1977; Amdt. 192–49, 50 FR 13225, Apr. 3, at a pressure producing a hoop stress of 1985; Amdt. 192–85, 63 FR 37503, July 13, 1998] 20 percent or more of SMYS must be installed so that the pipe fits the ditch § 192.315 Wrinkle bends in steel pipe. so as to minimize stresses and protect (a) A wrinkle bend may not be made the pipe coating from damage. on steel pipe to be operated at a pres- (b) When a ditch for a transmission sure that produces a hoop stress of 30 line or main is backfilled, it must be percent, or more, of SMYS. backfilled in a manner that: (b) Each wrinkle bend on steel pipe (1) Provides firm support under the must comply with the following: pipe; and (1) The bend must not have any sharp (2) Prevents damage to the pipe and kinks. pipe coating from equipment or from (2) When measured along the crotch the backfill material. of the bend, the wrinkles must be a dis- (c) All offshore pipe in water at least tance of at least one pipe diameter. 12 feet (3.7 meters) deep but not more (3) On pipe 16 inches (406 millimeters) than 200 feet (61 meters) deep, as meas- or larger in diameter, the bend may ured from the mean low tide, except not have a deflection of more than 11⁄2° pipe in the Gulf of Mexico and its inlets for each wrinkle. under 15 feet (4.6 meters) of water, (4) On pipe containing a longitudinal must be installed so that the top of the weld the longitudinal seam must be as pipe is below the natural bottom unless near as practicable to the neutral axis the pipe is supported by stanchions, of the bend. held in place by anchors or heavy con- [35 FR 13257, Aug. 19, 1970, as amended by crete coating, or protected by an equiv- Amdt. 192–85, 63 FR 37503, July 13, 1998] alent means. Pipe in the Gulf of Mexico and its inlets under 15 feet (4.6 meters) § 192.317 Protection from hazards. of water must be installed so that the (a) The operator must take all prac- top of the pipe is 36 inches (914 milli- ticable steps to protect each trans- meters) below the seabed for normal mission line or main from washouts, excavation or 18 inches (457 millime- floods, unstable soil, landslides, or ters) for rock excavation. other hazards that may cause the pipe- [35 FR 13257, Aug. 19, 1970, as amended by line to move or to sustain abnormal Amdt. 192–27, 41 FR 34606, Aug. 16, 1976; loads. In addition, the operator must Amdt. 192–78, 61 FR 28784, June 6, 1996; Amdt. take all practicable steps to protect 192–85, 63 FR 37503, July 13, 1998] offshore pipelines from damage by mud slides, water currents, hurricanes, ship § 192.321 Installation of plastic pipe. anchors, and fishing operations. (a) Plastic pipe must be installed (b) Each aboveground transmission below ground level except as provided line or main, not located offshore or in by paragraphs (g) and (h) of this sec- inland navigable water areas, must be tion. protected from accidental damage by (b) Plastic pipe that is installed in a vehicular traffic or other similar vault or any other below grade enclo- causes, either by being placed at a safe sure must be completely encased in

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gas-tight metal pipe and fittings that (3) Not allowed to exceed the pipe are adequately protected from corro- temperature limits specified in sion. § 192.123. (c) Plastic pipe must be installed so [35 FR 13257, Aug. 19, 1970, as amended by as to minimize shear or tensile Amdt. 192–78, 61 FR 28784, June 6, 1996; Amdt. stresses. 192–85, 63 FR 37503, July 13, 1998; Amdt. 192– (d) Thermoplastic pipe that is not en- 93, 68 FR 53900, Sept. 15, 2003; Amdt. 192–94, 69 cased must have a minimum wall FR 32895, June 14, 2004] thickness of 0.090 inch (2.29 millimeters), except that pipe with an outside § 192.323 Casing. diameter of 0.875 inch (22.3 millimeters) Each casing used on a transmission or less may have a minimum wall line or main under a railroad or high- thickness of 0.062 inch (1.58 millime- way must comply with the following: ters). (a) The casing must be designed to (e) Plastic pipe that is not encased withstand the superimposed loads. must have an electrically conducting (b) If there is a possibility of water wire or other means of locating the entering the casing, the ends must be pipe while it is underground. Tracer sealed. wire may not be wrapped around the (c) If the ends of an unvented casing pipe and contact with the pipe must be are sealed and the sealing is strong minimized but is not prohibited. Tracer enough to retain the maximum allow- wire or other metallic elements in- able operating pressure of the pipe, the stalled for pipe locating purposes must casing must be designed to hold this be resistant to corrosion damage, ei- pressure at a stress level of not more ther by use of coated copper wire or by than 72 percent of SMYS. other means. (d) If vents are installed on a casing, (f) Plastic pipe that is being encased the vents must be protected from the must be inserted into the casing pipe in weather to prevent water from enter- a manner that will protect the plastic. ing the casing. The leading end of the plastic must be closed before insertion. § 192.325 Underground clearance. (g) Uncased plastic pipe may be tem- (a) Each transmission line must be porarily installed above ground level installed with at least 12 inches (305 under the following conditions: millimeters) of clearance from any (1) The operator must be able to dem- other underground structure not asso- onstrate that the cumulative above- ciated with the transmission line. If ground exposure of the pipe does not this clearance cannot be attained, the exceed the manufacturer’s rec- transmission line must be protected ommended maximum period of expo- from damage that might result from sure or 2 years, whichever is less. the proximity of the other structure. (2) The pipe either is located where (b) Each main must be installed with damage by external forces is unlikely enough clearance from any other un- or is otherwise protected against such derground structure to allow proper damage. maintenance and to protect against (3) The pipe adequately resists expo- damage that might result from prox- sure to ultraviolet light and high and imity to other structures. low temperatures. (c) In addition to meeting the re- (h) Plastic pipe may be installed on quirements of paragraph (a) or (b) of bridges provided that it is: this section, each plastic transmission (1) Installed with protection from line or main must be installed with suf- mechanical damage, such as installa- ficient clearance, or must be insulated, tion in a metallic casing; from any source of heat so as to pre- (2) Protected from ultraviolet radi- vent the heat from impairing the serv- ation; and iceability of the pipe.

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(d) Each pipe-type or bottle-type consolidated rock between the top of holder must be installed with a min- the pipe and the underwater natural imum clearance from any other holder bottom (as determined by recognized as prescribed in § 192.175(b). and generally accepted practices). [35 FR 13257, Aug. 19, 1970, as amended by (f) All pipe installed offshore, except Amdt. 192–85, 63 FR 37503, July 13, 1998] in the Gulf of Mexico and its inlets, under water not more than 200 feet (60 § 192.327 Cover. meters) deep, as measured from the (a) Except as provided in paragraphs mean low tide, must be installed as fol- (c), (e), (f), and (g) of this section, each lows: buried transmission line must be in- (1) Except as provided in paragraph stalled with a minimum cover as fol- (c) of this section, pipe under water lows: less than 12 feet (3.66 meters) deep, must be installed with a minimum Consoli- Location Normal soil dated rock cover of 36 inches (914 millimeters) in soil or 18 inches (457 millimeters) in Inches (Millimeters). consolidated rock between the top of Class 1 locations ...... 30 (762) 18 (457) Class 2, 3, and 4 locations ...... 36 (914) 24 (610) the pipe and the natural bottom. Drainage ditches of public roads (2) Pipe under water at least 12 feet and railroad crossings ...... 36 (914) 24 (610) (3.66 meters) deep must be installed so (b) Except as provided in paragraphs that the top of the pipe is below the (c) and (d) of this section, each buried natural bottom, unless the pipe is sup- main must be installed with at least 24 ported by stanchions, held in place by inches (610 millimeters) of cover. anchors or heavy concrete coating, or (c) Where an underground structure protected by an equivalent means. prevents the installation of a trans- (g) All pipelines installed under mission line or main with the min- water in the Gulf of Mexico and its in- imum cover, the transmission line or lets, as defined in § 192.3, must be in- main may be installed with less cover stalled in accordance with if it is provided with additional protec- § 192.612(b)(3). tion to withstand anticipated external [35 FR 13257, Aug. 19, 1970, as amended by loads. Amdt. 192–27, 41 FR 34606, Aug. 16, 1976; (d) A main may be installed with less Amdt. 192–78, 61 FR 28785, June 6, 1996; Amdt. than 24 inches (610 millimeters) of 192–85, 63 FR 37503, July 13, 1998; Amdt. 192– cover if the law of the State or munici- 98, 69 FR 48406, Aug. 10, 2004] pality: (1) Establishes a minimum cover of § 192.328 Additional construction re- less than 24 inches (610 millimeters); quirements for steel pipe using al- (2) Requires that mains be installed ternative maximum allowable oper- in a common trench with other utility ating pressure. lines; and For a new or existing pipeline seg- (3) Provides adequately for preven- ment to be eligible for operation at the tion of damage to the pipe by external alternative maximum allowable oper- forces. ating pressure calculated under (e) Except as provided in paragraph § 192.620, a segment must meet the fol- (c) of this section, all pipe installed in lowing additional construction require- a navigable river, stream, or harbor ments. Records must be maintained, must be installed with a minimum for the useful life of the pipeline, dem- cover of 48 inches (1,219 millimeters) in onstrating compliance with these re- soil or 24 inches (610 millimeters) in quirements:

To address this construction issue: The pipeline segment must meet this additional construction requirement:

(a) Quality assurance ...... (1) The construction of the pipeline segment must be done under a quality assurance plan addressing pipe inspection, hauling and stringing, field bending, welding, non-destructive examination of girth welds, applying and testing field applied coating, lowering of the pipeline into the ditch, padding and backfilling, and hydrostatic testing. (2) The quality assurance plan for applying and testing field applied coating to girth welds must be: (i) Equivalent to that required under § 192.112(f)(3) for pipe; and

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To address this construction issue: The pipeline segment must meet this additional construction requirement:

(ii) Performed by an individual with the knowledge, skills, and ability to assure effective coating application. (b) Girth welds ...... (1) All girth welds on a new pipeline segment must be non-destructively examined in accordance with § 192.243(b) and (c). (c) Depth of cover ...... (1) Notwithstanding any lesser depth of cover otherwise allowed in § 192.327, there must be at least 36 inches (914 millimeters) of cover or equivalent means to protect the pipeline from outside force damage. (2) In areas where deep tilling or other activities could threaten the pipeline, the top of the pipeline must be installed at least one foot below the deepest expected penetration of the soil. (d) Initial strength testing ...... (1) The pipeline segment must not have experienced failures indicative of systemic material defects during strength testing, including initial hydrostatic testing. A root cause analysis, including metallurgical examination of the failed pipe, must be performed for any failure experienced to verify that it is not indicative of a systemic concern. The results of this root cause analysis must be reported to each PHMSA pipeline safety regional office where the pipe is in service at least 60 days prior to operating at the alternative MAOP. An operator must also notify a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State. (e) Interference currents ...... (1) For a new pipeline segment, the construction must address the impacts of induced alternating current from parallel electric transmission lines and other known sources of potential interference with corrosion control.

[72 FR 62176, Oct. 17, 2008] a separate metering or regulating building. Subpart H—Customer Meters, [35 FR 13257, Aug. 19, 1970, as amended by Service Regulators, and Serv- Amdt 192–85, 63 FR 37503, July 13, 1998; Amdt. ice Lines 192–93, 68 FR 53900, Sept. 15, 2003]

§ 192.351 Scope. § 192.355 Customer meters and regu- This subpart prescribes minimum re- lators: Protection from damage. quirements for installing customer me- (a) Protection from vacuum or back ters, service regulators, service lines, pressure. If the customer’s equipment service line valves, and service line might create either a vacuum or a back connections to mains. pressure, a device must be installed to protect the system. § 192.353 Customer meters and regu- (b) Service regulator vents and relief lators: Location. vents. Service regulator vents and re- (a) Each meter and service regulator, lief vents must terminate outdoors, whether inside or outside a building, and the outdoor terminal must— must be installed in a readily acces- (1) Be rain and insect resistant; sible location and be protected from (2) Be located at a place where gas corrosion and other damage, including, if installed outside a building, vehic- from the vent can escape freely into ular damage that may be anticipated. the atmosphere and away from any However, the upstream regulator in a opening into the building; and series may be buried. (3) Be protected from damage caused (b) Each service regulator installed by submergence in areas where flood- within a building must be located as ing may occur. near as practical to the point of service (c) Pits and vaults. Each pit or vault line entrance. that houses a customer meter or regu- (c) Each meter installed within a lator at a place where vehicular traffic building must be located in a venti- is anticipated, must be able to support lated place and not less than 3 feet (914 that traffic. millimeters) from any source of ignition or any source of heat which might [35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192–58, 53 FR 1635, Jan. 21, 1988] damage the meter. (d) Where feasible, the upstream regulator in a series must be located outside the building, unless it is located in

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§ 192.357 Customer meters and regu- so as to drain into the main or into lators: Installation. drips at the low points in the service (a) Each meter and each regulator line. must be installed so as to minimize an- (d) Protection against piping strain and ticipated stresses upon the connecting external loading. Each service line must piping and the meter. be installed so as to minimize antici- (b) When close all-thread nipples are pated piping strain and external load- used, the wall thickness remaining ing. after the threads are cut must meet (e) Installation of service lines into the minimum wall thickness require- buildings. Each underground service ments of this part. line installed below grade through the (c) Connections made of lead or other outer foundation wall of a building easily damaged material may not be must: used in the installation of meters or (1) In the case of a metal service line, regulators. be protected against corrosion; (d) Each regulator that might release (2) In the case of a plastic service gas in its operation must be vented to line, be protected from shearing action the outside atmosphere. and backfill settlement; and (3) Be sealed at the foundation wall § 192.359 Customer meter installations: Operating pressure. to prevent leakage into the building. (f) Installation of service lines under (a) A meter may not be used at a buildings. Where an underground serv- pressure that is more than 67 percent ice line is installed under a building: of the manufacturer’s shell test pres- (1) It must be encased in a gas tight sure. conduit; (b) Each newly installed meter manufactured after November 12, 1970, must (2) The conduit and the service line have been tested to a minimum of 10 must, if the service line supplies the p.s.i. (69 kPa) gage. building it underlies, extend into a nor- (c) A rebuilt or repaired tinned steel mally usable and accessible part of the case meter may not be used at a pres- building; and sure that is more than 50 percent of the (3) The space between the conduit pressure used to test the meter after and the service line must be sealed to rebuilding or repairing. prevent gas leakage into the building and, if the conduit is sealed at both [35 FR 13257, Aug. 19, 1970, as amended by ends, a vent line from the annular Amdt. 192–1, 35 FR 17660, Nov. 17, 1970; Amdt. space must extend to a point where gas 192–85, 63 FR 37503, July 13, 1998] would not be a hazard, and extend § 192.361 Service lines: Installation. above grade, terminating in a rain and insect resistant fitting. (a) Depth. Each buried service line must be installed with at least 12 (g) Locating underground service lines. inches (305 millimeters) of cover in pri- Each underground nonmetallic service vate property and at least 18 inches line that is not encased must have a (457 millimeters) of cover in streets and means of locating the pipe that com- roads. However, where an underground plies with § 192.321(e). structure prevents installation at [35 FR 13257, Aug. 19, 1970, as amended by those depths, the service line must be Amdt. 192–75, 61 FR 18517, Apr. 26, 1996; Amdt. able to withstand any anticipated ex- 192–85, 63 FR 37503, July 13, 1998; Amdt. 192– ternal load. 93, 68 FR 53900, Sept. 15, 2003] (b) Support and backfill. Each service line must be properly supported on un- § 192.363 Service lines: Valve require- disturbed or well-compacted soil, and ments. material used for backfill must be free (a) Each service line must have a of materials that could damage the service-line valve that meets the appli- pipe or its coating. cable requirements of subparts B and D (c) Grading for drainage. Where con- of this part. A valve incorporated in a densate in the gas might cause inter- meter bar, that allows the meter to be ruption in the gas supply to the cus- bypassed, may not be used as a service- tomer, the service line must be graded line valve.

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(b) A soft seat service line valve may § 192.369 Service lines: Connections to not be used if its ability to control the cast iron or ductile iron mains. flow of gas could be adversely affected (a) Each service line connected to a by exposure to anticipated heat. cast iron or ductile iron main must be (c) Each service-line valve on a high- connected by a mechanical clamp, by pressure service line, installed above drilling and tapping the main, or by ground or in an area where the blowing another method meeting the require- of gas would be hazardous, must be de- ments of § 192.273. signed and constructed to minimize the (b) If a threaded tap is being inserted, possibility of the removal of the core of the requirements of § 192.151 (b) and (c) the valve with other than specialized must also be met. tools. § 192.371 Service lines: Steel. § 192.365 Service lines: Location of Each steel service line to be operated valves. at less than 100 p.s.i. (689 kPa) gage (a) Relation to regulator or meter. Each must be constructed of pipe designed service-line valve must be installed up- for a minimum of 100 p.s.i. (689 kPa) stream of the regulator or, if there is gage. no regulator, upstream of the meter. [Amdt. 192–1, 35 FR 17660, Nov. 17, 1970, as (b) Outside valves. Each service line amended by Amdt. 192–85, 63 FR 37503, July must have a shut-off valve in a readily 13, 1998] accessible location that, if feasible, is outside of the building. § 192.373 Service lines: Cast iron and (c) Underground valves. Each under- ductile iron. ground service-line valve must be lo- (a) Cast or ductile iron pipe less than cated in a covered durable curb box or 6 inches (152 millimeters) in diameter standpipe that allows ready operation may not be installed for service lines. of the valve and is supported independ- (b) If cast iron pipe or ductile iron ently of the service lines. pipe is installed for use as a service line, the part of the service line which § 192.367 Service lines: General re- extends through the building wall must quirements for connections to main be of steel pipe. piping. (c) A cast iron or ductile iron service (a) Location. Each service line con- line may not be installed in unstable nection to a main must be located at soil or under a building. the top of the main or, if that is not [35 FR 13257, Aug. 19, 1970, as amended by practical, at the side of the main, un- Amdt. 192–85, 63 FR 37503, July 13, 1998] less a suitable protective device is installed to minimize the possibility of § 192.375 Service lines: Plastic. dust and moisture being carried from (a) Each plastic service line outside a the main into the service line. building must be installed below (b) Compression-type connection to ground level, except that— main. Each compression-type service (1) It may be installed in accordance line to main connection must: with § 192.321(g); and (1) Be designed and installed to effec- (2) It may terminate above ground tively sustain the longitudinal pull-out level and outside the building, if— or thrust forces caused by contraction (i) The above ground level part of the or expansion of the piping, or by antici- plastic service line is protected against pated external or internal loading; and deterioration and external damage; and (2) If gaskets are used in connecting (ii) The plastic service line is not the service line to the main connection used to support external loads. fitting, have gaskets that are compat- (b) Each plastic service line inside a ible with the kind of gas in the system. building must be protected against external damage. [35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192–75, 61 FR 18517, Apr. 26, 1996] [35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192–78, 61 FR 28785, June 6, 1996]

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§ 192.377 Service lines: Copper. cubic feet per hour (.01 cubic meters Each copper service line installed per hour); and within a building must be protected (4) Not close when the pressure is less against external damage. than the manufacturer’s minimum specified operating pressure and the § 192.379 New service lines not in use. flow rate is below the manufacturer’s minimum specified closure flow rate. Each service line that is not placed in service upon completion of installa- (b) An excess flow valve must meet tion must comply with one of the fol- the applicable requirements of Sub- lowing until the customer is supplied parts B and D of this part. with gas: (c) An operator must mark or other- (a) The valve that is closed to pre- wise identify the presence of an excess vent the flow of gas to the customer flow valve in the service line. must be provided with a locking device (d) An operator shall locate an excess or other means designed to prevent the flow valve as near as practical to the opening of the valve by persons other fitting connecting the service line to than those authorized by the operator. its source of gas supply. (b) A mechanical device or fitting (e) An operator should not install an that will prevent the flow of gas must excess flow valve on a service line be installed in the service line or in the where the operator has prior experi- meter assembly. ence with contaminants in the gas (c) The customer’s piping must be stream, where these contaminants physically disconnected from the gas could be expected to cause the excess supply and the open pipe ends sealed. flow valve to malfunction or where the excess flow valve would interfere with [Amdt. 192–8, 37 FR 20694, Oct. 3, 1972] necessary operation and maintenance activities on the service, such as blow- § 192.381 Service lines: Excess flow valve performance standards. ing liquids from the line. (a) Excess flow valves to be used on [Amdt. 192–79, 61 FR 31459, June 20, 1996, as single residence service lines that oper- amended by Amdt. 192–80, 62 FR 2619, Jan. 17, ate continuously throughout the year 1997; Amdt. 192–85, 63 FR 37504, July 13, 1998] at a pressure not less than 10 p.s.i. (69 § 192.383 Excess flow valve installa- kPa) gage must be manufactured and tion. tested by the manufacturer according to an industry specification, or the (a) Definitions. As used in this sec- manufacturer’s written specification, tion: to ensure that each valve will: Replaced service line means a gas serv- (1) Function properly up to the max- ice line where the fitting that connects imum operating pressure at which the the service line to the main is replaced valve is rated; or the piping connected to this fitting (2) Function properly at all tempera- is replaced. tures reasonably expected in the oper- Service line serving single-family resi- ating environment of the service line; dence means a gas service line that be- (3) At 10 p.s.i. (69 kPa) gage: gins at the fitting that connects the (i) Close at, or not more than 50 per- service line to the main and serves cent above, the rated closure flow rate only one single-family residence. specified by the manufacturer; and (b) Installation required. An excess (ii) Upon closure, reduce gas flow— flow valve (EFV) installation must (A) For an excess flow valve designed comply with the performance stand- to allow pressure to equalize across the ards in § 192.381. The operator must in- valve, to no more than 5 percent of the stall an EFV on any new or replaced manufacturer’s specified closure flow service line serving a single-family res- rate, up to a maximum of 20 cubic feet idence after February 12, 2010, unless per hour (0.57 cubic meters per hour); one or more of the following conditions or is present: (B) For an excess flow valve designed (1) The service line does not operate to prevent equalization of pressure at a pressure of 10 psig or greater across the valve, to no more than 0.4 throughout the year;

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(2) The operator has prior experience (b) Regulated onshore gathering lines. with contaminants in the gas stream For any regulated onshore gathering that could interfere with the EFV’s op- line under § 192.9 existing on April 14, eration or cause loss of service to a res- 2006, that was not previously subject to idence; this part, and for any onshore gath- (3) An EFV could interfere with nec- ering line that becomes a regulated on- essary operation or maintenance ac- shore gathering line under § 192.9 after tivities, such as blowing liquids from April 14, 2006, because of a change in the line; or class location or increase in dwelling (4) An EFV meeting performance density: standards in § 192.381 is not commer- (1) The requirements of this subpart cially available to the operator. specifically applicable to pipelines installed before August 1, 1971, apply to (c) Reporting. Each operator must re- the gathering line regardless of the port the EFV measures detailed in the date the pipeline was actually in- annual report required by § 191.11. stalled; and [Amdt. 192–113, 74 FR 63934, Dec. 4, 2009, as (2) The requirements of this subpart amended at 75 FR 5244, Feb. 2, 2010; 76 FR specifically applicable to pipelines in- 5499, Feb. 1, 2011] stalled after July 31, 1971, apply only if the pipeline substantially meets those Subpart I—Requirements for requirements. Corrosion Control [Amdt. 192–30, 42 FR 60148, Nov. 25, 1977, as amended by Amdt. 192–102, 71 FR 13303, Mar. 15, 2006] SOURCE: Amdt. 192–4, 36 FR 12302, June 30, 1971, unless otherwise noted. § 192.453 General. § 192.451 Scope. The corrosion control procedures required by § 192.605(b)(2), including those (a) This subpart prescribes minimum for the design, installation, operation, requirements for the protection of me- and maintenance of cathodic protec- tallic pipelines from external, internal, tion systems, must be carried out by, and atmospheric corrosion. or under the direction of, a person (b) [Reserved] qualified in pipeline corrosion control [Amdt. 192–4, 36 FR 12302, June 30, 1971, as methods. amended by Amdt. 192–27, 41 FR 34606, Aug. [Amdt. 192–71, 59 FR 6584, Feb. 11, 1994] 16, 1976; Amdt. 192–33, 43 FR 39389, Sept. 5, 1978] § 192.455 External corrosion control: Buried or submerged pipelines in- § 192.452 How does this subpart apply stalled after July 31, 1971. to converted pipelines and regu- (a) Except as provided in paragraphs lated onshore gathering lines? (b), (c), and (f) of this section, each bur- (a) Converted pipelines. Notwith- ied or submerged pipeline installed standing the date the pipeline was in- after July 31, 1971, must be protected stalled or any earlier deadlines for against external corrosion, including compliance, each pipeline which quali- the following: fies for use under this part in accord- (1) It must have an external protec- ance with § 192.14 must meet the re- tive coating meeting the requirements quirements of this subpart specifically of § 192.461. applicable to pipelines installed before (2) It must have a cathodic protec- August 1, 1971, and all other applicable tion system designed to protect the requirements within 1 year after the pipeline in accordance with this sub- pipeline is readied for service. How- part, installed and placed in operation ever, the requirements of this subpart within 1 year after completion of con- specifically applicable to pipelines in- struction. stalled after July 31, 1971, apply if the (b) An operator need not comply with pipeline substantially meets those re- paragraph (a) of this section, if the op- quirements before it is readied for serv- erator can demonstrate by tests, inves- ice or it is a segment which is replaced, tigation, or experience in the area of relocated, or substantially altered. application, including, as a minimum,

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soil resistivity measurements and tests (2) The fitting is designed to prevent for corrosion accelerating bacteria, leakage caused by localized corrosion that a corrosive environment does not pitting. exist. However, within 6 months after [Amdt. 192–4, 36 FR 12302, June 30, 1971, as an installation made pursuant to the amended at Amdt. 192–28, 42 FR 35654, July preceding sentence, the operator shall 11, 1977; Amdt. 192–39, 47 FR 9844, Mar. 8, 1982; conduct tests, including pipe-to-soil Amdt. 192–78, 61 FR 28785, June 6, 1996; Amdt. potential measurements with respect 192–85, 63 FR 37504, July 13, 1998] to either a continuous reference elec- § 192.457 External corrosion control: trode or an electrode using close spac- Buried or submerged pipelines in- ing, not to exceed 20 feet (6 meters), stalled before August 1, 1971. and soil resistivity measurements at (a) Except for buried piping at com- potential profile peak locations, to pressor, regulator, and measuring sta- adequately evaluate the potential pro- tions, each buried or submerged trans- file along the entire pipeline. If the mission line installed before August 1, tests made indicate that a corrosive 1971, that has an effective external condition exists, the pipeline must be coating must be cathodically protected cathodically protected in accordance along the entire area that is effectively with paragraph (a)(2) of this section. coated, in accordance with this sub- (c) An operator need not comply with part. For the purposes of this subpart, paragraph (a) of this section, if the op- a pipeline does not have an effective erator can demonstrate by tests, inves- external coating if its cathodic protec- tigation, or experience that— tion current requirements are substan- (1) For a copper pipeline, a corrosive tially the same as if it were bare. The environment does not exist; or operator shall make tests to determine (2) For a temporary pipeline with an the cathodic protection current re- operating period of service not to ex- quirements. ceed 5 years beyond installation, corro- (b) Except for cast iron or ductile sion during the 5-year period of service iron, each of the following buried or submerged pipelines installed before of the pipeline will not be detrimental August 1, 1971, must be cathodically to public safety. protected in accordance with this sub- (d) Notwithstanding the provisions of part in areas in which active corrosion paragraph (b) or (c) of this section, if a is found: pipeline is externally coated, it must (1) Bare or ineffectively coated trans- be cathodically protected in accord- mission lines. ance with paragraph (a)(2) of this sec- (2) Bare or coated pipes at com- tion. pressor, regulator, and measuring sta- (e) Aluminum may not be installed in tions. a buried or submerged pipeline if that (3) Bare or coated distribution lines. aluminum is exposed to an environ- [Amdt. 192–4, 36 FR 12302, June 30, 1971, as ment with a natural pH in excess of 8, amended by Amdt. 192–33, 43 FR 39390, Sept. unless tests or experience indicate its 5, 1978; Amdt. 192–93, 68 FR 53900, Sept. 15, suitability in the particular environ- 2003] ment involved. (f) This section does not apply to § 192.459 External corrosion control: Examination of buried pipeline electrically isolated, metal alloy fit- when exposed. tings in plastic pipelines, if: (1) For the size fitting to be used, an Whenever an operator has knowledge operator can show by test, investiga- that any portion of a buried pipeline is exposed, the exposed portion must be tion, or experience in the area of appli- examined for evidence of external cor- cation that adequate corrosion control rosion if the pipe is bare, or if the coat- is provided by the alloy composition; ing is deteriorated. If external corro- and sion requiring remedial action under §§ 192.483 through 192.489 is found, the operator shall investigate circumferen- tially and longitudinally beyond the

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exposed portion (by visual examina- (b) If amphoteric metals are included tion, indirect method, or both) to de- in a buried or submerged pipeline con- termine whether additional corrosion taining a metal of different anodic po- requiring remedial action exists in the tential— vicinity of the exposed portion. (1) The amphoteric metals must be [Amdt. 192–87, 64 FR 56981, Oct. 22, 1999] electrically isolated from the remain- der of the pipeline and cathodically § 192.461 External corrosion control: protected; or Protective coating. (2) The entire buried or submerged (a) Each external protective coating, pipeline must be cathodically pro- whether conductive or insulating, ap- tected at a cathodic potential that plied for the purpose of external corro- meets the requirements of appendix D sion control must— of this part for amphoteric metals. (1) Be applied on a properly prepared (c) The amount of cathodic protec- surface; tion must be controlled so as not to (2) Have sufficient adhesion to the damage the protective coating or the metal surface to effectively resist pipe. underfilm migration of moisture; (3) Be sufficiently ductile to resist § 192.465 External corrosion control: cracking; Monitoring. (4) Have sufficient strength to resist (a) Each pipeline that is under ca- damage due to handling and soil stress; thodic protection must be tested at and least once each calendar year, but with (5) Have properties compatible with intervals not exceeding 15 months, to any supplemental cathodic protection. determine whether the cathodic protec- (b) Each external protective coating tion meets the requirements of which is an electrically insulating type § 192.463. However, if tests at those in- must also have low moisture absorp- tervals are impractical for separately tion and high electrical resistance. protected short sections of mains or (c) Each external protective coating transmission lines, not in excess of 100 must be inspected just prior to low- feet (30 meters), or separately pro- ering the pipe into the ditch and back- tected service lines, these pipelines filling, and any damage detrimental to may be surveyed on a sampling basis. effective corrosion control must be re- At least 10 percent of these protected paired. structures, distributed over the entire (d) Each external protective coating system must be surveyed each calendar must be protected from damage result- year, with a different 10 percent ing from adverse ditch conditions or checked each subsequent year, so that damage from supporting blocks. the entire system is tested in each 10– (e) If coated pipe is installed by boring, driving, or other similar method, year period. precautions must be taken to minimize (b) Each cathodic protection rectifier damage to the coating during installa- or other impressed current power tion. source must be inspected six times each calendar year, but with intervals § 192.463 External corrosion control: not exceeding 21⁄2 months, to insure Cathodic protection. that it is operating. (a) Each cathodic protection system (c) Each reverse current switch, each required by this subpart must provide a diode, and each interference bond level of cathodic protection that com- whose failure would jeopardize struc- plies with one or more of the applicable ture protection must be electrically criteria contained in appendix D of this checked for proper performance six part. If none of these criteria is appli- times each calendar year, but with in- cable, the cathodic protection system tervals not exceeding 21⁄2 months. Each must provide a level of cathodic pro- other interference bond must be tection at least equal to that provided checked at least once each calendar by compliance with one or more of year, but with intervals not exceeding these criteria. 15 months.

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(d) Each operator shall take prompt precautions are taken to prevent arc- remedial action to correct any defi- ing. ciencies indicated by the monitoring. (f) Where a pipeline is located in (e) After the initial evaluation re- close proximity to electrical trans- quired by §§ 192.455(b) and (c) and mission tower footings, ground cables 192.457(b), each operator must, not less or counterpoise, or in other areas than every 3 years at intervals not ex- where fault currents or unusual risk of ceeding 39 months, reevaluate its un- lightning may be anticipated, it must protected pipelines and cathodically be provided with protection against protect them in accordance with this damage due to fault currents or light- subpart in areas in which active corro- ning, and protective measures must sion is found. The operator must deter- also be taken at insulating devices. mine the areas of active corrosion by [Amdt. 192–4, 36 FR 12302, June 30, 1971, as electrical survey. However, on distribu- amended by Amdt. 192–33, 43 FR 39390, Sept. tion lines and where an electrical sur- 5, 1978] vey is impractical on transmission lines, areas of active corrosion may be § 192.469 External corrosion control: determined by other means that in- Test stations. clude review and analysis of leak re- Each pipeline under cathodic protec- pair and inspection records, corrosion tion required by this subpart must monitoring records, exposed pipe in- have sufficient test stations or other spection records, and the pipeline envi- contact points for electrical measure- ronment. ment to determine the adequacy of ca- [Amdt. 192–4, 36 FR 12302, June 30, 1971, as thodic protection. amended by Amdt. 192–33, 43 FR 39390, Sept. [Amdt. 192–27, 41 FR 34606, Aug. 16, 1976] 5, 1978; Amdt. 192–35A, 45 FR 23441, Apr. 7, 1980; Amdt. 192–85, 63 FR 37504, July 13, 1998; § 192.471 External corrosion control: Amdt. 192–93, 68 FR 53900, Sept. 15, 2003; Test leads. Amdt. 192–114, 75 FR 48603, Aug. 11, 2010] (a) Each test lead wire must be con- § 192.467 External corrosion control: nected to the pipeline so as to remain Electrical isolation. mechanically secure and electrically (a) Each buried or submerged pipe- conductive. line must be electrically isolated from (b) Each test lead wire must be at- other underground metallic structures, tached to the pipeline so as to mini- unless the pipeline and the other struc- mize stress concentration on the pipe. tures are electrically interconnected (c) Each bared test lead wire and and cathodically protected as a single bared metallic area at point of connec- unit. tion to the pipeline must be coated (b) One or more insulating devices with an electrical insulating material must be installed where electrical iso- compatible with the pipe coating and lation of a portion of a pipeline is nec- the insulation on the wire. essary to facilitate the application of corrosion control. § 192.473 External corrosion control: Interference currents. (c) Except for unprotected copper inserted in ferrous pipe, each pipeline (a) Each operator whose pipeline sys- must be electrically isolated from me- tem is subjected to stray currents shall tallic casings that are a part of the un- have in effect a continuing program to derground system. However, if isola- minimize the detrimental effects of tion is not achieved because it is im- such currents. practical, other measures must be (b) Each impressed current type ca- taken to minimize corrosion of the thodic protection system or galvanic pipeline inside the casing. anode system must be designed and in- (d) Inspection and electrical tests stalled so as to minimize any adverse must be made to assure that electrical effects on existing adjacent under- isolation is adequate. ground metallic structures. (e) An insulating device may not be [Amdt. 192–4, 36 FR 12302, June 30, 1971, as installed in an area where a combus- amended by Amdt. 192–33, 43 FR 39390, Sept. tible atmosphere is anticipated unless 5, 1978]

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§ 192.475 Internal corrosion control: (b) Exceptions to applicability. The de- General. sign and construction requirements of (a) Corrosive gas may not be trans- paragraph (a) of this section do not ported by pipeline, unless the corrosive apply to the following: effect of the gas on the pipeline has (1) Offshore pipeline; and been investigated and steps have been (2) Pipeline installed or line pipe, taken to minimize internal corrosion. valve, fitting or other line component (b) Whenever any pipe is removed replaced before May 23, 2007. from a pipeline for any reason, the in- (c) Change to existing transmission line. ternal surface must be inspected for When an operator changes the configu- evidence of corrosion. If internal corro- ration of a transmission line, the oper- sion is found— ator must evaluate the impact of the (1) The adjacent pipe must be inves- change on internal corrosion risk to tigated to determine the extent of in- the downstream portion of an existing ternal corrosion; onshore transmission line and provide (2) Replacement must be made to the for removal of liquids and monitoring extent required by the applicable para- of internal corrosion as appropriate. graphs of §§ 192.485, 192.487, or 192.489; (d) Records. An operator must main- and tain records demonstrating compliance (3) Steps must be taken to minimize with this section. Provided the records the internal corrosion. show why incorporating design fea- (c) Gas containing more than 0.25 tures addressing paragraph (a)(1), grain of hydrogen sulfide per 100 cubic (a)(2), or (a)(3) of this section is im- feet (5.8 milligrams/m.3) at standard practicable or unnecessary, an operator conditions (4 parts per million) may may fulfill this requirement through not be stored in pipe-type or bottle- written procedures supported by as- type holders. built drawings or other construction [Amdt. 192–4, 36 FR 12302, June 30, 1971, as records. amended by Amdt. 192–33, 43 FR 39390, Sept. [72 FR 20059, Apr. 23, 2007] 5, 1978; Amdt. 192–78, 61 FR 28785, June 6, 1996; Amdt. 192–85, 63 FR 37504, July 13, 1998] § 192.477 Internal corrosion control: § 192.476 Internal corrosion control: Monitoring. Design and construction of trans- If corrosive gas is being transported, mission line. coupons or other suitable means must (a) Design and construction. Except as be used to determine the effectiveness provided in paragraph (b) of this sec- of the steps taken to minimize internal tion, each new transmission line and corrosion. Each coupon or other means each replacement of line pipe, valve, of monitoring internal corrosion must fitting, or other line component in a be checked two times each calendar transmission line must have features year, but with intervals not exceeding incorporated into its design and con- 71⁄2 months. struction to reduce the risk of internal corrosion. At a minimum, unless it is [Amdt. 192–33, 43 FR 39390, Sept. 5, 1978] impracticable or unnecessary to do so, § 192.479 Atmospheric corrosion con- each new transmission line or replace- trol: General. ment of line pipe, valve, fitting, or other line component in a transmission (a) Each operator must clean and line must: coat each pipeline or portion of pipe- (1) Be configured to reduce the risk line that is exposed to the atmosphere, that liquids will collect in the line; except pipelines under paragraph (c) of (2) Have effective liquid removal fea- this section. tures whenever the configuration (b) Coating material must be suitable would allow liquids to collect; and for the prevention of atmospheric cor- (3) Allow use of devices for moni- rosion. toring internal corrosion at locations (c) Except portions of pipelines in off- with significant potential for internal shore splash zones or soil-to-air inter- corrosion. faces, the operator need not protect

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from atmospheric corrosion any pipe- must be cathodically protected in ac- line for which the operator dem- cordance with this subpart. onstrates by test, investigation, or experience appropriate to the environ- § 192.485 Remedial measures: Trans- ment of the pipeline that corrosion mission lines. will— (a) General corrosion. Each segment of (1) Only be a light surface oxide; or transmission line with general corro- (2) Not affect the safe operation of sion and with a remaining wall thick- the pipeline before the next scheduled ness less than that required for the inspection. MAOP of the pipeline must be replaced [Amdt. 192–93, 68 FR 53901, Sept. 15, 2003] or the operating pressure reduced commensurate with the strength of the § 192.481 Atmospheric corrosion con- pipe based on actual remaining wall trol: Monitoring. thickness. However, corroded pipe may (a) Each operator must inspect each be repaired by a method that reliable pipeline or portion of pipeline that is engineering tests and analyses show exposed to the atmosphere for evidence can permanently restore the service- of atmospheric corrosion, as follows: ability of the pipe. Corrosion pitting so closely grouped as to affect the overall If the pipeline is lo- strength of the pipe is considered gen- cated: Then the frequency of inspection is: eral corrosion for the purpose of this Onshore ...... At least once every 3 calendar years, paragraph. but with intervals not exceeding 39 (b) Localized corrosion pitting. Each months Offshore ...... At least once each calendar year, but segment of transmission line pipe with with intervals not exceeding 15 localized corrosion pitting to a degree months where leakage might result must be replaced or repaired, or the operating (b) During inspections the operator pressure must be reduced commensu- must give particular attention to pipe rate with the strength of the pipe, at soil-to-air interfaces, under thermal based on the actual remaining wall insulation, under disbonded coatings, thickness in the pits. at pipe supports, in splash zones, at (c) Under paragraphs (a) and (b) of deck penetrations, and in spans over this section, the strength of pipe based water. on actual remaining wall thickness (c) If atmospheric corrosion is found may be determined by the procedure in during an inspection, the operator ASME/ANSI B31G or the procedure in must provide protection against the AGA Pipeline Research Committee corrosion as required by § 192.479. Project PR 3–805 (with RSTRENG [Amdt. 192–93, 68 FR 53901, Sept. 15, 2003] disk). Both procedures apply to corroded regions that do not penetrate the § 192.483 Remedial measures: General. pipe wall, subject to the limitations (a) Each segment of metallic pipe prescribed in the procedures. that replaces pipe removed from a bur- [Amdt. 192–4, 36 FR 12302, June 30, 1971, as ied or submerged pipeline because of amended by Amdt. 192–33, 43 FR 39390, Sept. external corrosion must have a prop- 5, 1978; Amdt. 192–78, 61 FR 28785, June 6, 1996; erly prepared surface and must be pro- Amdt. 192–88, 64 FR 69664, Dec. 14, 1999] vided with an external protective coating that meets the requirements of § 192.487 Remedial measures: Distribu- § 192.461. tion lines other than cast iron or (b) Each segment of metallic pipe ductile iron lines. that replaces pipe removed from a bur- (a) General corrosion. Except for cast ied or submerged pipeline because of iron or ductile iron pipe, each segment external corrosion must be cathodi- of generally corroded distribution line cally protected in accordance with this pipe with a remaining wall thickness subpart. less than that required for the MAOP (c) Except for cast iron or ductile of the pipeline, or a remaining wall iron pipe, each segment of buried or thickness less than 30 percent of the submerged pipe that is required to be nominal wall thickness, must be re- repaired because of external corrosion placed. However, corroded pipe may be

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repaired by a method that reliable en- 2 In § 192.925(b), the provision regarding detection of coating damage applies only to pipelines subject to subpart O of gineering tests and analyses show can this part. permanently restore the serviceability of the pipe. Corrosion pitting so closely [Amdt. 192–101, 70 FR 61575, Oct. 25, 2005] grouped as to affect the overall strength of the pipe is considered gen- § 192.491 Corrosion control records. eral corrosion for the purpose of this (a) Each operator shall maintain paragraph. records or maps to show the location of (b) Localized corrosion pitting. Except cathodically protected piping, cathodic for cast iron or ductile iron pipe, each protection facilities, galvanic anodes, segment of distribution line pipe with and neighboring structures bonded to localized corrosion pitting to a degree the cathodic protection system. where leakage might result must be re- Records or maps showing a stated num- placed or repaired. ber of anodes, installed in a stated [Amdt. 192–4, 36 FR 12302, June 30, 1971, as manner or spacing, need not show spe- amended by Amdt. 192–88, 64 FR 69665, Dec. cific distances to each buried anode. 14, 1999] (b) Each record or map required by paragraph (a) of this section must be § 192.489 Remedial measures: Cast retained for as long as the pipeline re- iron and ductile iron pipelines. mains in service. (a) General graphitization. Each seg- (c) Each operator shall maintain a ment of cast iron or ductile iron pipe record of each test, survey, or inspec- on which general graphitization is tion required by this subpart in suffi- found to a degree where a fracture or cient detail to demonstrate the ade- any leakage might result, must be re- quacy of corrosion control measures or placed. that a corrosive condition does not (b) Localized graphitization. Each seg- exist. These records must be retained ment of cast iron or ductile iron pipe for at least 5 years, except that records on which localized graphitization is related to §§ 192.465 (a) and (e) and found to a degree where any leakage 192.475(b) must be retained for as long might result, must be replaced or reas the pipeline remains in service. paired, or sealed by internal sealing methods adequate to prevent or arrest [Amdt. 192–78, 61 FR 28785, June 6, 1996] any leakage. Subpart J—Test Requirements § 192.490 Direct assessment. Each operator that uses direct as- § 192.501 Scope. sessment as defined in § 192.903 on an This subpart prescribes minimum onshore transmission line made pri- leak-test and strength-test require- marily of steel or iron to evaluate the ments for pipelines. effects of a threat in the first column must carry out the direct assessment § 192.503 General requirements. according to the standard listed in the (a) No person may operate a new seg- second column. These standards do not ment of pipeline, or return to service a apply to methods associated with di- segment of pipeline that has been relo- rect assessment, such as close interval cated or replaced, until— surveys, voltage gradient surveys, or (1) It has been tested in accordance examination of exposed pipelines, when with this subpart and § 192.619 to sub- used separately from the direct assess- stantiate the maximum allowable oper- ment process. ating pressure; and Threat Standard 1 (2) Each potentially hazardous leak has been located and eliminated. External corrosion ...... § 192.925 2 Internal corrosion in pipelines that trans- § 192.927 (b) The test medium must be liquid, port dry gas. air, natural gas, or inert gas that is— Stress corrosion cracking ...... § 192.929 (1) Compatible with the material of 1 For lines not subject to subpart O of this part, the terms which the pipeline is constructed; ‘‘covered segment’’ and ‘‘covered pipeline segment’’ in §§ 192.925, 192.927, and 192.929 refer to the pipeline seg- (2) Relatively free of sedimentary ment on which direct assessment is performed. materials; and

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(3) Except for natural gas, nonflam- (c) Except as provided in paragraph mable. (e) of this section, the strength test (c) Except as provided in § 192.505(a), must be conducted by maintaining the if air, natural gas, or inert gas is used pressure at or above the test pressure as the test medium, the following max- for at least 8 hours. imum hoop stress limitations apply: (d) If a component other than pipe is the only item being replaced or added Maximum hoop stress allowed as per- to a pipeline, a strength test after in- centage of SMYS Class location stallation is not required, if the manu- Natural gas Air or inert gas facturer of the component certifies 1 ...... 80 80 that— 2 ...... 30 75 (1) The component was tested to at 3 ...... 30 50 least the pressure required for the pipe- 4 ...... 30 40 line to which it is being added; (2) The component was manufactured (d) Each joint used to tie in a test under a quality control system that en- segment of pipeline is excepted from sures that each item manufactured is the specific test requirements of this at least equal in strength to a proto- subpart, but each non-welded joint type and that the prototype was tested must be leak tested at not less than its to at least the pressure required for the operating pressure. pipeline to which it is being added; or [35 FR 13257, Aug. 19, 1970, as amended by (3) The component carries a pressure Amdt. 192–58, 53 FR 1635, Jan. 21, 1988; Amdt. rating established through applicable 192–60, 53 FR 36029, Sept. 16, 1988; Amdt. 192– ASME/ANSI, MSS specifications, or by 60A, 54 FR 5485, Feb. 3, 1989] unit strength calculations as described in § 192.143. § 192.505 Strength test requirements (e) For fabricated units and short for steel pipeline to operate at a sections of pipe, for which a post in- hoop stress of 30 percent or more of stallation test is impractical, a pre- SMYS. installation strength test must be con- (a) Except for service lines, each seg- ducted by maintaining the pressure at ment of a steel pipeline that is to oper- or above the test pressure for at least ate at a hoop stress of 30 percent or 4 hours. more of SMYS must be strength tested in accordance with this section to sub- [35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192–85, 63 FR 37504, July 13, 1998; stantiate the proposed maximum al- Amdt. 192–94, 69 FR 32895, June 14, 2004; lowable operating pressure. In addi- Amdt. 195–94, 69 FR 54592, Sept. 9, 2004] tion, in a Class 1 or Class 2 location, if there is a building intended for human § 192.507 Test requirements for pipe- occupancy within 300 feet (91 meters) of lines to operate at a hoop stress less a pipeline, a hydrostatic test must be than 30 percent of SMYS and at or conducted to a test pressure of at least above 100 p.s.i. (689 kPa) gage. 125 percent of maximum operating Except for service lines and plastic pressure on that segment of the pipe- pipelines, each segment of a pipeline line within 300 feet (91 meters) of such that is to be operated at a hoop stress a building, but in no event may the less than 30 percent of SMYS and at or test section be less than 600 feet (183 above 100 p.s.i. (689 kPa) gage must be meters) unless the length of the newly tested in accordance with the fol- installed or relocated pipe is less than lowing: 600 feet (183 meters). However, if the (a) The pipeline operator must use a buildings are evacuated while the hoop test procedure that will ensure dis- stress exceeds 50 percent of SMYS, air covery of all potentially hazardous or inert gas may be used as the test leaks in the segment being tested. medium. (b) If, during the test, the segment is (b) In a Class 1 or Class 2 location, to be stressed to 20 percent or more of each compressor station regulator sta- SMYS and natural gas, inert gas, or air tion, and measuring station, must be is the test medium— tested to at least Class 3 location test (1) A leak test must be made at a requirements. pressure between 100 p.s.i. (689 kPa)

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gage and the pressure required to that each segment of a steel service produce a hoop stress of 20 percent of line stressed to 20 percent or more of SMYS; or SMYS must be tested in accordance (2) The line must be walked to check with § 192.507 of this subpart. for leaks while the hoop stress is held at approximately 20 percent of SMYS. [35 FR 13257, Aug. 19, 1970, as amended by (c) The pressure must be maintained Amdt. 192–74, 61 FR 18517, Apr. 26, 1996; Amdt at or above the test pressure for at 192–85, 63 FR 37504, July 13, 1998] least 1 hour. § 192.513 Test requirements for plastic [35 FR 13257, Aug. 19, 1970, as amended by pipelines. Amdt. 192–58, 53 FR 1635, Jan. 21, 1988; Amdt. (a) Each segment of a plastic pipeline 192–85, 63 FR 37504, July 13, 1998] must be tested in accordance with this § 192.509 Test requirements for pipe- section. lines to operate below 100 p.s.i. (689 (b) The test procedure must insure kPa) gage. discovery of all potentially hazardous Except for service lines and plastic leaks in the segment being tested. pipelines, each segment of a pipeline (c) The test pressure must be at least that is to be operated below 100 p.s.i. 150 percent of the maximum operating (689 kPa) gage must be leak tested in pressure or 50 p.s.i. (345 kPa) gage, accordance with the following: whichever is greater. However, the (a) The test procedure used must en- maximum test pressure may not be sure discovery of all potentially haz- more than three times the pressure de- ardous leaks in the segment being test- termined under § 192.121, at a tempera- ed. ture not less than the pipe temperature (b) Each main that is to be operated during the test. at less than 1 p.s.i. (6.9 kPa) gage must (d) During the test, the temperature be tested to at least 10 p.s.i. (69 kPa) of thermoplastic material may not be gage and each main to be operated at more than 100 °F (38 °C), or the tem- or above 1 p.s.i. (6.9 kPa) gage must be perature at which the material’s long- tested to at least 90 p.s.i. (621 kPa) term hydrostatic strength has been de- gage. termined under the listed specification, [35 FR 13257, Aug. 19, 1970, as amended by whichever is greater. Amdt. 192–58, 53 FR 1635, Jan. 21, 1988; Amdt. 192–85, 63 FR 37504, July 13, 1998] [35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192–77, 61 FR 27793, June 3, 1996; 61 FR § 192.511 Test requirements for service 45905, Aug. 30, 1996; Amdt. 192–85, 63 FR 37504, lines. July 13, 1998] (a) Each segment of a service line § 192.515 Environmental protection (other than plastic) must be leak test- and safety requirements. ed in accordance with this section before being placed in service. If feasible, (a) In conducting tests under this the service line connection to the main subpart, each operator shall insure must be included in the test; if not fea- that every reasonable precaution is sible, it must be given a leakage test at taken to protect its employees and the the operating pressure when placed in general public during the testing. service. Whenever the hoop stress of the seg- (b) Each segment of a service line ment of the pipeline being tested will (other than plastic) intended to be op- exceed 50 percent of SMYS, the oper- erated at a pressure of at least 1 p.s.i. ator shall take all practicable steps to (6.9 kPa) gage but not more than 40 keep persons not working on the test- p.s.i. (276 kPa) gage must be given a ing operation outside of the testing leak test at a pressure of not less than area until the pressure is reduced to or 50 p.s.i. (345 kPa) gage. below the proposed maximum allow- (c) Each segment of a service line able operating pressure. (other than plastic) intended to be op- (b) The operator shall insure that the erated at pressures of more than 40 test medium is disposed of in a manner p.s.i. (276 kPa) gage must be tested to that will minimize damage to the envi- at least 90 p.s.i. (621 kPa) gage, except ronment.

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§ 192.517 Records. tain for the life of the segment a record (a) Each operator shall make, and re- of each investigation required by this tain for the useful life of the pipeline, subpart, of all work performed, and of a record of each test performed under each pressure test conducted, in con- §§ 192.505 and 192.507. The record must nection with the uprating. contain at least the following informa- (c) Written plan. Each operator who tion: uprates a segment of pipeline shall es- (1) The operator’s name, the name of tablish a written procedure that will the operator’s employee responsible for ensure that each applicable require- making the test, and the name of any ment of this subpart is complied with. test company used. (d) Limitation on increase in maximum (2) Test medium used. allowable operating pressure. Except as (3) Test pressure. provided in § 192.555(c), a new maximum (4) Test duration. allowable operating pressure estab- (5) Pressure recording charts, or lished under this subpart may not ex- other record of pressure readings. ceed the maximum that would be al- (6) Elevation variations, whenever lowed under §§ 192.619 and 192.621 for a significant for the particular test. new segment of pipeline constructed of (7) Leaks and failures noted and their the same materials in the same loca- disposition. tion. However, when uprating a steel (b) Each operator must maintain a pipeline, if any variable necessary to record of each test required by determine the design pressure under §§ 192.509, 192.511, and 192.513 for at least the design formula (§ 192.105) is un- 5 years. known, the MAOP may be increased as provided in § 192.619(a)(1). [35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192–93, 68 FR 53901, Sept. 15, 2003] [35 FR 13257, Aug. 10, 1970, as amended by Amdt. 192–78, 61 FR 28785, June 6, 1996; Amdt. Subpart K—Uprating 192–93, 68 FR 53901, Sept. 15, 2003] § 192.555 Uprating to a pressure that § 192.551 Scope. will produce a hoop stress of 30 per- This subpart prescribes minimum recent or more of SMYS in steel pipe- quirements for increasing maximum lines. allowable operating pressures (a) Unless the requirements of this (uprating) for pipelines. section have been met, no person may subject any segment of a steel pipeline § 192.553 General requirements. to an operating pressure that will (a) Pressure increases. Whenever the produce a hoop stress of 30 percent or requirements of this subpart require more of SMYS and that is above the es- that an increase in operating pressure tablished maximum allowable oper- be made in increments, the pressure ating pressure. must be increased gradually, at a rate (b) Before increasing operating pres- that can be controlled, and in accord- sure above the previously established ance with the following: maximum allowable operating pressure (1) At the end of each incremental in- the operator shall: crease, the pressure must be held con- (1) Review the design, operating, and stant while the entire segment of pipe- maintenance history and previous test- line that is affected is checked for ing of the segment of pipeline and de- leaks. termine whether the proposed increase (2) Each leak detected must be re- is safe and consistent with the require- paired before a further pressure in- ments of this part; and crease is made, except that a leak de- (2) Make any repairs, replacements, termined not to be potentially haz- or alterations in the segment of pipe- ardous need not be repaired, if it is line that are necessary for safe oper- monitored during the pressure increase ation at the increased pressure. and it does not become potentially haz- (c) After complying with paragraph ardous. (b) of this section, an operator may in- (b) Records. Each operator who crease the maximum allowable oper- uprates a segment of pipeline shall re- ating pressure of a segment of pipeline

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constructed before September 12, 1970, SMYS and that is above the previously to the highest pressure that is per- established maximum allowable oper- mitted under § 192.619, using as test ating pressure; or pressure the highest pressure to which (2) A plastic, cast iron, or ductile the segment of pipeline was previously iron pipeline segment to an operating subjected (either in a strength test or pressure that is above the previously in actual operation). established maximum allowable oper- (d) After complying with paragraph ating pressure. (b) of this section, an operator that (b) Before increasing operating pres- does not qualify under paragraph (c) of sure above the previously established this section may increase the pre- maximum allowable operating pres- viously established maximum allow- sure, the operator shall: able operating pressure if at least one (1) Review the design, operating, and of the following requirements is met: maintenance history of the segment of (1) The segment of pipeline is suc- pipeline; cessfully tested in accordance with the (2) Make a leakage survey (if it has requirements of this part for a new line been more than 1 year since the last of the same material in the same loca- survey) and repair any leaks that are tion. found, except that a leak determined (2) An increased maximum allowable not to be potentially hazardous need operating pressure may be established not be repaired, if it is monitored dur- for a segment of pipeline in a Class 1 ing the pressure increase and it does location if the line has not previously not become potentially hazardous; been tested, and if: (i) It is impractical to test it in ac- (3) Make any repairs, replacements, cordance with the requirements of this or alterations in the segment of pipe- part; line that are necessary for safe oper- (ii) The new maximum operating ation at the increased pressure; pressure does not exceed 80 percent of (4) Reinforce or anchor offsets, bends that allowed for a new line of the same and dead ends in pipe joined by com- design in the same location; and pression couplings or bell and spigot (iii) The operator determines that joints to prevent failure of the pipe the new maximum allowable operating joint, if the offset, bend, or dead end is pressure is consistent with the condi- exposed in an excavation; tion of the segment of pipeline and the (5) Isolate the segment of pipeline in design requirements of this part. which the pressure is to be increased (e) Where a segment of pipeline is from any adjacent segment that will uprated in accordance with paragraph continue to be operated at a lower (c) or (d)(2) of this section, the increase pressure; and in pressure must be made in incre- (6) If the pressure in mains or service ments that are equal to: lines, or both, is to be higher than the (1) 10 percent of the pressure before pressure delivered to the customer, in- the uprating; or stall a service regulator on each serv- (2) 25 percent of the total pressure in- ice line and test each regulator to decrease, termine that it is functioning. Pressure whichever produces the fewer number may be increased as necessary to test of increments. each regulator, after a regulator has been installed on each pipeline subject § 192.557 Uprating: Steel pipelines to a to the increased pressure. pressure that will produce a hoop (c) After complying with paragraph stress less than 30 percent of SMYS: (b) of this section, the increase in max- plastic, cast iron, and ductile iron imum allowable operating pressure pipelines. must be made in increments that are (a) Unless the requirements of this equal to 10 p.s.i. (69 kPa) gage or 25 per- section have been met, no person may cent of the total pressure increase, subject: whichever produces the fewer number (1) A segment of steel pipeline to an of increments. Whenever the require- operating pressure that will produce a ments of paragraph (b)(6) of this sec- hoop stress less than 30 percent of tion apply, there must be at least two

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approximately equal incremental in- (2) Unless the actual maximum cover creases. depth is known, the operator shall (d) If records for cast iron or ductile measure the actual cover in at least iron pipeline facilities are not com- three places where the cover is most plete enough to determine stresses pro- likely to be greatest and shall use the duced by internal pressure, trench greatest cover measured. loading, rolling loads, beam stresses, (3) Unless the actual nominal wall and other bending loads, in evaluating thickness is known, the operator shall the level of safety of the pipeline when determine the wall thickness by cut- operating at the proposed increased pressure, the following procedures ting and measuring coupons from at must be followed: least three separate pipe lengths. The (1) In estimating the stresses, if the coupons must be cut from pipe lengths original laying conditions cannot be in areas where the cover depth is most ascertained, the operator shall assume likely to be the greatest. The average that cast iron pipe was supported on of all measurements taken must be in- blocks with tamped backfill and that creased by the allowance indicated in ductile iron pipe was laid without the following table: blocks with tamped backfill.

Allowance inches (millimeters)

Pipe size inches (millimeters) Cast iron pipe Centrifugally cast Ductile iron pipe Pit cast pipe pipe

3 to 8 (76 to 203) ...... 0.075 (1.91) 0.065 (1.65) 0.065 (1.65) 10 to 12 (254 to 305) ...... 0.08 (2.03) 0.07 (1.78) 0.07 (1.78) 14 to 24 (356 to 610) ...... 0.08 (2.03) 0.08 (2.03) 0.075 (1.91) 30 to 42 (762 to 1067) ...... 0.09 (2.29) 0.09 (2.29) 0.075 (1.91) 48 (1219) ...... 0.09 (2.29) 0.09 (2.29) 0.08 (2.03) 54 to 60 (1372 to 1524) ...... 0.09 (2.29) ......

(4) For cast iron pipe, unless the pipe (c) The Administrator or the State manufacturing process is known, the Agency that has submitted a current operator shall assume that the pipe is certification under the pipeline safety pit cast pipe with a bursting tensile laws, (49 U.S.C. 60101 et seq.) with re- strength of 11,000 p.s.i. (76 MPa) gage spect to the pipeline facility governed and a modulus of rupture of 31,000 p.s.i. by an operator’s plans and procedures (214 MPa) gage. may, after notice and opportunity for [35 FR 13257, Aug. 19, 1970, as amended by hearing as provided in 49 CFR 190.237 or Amdt. 192–37, 46 FR 10160, Feb. 2, 1981; Amdt. the relevant State procedures, require 192–62, 54 FR 5628, Feb. 6, 1989; Amdt. 195–85, the operator to amend its plans and 63 FR 37504, July 13, 1998] procedures as necessary to provide a reasonable level of safety. Subpart L—Operations [35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192–66, 56 FR 31090, July 9, 1991; Amdt. § 192.601 Scope. 192–71, 59 FR 6584, Feb. 11, 1994; Amdt. 192–75, This subpart prescribes minimum re- 61 FR 18517, Apr. 26, 1996] quirements for the operation of pipeline facilities. § 192.605 Procedural manual for operations, maintenance, and emer- § 192.603 General provisions. gencies. (a) No person may operate a segment (a) General. Each operator shall pre- of pipeline unless it is operated in ac- pare and follow for each pipeline, a cordance with this subpart. manual of written procedures for con- (b) Each operator shall keep records ducting operations and maintenance necessary to administer the procedures activities and for emergency response. established under § 192.605. For transmission lines, the manual

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must also include procedures for han- including a breathing apparatus and, a dling abnormal operations. This man- rescue harness and line. ual must be reviewed and updated by (10) Systematic and routine testing the operator at intervals not exceeding and inspection of pipe-type or bottle- 15 months, but at least once each cal- type holders including— endar year. This manual must be pre- (i) Provision for detecting external pared before operations of a pipeline corrosion before the strength of the system commence. Appropriate parts container has been impaired; of the manual must be kept at loca- (ii) Periodic sampling and testing of tions where operations and mainte- gas in storage to determine the dew nance activities are conducted. point of vapors contained in the stored (b) Maintenance and normal oper- gas which, if condensed, might cause ations. The manual required by para- internal corrosion or interfere with the graph (a) of this section must include safe operation of the storage plant; and procedures for the following, if applica- (iii) Periodic inspection and testing ble, to provide safety during mainte- of pressure limiting equipment to de- nance and operations. termine that it is in safe operating (1) Operating, maintaining, and re- condition and has adequate capacity. pairing the pipeline in accordance with (11) Responding promptly to a report each of the requirements of this sub- of a gas odor inside or near a building, part and subpart M of this part. unless the operator’s emergency proce- (2) Controlling corrosion in accord- dures under § 192.615(a)(3) specifically ance with the operations and mainte- apply to these reports. nance requirements of subpart I of this (12) Implementing the applicable con- part. trol room management procedures required by § 192.631. (3) Making construction records, (c) Abnormal operation. For trans- maps, and operating history available mission lines, the manual required by to appropriate operating personnel. paragraph (a) of this section must in- (4) Gathering of data needed for re- clude procedures for the following to porting incidents under Part 191 of this provide safety when operating design chapter in a timely and effective man- limits have been exceeded: ner. (1) Responding to, investigating, and (5) Starting up and shutting down correcting the cause of: any part of the pipeline in a manner (i) Unintended closure of valves or designed to assure operation within the shutdowns; MAOP limits prescribed by this part, (ii) Increase or decrease in pressure plus the build-up allowed for operation or flow rate outside normal operating of pressure-limiting and control de- limits; vices. (iii) Loss of communications; (6) Maintaining compressor stations, (iv) Operation of any safety device; including provisions for isolating units and or sections of pipe and for purging be- (v) Any other foreseeable malfunc- fore returning to service. tion of a component, deviation from (7) Starting, operating and shutting normal operation, or personnel error, down gas compressor units. which may result in a hazard to per- (8) Periodically reviewing the work sons or property. done by operator personnel to deter- (2) Checking variations from normal mine the effectiveness, and adequacy of operation after abnormal operation has the procedures used in normal oper- ended at sufficient critical locations in ation and maintenance and modifying the system to determine continued in- the procedures when deficiencies are tegrity and safe operation. found. (3) Notifying responsible operator (9) Taking adequate precautions in personnel when notice of an abnormal excavated trenches to protect per- operation is received. sonnel from the hazards of unsafe accu- (4) Periodically reviewing the re- mulations of vapor or gas, and making sponse of operator personnel to deter- available when needed at the exca- mine the effectiveness of the proce- vation, emergency rescue equipment, dures controlling abnormal operation

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and taking corrective action where de- ating hoop stress, taking pressure gra- ficiencies are found. dient into account, for the segment of (5) The requirements of this para- pipeline involved; and graph (c) do not apply to natural gas (f) The actual area affected by the distribution operators that are oper- population density increase, and phys- ating transmission lines in connection ical barriers or other factors which with their distribution system. may limit further expansion of the (d) Safety-related condition reports. more densely populated area. The manual required by paragraph (a) of this section must include instruc- § 192.611 Change in class location: tions enabling personnel who perform Confirmation or revision of max- operation and maintenance activities imum allowable operating pressure. to recognize conditions that poten- (a) If the hoop stress corresponding tially may be safety-related conditions to the established maximum allowable that are subject to the reporting requirements of § 191.23 of this sub- operating pressure of a segment of chapter. pipeline is not commensurate with the (e) Surveillance, emergency response, present class location, and the segment and accident investigation. The proce- is in satisfactory physical condition, dures required by §§ 192.613(a), 192.615, the maximum allowable operating and 192.617 must be included in the pressure of that segment of pipeline manual required by paragraph (a) of must be confirmed or revised according this section. to one of the following requirements: (1) If the segment involved has been [Amdt. 192–71, 59 FR 6584, Feb. 11, 1994, as amended by Amdt. 192–71A, 60 FR 14381, Mar. previously tested in place for a period 17, 1995; Amdt. 192–93, 68 FR 53901, Sept. 15, of not less than 8 hours: 2003; Amdt. 192–112, 74 FR 63327, Dec. 3, 2009] (i) The maximum allowable operating pressure is 0.8 times the test pressure § 192.607 [Reserved] in Class 2 locations, 0.667 times the test pressure in Class 3 locations, or 0.555 § 192.609 Change in class location: Re- quired study. times the test pressure in Class 4 locations. The corresponding hoop stress Whenever an increase in population may not exceed 72 percent of the SMYS density indicates a change in class lo- of the pipe in Class 2 locations, 60 per- cation for a segment of an existing steel pipeline operating at hoop stress cent of SMYS in Class 3 locations, or 50 that is more than 40 percent of SMYS, percent of SMYS in Class 4 locations. or indicates that the hoop stress cor- (ii) The alternative maximum allow- responding to the established max- able operating pressure is 0.8 times the imum allowable operating pressure for test pressure in Class 2 locations and a segment of existing pipeline is not 0.667 times the test pressure in Class 3 commensurate with the present class locations. For pipelines operating at location, the operator shall imme- alternative maximum allowable pres- diately make a study to determine: sure per § 192.620, the corresponding (a) The present class location for the hoop stress may not exceed 80 percent segment involved. of the SMYS of the pipe in Class 2 loca- (b) The design, construction, and tions and 67 percent of SMYS in Class testing procedures followed in the 3 locations. original construction, and a compari- (2) The maximum allowable oper- son of these procedures with those re- ating pressure of the segment involved quired for the present class location by must be reduced so that the cor- the applicable provisions of this part. responding hoop stress is not more (c) The physical condition of the seg- than that allowed by this part for new ment to the extent it can be segments of pipelines in the existing ascertained from available records; class location. (d) The operating and maintenance (3) The segment involved must be history of the segment; (e) The maximum actual operating tested in accordance with the applica- pressure and the corresponding oper- ble requirements of subpart J of this

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part, and its maximum allowable oper- § 192.612 Underwater inspection and ating pressure must then be estab- reburial of pipelines in the Gulf of lished according to the following cri- Mexico and its inlets. teria: (a) Each operator shall prepare and (i) The maximum allowable operating follow a procedure to identify its pipe- pressure after the requalification test lines in the Gulf of Mexico and its in- is 0.8 times the test pressure for Class lets in waters less than 15 feet (4.6 me- 2 locations, 0.667 times the test pres- ters) deep as measured from mean low sure for Class 3 locations, and 0.555 water that are at risk of being an ex- times the test pressure for Class 4 loca- posed underwater pipeline or a hazard tions. to navigation. The procedures must be (ii) The corresponding hoop stress in effect August 10, 2005. may not exceed 72 percent of the SMYS (b) Each operator shall conduct ap- of the pipe in Class 2 locations, 60 per- propriate periodic underwater inspec- cent of SMYS in Class 3 locations, or 50 tions of its pipelines in the Gulf of percent of SMYS in Class 4 locations. Mexico and its inlets in waters less (iii) For pipeline operating at an al- than 15 feet (4.6 meters) deep as meas- ternative maximum allowable oper- ured from mean low water based on the ating pressure per § 192.620, the alter- identified risk. native maximum allowable operating (c) If an operator discovers that its pressure after the requalification test pipeline is an exposed underwater pipe- is 0.8 times the test pressure for Class line or poses a hazard to navigation, 2 locations and 0.667 times the test the operator shall— pressure for Class 3 locations. The cor- (1) Promptly, but not later than 24 responding hoop stress may not exceed hours after discovery, notify the Na- 80 percent of the SMYS of the pipe in tional Response Center, telephone: 1– Class 2 locations and 67 percent of 800–424–8802, of the location and, if SMYS in Class 3 locations. available, the geographic coordinates (b) The maximum allowable oper- of that pipeline. ating pressure confirmed or revised in (2) Promptly, but not later than 7 accordance with this section, may not days after discovery, mark the location exceed the maximum allowable oper- of the pipeline in accordance with 33 ating pressure established before the CFR part 64 at the ends of the pipeline confirmation or revision. segment and at intervals of not over (c) Confirmation or revision of the 500 yards (457 meters) long, except that maximum allowable operating pressure a pipeline segment less than 200 yards of a segment of pipeline in accordance (183 meters) long need only be marked with this section does not preclude the at the center; and application of §§ 192.553 and 192.555. (3) Within 6 months after discovery, (d) Confirmation or revision of the or not later than November 1 of the fol- maximum allowable operating pressure lowing year if the 6 month period is that is required as a result of a study later than November 1 of the year of under § 192.609 must be completed with- discovery, bury the pipeline so that the in 24 months of the change in class lo- top of the pipe is 36 inches (914 milli- cation. Pressure reduction under parameters) below the underwater natural graph (a) (1) or (2) of this section with- bottom (as determined by recognized in the 24-month period does not pre- and generally accepted practices) for clude establishing a maximum allow- normal excavation or 18 inches (457 able operating pressure under para- millimeters) for rock excavation. graph (a)(3) of this section at a later (i) An operator may employ engi- date. neered alternatives to burial that meet [Amdt. 192–63A, 54 FR 24174, June 6, 1989 as or exceed the level of protection pro- amended by Amdt. 192–78, 61 FR 28785, June vided by burial. 6, 1996; Amdt. 192–94, 69 FR 32895, June 14, (ii) If an operator cannot obtain re- 2004; 73 FR 62177, Oct. 17, 2008] quired state or Federal permits in time to comply with this section, it must

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notify OPS; specify whether the re- line system must be covered by a quali- quired permit is State or Federal; and, fied one-call system where there is one justify the delay. in place. For the purpose of this sec- [Amdt. 192–98, 69 FR 48406, Aug. 10, 2004] tion, a one-call system is considered a ‘‘qualified one-call system’’ if it meets § 192.613 Continuing surveillance. the requirements of section (b)(1) or (b)(2) of this section. (a) Each operator shall have a procedure for continuing surveillance of its (1) The state has adopted a one-call facilities to determine and take appro- damage prevention program under priate action concerning changes in § 198.37 of this chapter; or class location, failures, leakage his- (2) The one-call system: tory, corrosion, substantial changes in (i) Is operated in accordance with cathodic protection requirements, and § 198.39 of this chapter; other unusual operating and mainte- (ii) Provides a pipeline operator an nance conditions. opportunity similar to a voluntary par- (b) If a segment of pipeline is deter- ticipant to have a part in management mined to be in unsatisfactory condition responsibilities; and but no immediate hazard exists, the op- (iii) Assesses a participating pipeline erator shall initiate a program to re- operator a fee that is proportionate to condition or phase out the segment in- the costs of the one-call system’s cov- volved, or, if the segment cannot be re- erage of the operator’s pipeline. conditioned or phased out, reduce the (c) The damage prevention program maximum allowable operating pressure required by paragraph (a) of this sec- in accordance with § 192.619 (a) and (b). tion must, at a minimum: (1) Include the identity, on a current § 192.614 Damage prevention program. basis, of persons who normally engage (a) Except as provided in paragraphs in excavation activities in the area in (d) and (e) of this section, each oper- which the pipeline is located. ator of a buried pipeline must carry (2) Provides for notification of the out, in accordance with this section, a public in the vicinity of the pipeline written program to prevent damage to and actual notification of the persons that pipeline from excavation activi- identified in paragraph (c)(1) of this ties. For the purposes of this section, section of the following as often as the term ‘‘excavation activities’’ in- needed to make them aware of the cludes excavation, blasting, boring, damage prevention program: tunneling, backfilling, the removal of (i) The program’s existence and pur- aboveground structures by either ex- pose; and plosive or mechanical means, and other (ii) How to learn the location of un- earthmoving operations. derground pipelines before excavation (b) An operator may comply with any of the requirements of paragraph (c) of activities are begun. this section through participation in a (3) Provide a means of receiving and public service program, such as a one- recording notification of planned exca- call system, but such participation vation activities. does not relieve the operator of respon- (4) If the operator has buried pipe- sibility for compliance with this sec- lines in the area of excavation activity, tion. However, an operator must per- provide for actual notification of perform the duties of paragraph (c)(3) of sons who give notice of their intent to this section through participation in a excavate of the type of temporary one-call system, if that one-call system marking to be provided and how to is a qualified one-call system. In areas identify the markings. that are covered by more than one (5) Provide for temporary marking of qualified one-call system, an operator buried pipelines in the area of exca- need only join one of the qualified one- vation activity before, as far as prac- call systems if there is a central tele- tical, the activity begins. phone number for excavators to call for (6) Provide as follows for inspection excavation activities, or if the one-call of pipelines that an operator has rea- systems in those areas communicate son to believe could be damaged by ex- with one another. An operator’s pipe- cavation activities:

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(i) The inspection must be done as (4) The availability of personnel, frequently as necessary during and equipment, tools, and materials, as after the activities to verify the integ- needed at the scene of an emergency. rity of the pipeline; and (5) Actions directed toward pro- (ii) In the case of blasting, any in- tecting people first and then property. spection must include leakage surveys. (6) Emergency shutdown and pressure (d) A damage prevention program reduction in any section of the opera- under this section is not required for tor’s pipeline system necessary to min- the following pipelines: imize hazards to life or property. (1) Pipelines located offshore. (7) Making safe any actual or potential hazard to life or property. (2) Pipelines, other than those lo- (8) Notifying appropriate fire, police, cated offshore, in Class 1 or 2 locations and other public officials of gas pipe- until September 20, 1995. line emergencies and coordinating with (3) Pipelines to which access is phys- them both planned responses and ac- ically controlled by the operator. tual responses during an emergency. (e) Pipelines operated by persons (9) Safely restoring any service out- other than municipalities (including age. operators of master meters) whose pri- (10) Beginning action under § 192.617, mary activity does not include the if applicable, as soon after the end of transportation of gas need not comply the emergency as possible. with the following: (11) Actions required to be taken by a (1) The requirement of paragraph (a) controller during an emergency in ac- of this section that the damage preven- cordance with § 192.631. tion program be written; and (b) Each operator shall: (2) The requirements of paragraphs (1) Furnish its supervisors who are (c)(1) and (c)(2) of this section. responsible for emergency action a copy of that portion of the latest edi- [Amdt. 192–40, 47 FR 13824, Apr. 1, 1982, as tion of the emergency procedures es- amended by Amdt. 192–57, 52 FR 32800, Aug. 31, 1987; Amdt. 192–73, 60 FR 14650, Mar. 20, tablished under paragraph (a) of this 1995; Amdt. 192–78, 61 FR 28785, June 6, 1996; section as necessary for compliance Amdt.192–82, 62 FR 61699, Nov. 19, 1997; Amdt. with those procedures. 192–84, 63 FR 38758, July 20, 1998] (2) Train the appropriate operating personnel to assure that they are § 192.615 Emergency plans. knowledgeable of the emergency proce- (a) Each operator shall establish dures and verify that the training is ef- written procedures to minimize the fective. hazard resulting from a gas pipeline (3) Review employee activities to de- emergency. At a minimum, the proce- termine whether the procedures were dures must provide for the following: effectively followed in each emergency. (c) Each operator shall establish and (1) Receiving, identifying, and maintain liaison with appropriate fire, classifying notices of events which re- police, and other public officials to: quire immediate response by the oper- (1) Learn the responsibility and re- ator. sources of each government organiza- (2) Establishing and maintaining ade- tion that may respond to a gas pipeline quate means of communication with emergency; appropriate fire, police, and other pub- (2) Acquaint the officials with the op- lic officials. erator’s ability in responding to a gas (3) Prompt and effective response to a pipeline emergency; notice of each type of emergency, in- (3) Identify the types of gas pipeline cluding the following: emergencies of which the operator no- (i) Gas detected inside or near a tifies the officials; and building. (4) Plan how the operator and offi- (ii) Fire located near or directly in- cials can engage in mutual assistance volving a pipeline facility. to minimize hazards to life or property. (iii) Explosion occurring near or di- [Amdt. 192–24, 41 FR 13587, Mar. 31, 1976, as rectly involving a pipeline facility. amended by Amdt. 192–71, 59 FR 6585, Feb. 11, (iv) Natural disaster. 1994; Amdt. 192–112, 74 FR 63327, Dec. 3, 2009]

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§ 192.616 Public awareness. (h) Operators in existence on June 20, 2005, must have completed their writ- (a) Except for an operator of a master meter or petroleum gas system covered ten programs no later than June 20, under paragraph (j) of this section, 2006. The operator of a master meter or each pipeline operator must develop petroleum gas system covered under and implement a written continuing paragraph (j) of this section must com- public education program that follows plete development of its written proce- the guidance provided in the American dure by June 13, 2008. Upon request, op- Petroleum Institute’s (API) Rec- erators must submit their completed ommended Practice (RP) 1162 (incor- programs to PHMSA or, in the case of porated by reference, see § 192.7). an intrastate pipeline facility operator, (b) The operator’s program must fol- the appropriate State agency. low the general program recommenda- (i) The operator’s program docu- tions of API RP 1162 and assess the mentation and evaluation results must unique attributes and characteristics be available for periodic review by ap- of the operator’s pipeline and facilities. propriate regulatory agencies. (c) The operator must follow the gen- (j) Unless the operator transports gas eral program recommendations, includ- as a primary activity, the operator of a ing baseline and supplemental require- master meter or petroleum gas system ments of API RP 1162, unless the oper- is not required to develop a public ator provides justification in its pro- awareness program as prescribed in gram or procedural manual as to why paragraphs (a) through (g) of this sec- compliance with all or certain provi- tion. Instead the operator must develop sions of the recommended practice is and implement a written procedure to not practicable and not necessary for provide its customers public awareness safety. messages twice annually. If the master (d) The operator’s program must specifically include provisions to educate meter or petroleum gas system is lo- the public, appropriate government or- cated on property the operator does ganizations, and persons engaged in ex- not control, the operator must provide cavation related activities on: similar messages twice annually to (1) Use of a one-call notification sys- persons controlling the property. The tem prior to excavation and other dam- public awareness message must in- age prevention activities; clude: (2) Possible hazards associated with (1) A description of the purpose and unintended releases from a gas pipeline reliability of the pipeline; facility; (2) An overview of the hazards of the (3) Physical indications that such a pipeline and prevention measures used; release may have occurred; (3) Information about damage preven- (4) Steps that should be taken for tion; public safety in the event of a gas pipe- (4) How to recognize and respond to a line release; and leak; and (5) Procedures for reporting such an (5) How to get additional informa- event. tion. (e) The program must include activities to advise affected municipalities, [Amdt. 192–100, 70 FR 28842, May 19, 2005; 70 school districts, businesses, and resi- FR 35041, June 16, 2005; 72 FR 70810, Dec. 13, dents of pipeline facility locations. 2007] (f) The program and the media used § 192.617 Investigation of failures. must be as comprehensive as necessary to reach all areas in which the operator Each operator shall establish proce- transports gas. dures for analyzing accidents and fail- (g) The program must be conducted ures, including the selection of samples in English and in other languages com- of the failed facility or equipment for monly understood by a significant laboratory examination, where appro- number and concentration of the non- priate, for the purpose of determining English speaking population in the op- the causes of the failure and mini- erator’s area. mizing the possibility of a recurrence.

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§ 192.619 Maximum allowable oper- (i) For plastic pipe in all locations, ating pressure: Steel or plastic pipe- the test pressure is divided by a factor lines. of 1.5. (a) No person may operate a segment (ii) For steel pipe operated at 100 of steel or plastic pipeline at a pressure p.s.i. (689 kPa) gage or more, the test that exceeds a maximum allowable op- pressure is divided by a factor deter- erating pressure determined under mined in accordance with the following paragraph (c) or (d) of this section, or table: the lowest of the following: 1 (1) The design pressure of the weak- Factors , segment— est element in the segment, deter- Installed Class location before Installed Converted mined in accordance with subparts C (Nov. 12, after (Nov. under and D of this part. However, for steel 1970) 11, 1970) § 192.14 pipe in pipelines being converted under 1 ...... 1.1 1.1 1.25 § 192.14 or uprated under subpart K of 2 ...... 1.25 1.25 1.25 this part, if any variable necessary to 3 ...... 1.4 1.5 1.5 determine the design pressure under 4 ...... 1.4 1.5 1.5 the design formula (§ 192.105) is un- 1 For offshore segments installed, uprated or converted after known, one of the following pressures July 31, 1977, that are not located on an offshore platform, the factor is 1.25. For segments installed, uprated or con- is to be used as design pressure: verted after July 31, 1977, that are located on an offshore (i) Eighty percent of the first test platform or on a platform in inland navigable waters, including pressure that produces yield under sec- a pipe riser, the factor is 1.5. tion N5 of Appendix N of ASME B31.8 (3) The highest actual operating pres- (incorporated by reference, see § 192.7), sure to which the segment was sub- reduced by the appropriate factor in jected during the 5 years preceding the paragraph (a)(2)(ii) of this section; or applicable date in the second column. (ii) If the pipe is 123⁄4 inches (324 mm) This pressure restriction applies unless or less in outside diameter and is not the segment was tested according to tested to yield under this paragraph, the requirements in paragraph (a)(2) of 200 p.s.i. (1379 kPa). this section after the applicable date in (2) The pressure obtained by dividing the third column or the segment was the pressure to which the segment was uprated according to the requirements tested after construction as follows: in subpart K of this part:

Pipeline segment Pressure date Test date

—Onshore gathering line that first be- March 15, 2006, or date line becomes 5 years preceding applicable date in sec- came subject to this part (other than subject to this part, whichever is later. ond column. § 192.612) after April 13, 2006. —Onshore transmission line that was a gathering line not subject to this part before March 15, 2006. Offshore gathering lines ...... July 1, 1976 ...... July 1, 1971. All other pipelines ...... July 1, 1970 ...... July 1, 1965.

(4) The pressure determined by the in the following instance. An operator operator to be the maximum safe pres- may operate a segment of pipeline sure after considering the history of found to be in satisfactory condition, the segment, particularly known corro- considering its operating and mainte- sion and the actual operating pressure. nance history, at the highest actual op- (b) No person may operate a segment erating pressure to which the segment to which paragraph (a)(4) of this sec- was subjected during the 5 years pre- tion is applicable, unless over-pressure ceding the applicable date in the sec- protective devices are installed on the ond column of the table in paragraph segment in a manner that will prevent (a)(3) of this section. An operator must the maximum allowable operating still comply with § 192.611. pressure from being exceeded, in ac- (d) The operator of a pipeline seg- cordance with § 192.195. ment of steel pipeline meeting the con- (c) The requirements on pressure re- ditions prescribed in § 192.620(b) may strictions in this section do not apply

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elect to operate the segment at a max- Class location Alternative test imum allowable operating pressure de- factor termined under § 192.620(a). 3 ...... 1.50 [35 FR 13257, Aug. 19, 1970] 1 For Class 2 alternative maximum allowable operating pressure segments installed prior to December 22, 2008 the EDITORIAL NOTE: For FEDERAL REGISTER ci- alternative test factor is 1.25. tations affecting § 192.619, see the List of CFR Sections Affected, which appears in the (b) When may an operator use the alter- Finding Aids section of the printed volume native maximum allowable operating pres- and at www.fdsys.gov. sure calculated under paragraph (a) of this section? An operator may use an al- § 192.620 Alternative maximum allow- ternative maximum allowable operable operating pressure for certain ating pressure calculated under para- steel pipelines. graph (a) of this section if the fol- (a) How does an operator calculate the lowing conditions are met: alternative maximum allowable operating (1) The pipeline segment is in a Class pressure? An operator calculates the al- 1, 2, or 3 location; ternative maximum allowable oper- (2) The pipeline segment is con- ating pressure by using different fac- structed of steel pipe meeting the addi- tors in the same formulas used for cal- tional design requirements in § 192.112; culating maximum allowable operating (3) A supervisory control and data ac- pressure under § 192.619(a) as follows: quisition system provides remote mon- (1) In determining the alternative de- itoring and control of the pipeline seg- sign pressure under § 192.105, use a de- ment. The control provided must in- sign factor determined in accordance clude monitoring of pressures and with § 192.111(b), (c), or (d) or, if none of flows, monitoring compressor start-ups these paragraphs apply, in accordance and shut-downs, and remote closure of with the following table: valves per paragraph (d)(3) of this section; Class location Alternative design factor (F) (4) The pipeline segment meets the 1 ...... 0.80 additional construction requirements 2 ...... 0.67 described in § 192.328; 3 ...... 0.56 (5) The pipeline segment does not contain any mechanical couplings used (i) For facilities installed prior to De- in place of girth welds; cember 22, 2008, for which § 192.111(b), (6) If a pipeline segment has been pre- (c), or (d) applies, use the following de- viously operated, the segment has not sign factors as alternatives for the fac- experienced any failure during normal tors specified in those paragraphs: ¥ operations indicative of a systemic § 192.111(b) 0.67 or less; 192.111(c) and fault in material as determined by a (d)¥0.56 or less. root cause analysis, including met- (ii) [Reserved] allurgical examination of the failed (2) The alternative maximum allow- pipe. The results of this root cause able operating pressure is the lower of analysis must be reported to each the following: PHMSA pipeline safety regional office (i) The design pressure of the weakest where the pipeline is in service at least element in the pipeline segment, deter- 60 days prior to operation at the alter- mined under subparts C and D of this native MAOP. An operator must also part. notify a State pipeline safety authority (ii) The pressure obtained by dividing when the pipeline is located in a State the pressure to which the pipeline seg- where PHMSA has an interstate agent ment was tested after construction by agreement, or an intrastate pipeline is a factor determined in the following regulated by that State; and table: (7) At least 95 percent of girth welds on a segment that was constructed Class location Alternative test factor prior to December 22, 2008, must have 1 ...... 1.25 been non-destructively examined in ac- 2 ...... 1 1.50 cordance with § 192.243(b) and (c).

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(c) What is an operator electing to use (ii) For a pipeline segment in exist- the alternative maximum allowable oper- ence prior to December 22, 2008, certify, ating pressure required to do? If an oper- under paragraph (c)(2) of this section, ator elects to use the alternative max- that the strength test performed under imum allowable operating pressure cal- § 192.505 was conducted at test pressure culated under paragraph (a) of this sec- calculated under paragraph (a) of this tion for a pipeline segment, the oper- section, or conduct a new strength test ator must do each of the following: in accordance with paragraph (c)(4)(i) (1) Notify each PHMSA pipeline safe- of this section. ty regional office where the pipeline is (5) Comply with the additional oper- in service of its election with respect ation and maintenance requirements to a segment at least 180 days before described in paragraph (d) of this sec- operating at the alternative maximum tion. allowable operating pressure. An operator must also notify a State pipeline (6) If the performance of a construc- safety authority when the pipeline is tion task associated with imple- located in a State where PHMSA has menting alternative MAOP that occurs an interstate agent agreement, or an after December 22, 2008, can affect the intrastate pipeline is regulated by that integrity of the pipeline segment, treat State. that task as a ‘‘covered task’’, notwith- (2) Certify, by signature of a senior standing the definition in § 192.801(b) executive officer of the company, as and implement the requirements of follows: subpart N as appropriate. (i) The pipeline segment meets the (7) Maintain, for the useful life of the conditions described in paragraph (b) of pipeline, records demonstrating com- this section; and pliance with paragraphs (b), (c)(6), and (ii) The operating and maintenance (d) of this section. procedures include the additional oper- (8) A Class 1 and Class 2 pipeline loca- ating and maintenance requirements of tion can be upgraded one class due to paragraph (d) of this section; and class changes per § 192.611(a)(3)(i). All (iii) The review and any needed pro- class location changes from Class 1 to gram upgrade of the damage preven- Class 2 and from Class 2 to Class 3 must tion program required by paragraph have all anomalies evaluated and reme- (d)(4)(v) of this section has been com- diated per: The ‘‘original pipeline class pleted. grade’’ § 192.620(d)(11) anomaly repair (3) Send a copy of the certification requirements; and all anomalies with a required by paragraph (c)(2) of this sec- wall loss equal to or greater than 40 tion to each PHMSA pipeline safety re- percent must be excavated and remedi- gional office where the pipeline is in service 30 days prior to operating at ated. Pipelines in Class 4 may not oper- the alternative MAOP. An operator ate at an alternative MAOP. must also send a copy to a State pipe- (d) What additional operation and line safety authority when the pipeline maintenance requirements apply to oper- is located in a State where PHMSA has ation at the alternative maximum allow- an interstate agent agreement, or an able operating pressure? In addition to intrastate pipeline is regulated by that compliance with other applicable safe- State. ty standards in this part, if an operator (4) For each pipeline segment, do one establishes a maximum allowable oper- of the following: ating pressure for a pipeline segment (i) Perform a strength test as de- under paragraph (a) of this section, an scribed in § 192.505 at a test pressure operator must comply with the addi- calculated under paragraph (a) of this tional operation and maintenance re- section or quirements as follows:

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

(1) Identifying and evaluating Develop a threat matrix consistent with § 192.917 to do the following: threats. (i) Identify and compare the increased risk of operating the pipeline at the increased stress level under this section with conventional operation; and (ii) Describe and implement procedures used to mitigate the risk. (2) Notifying the public ...... (i) Recalculate the potential impact circle as defined in § 192.903 to reflect use of the alternative maximum operating pressure calculated under paragraph (a) of this section and pipeline operating conditions; and (ii) In implementing the public education program required under § 192.616, perform the following: (A) Include persons occupying property within 220 yards of the centerline and within the potential impact circle within the targeted audience; and (B) Include information about the integrity management activities performed under this section within the message provided to the audience. (3) Responding to an emer- (i) Ensure that the identification of high consequence areas reflects the larger potential impact gency in an area defined as circle recalculated under paragraph (d)(2)(i) of this section. a high consequence area in § 192.903. (ii) If personnel response time to mainline valves on either side of the high consequence area exceeds one hour (under normal driving conditions and speed limits) from the time the event is identified in the control room, provide remote valve control through a supervisory control and data acquisition (SCADA) system, other leak detection system, or an alternative method of control. (iii) Remote valve control must include the ability to close and monitor the valve position (open or closed), and monitor pressure upstream and downstream. (iv) A line break valve control system using differential pressure, rate of pressure drop or other widely-accepted method is an acceptable alternative to remote valve control. (4) Protecting the right-of-way .. (i) Patrol the right-of-way at intervals not exceeding 45 days, but at least 12 times each calendar year, to inspect for excavation activities, ground movement, wash outs, leakage, or other activities or conditions affecting the safety operation of the pipeline. (ii) Develop and implement a plan to monitor for and mitigate occurrences of unstable soil and ground movement. (iii) If observed conditions indicate the possible loss of cover, perform a depth of cover study and replace cover as necessary to restore the depth of cover or apply alternative means to provide protection equivalent to the originally-required depth of cover. (iv) Use line-of-sight line markers satisfying the requirements of § 192.707(d) except in agricul- tural areas, large water crossings or swamp, steep terrain, or where prohibited by Federal Energy Regulatory Commission orders, permits, or local law. (v) Review the damage prevention program under § 192.614(a) in light of national consensus practices, to ensure the program provides adequate protection of the right-of-way. Identify the standards or practices considered in the review, and meet or exceed those standards or practices by incorporating appropriate changes into the program. (vi) Develop and implement a right-of-way management plan to protect the pipeline segment from damage due to excavation activities. (5) Controlling internal corro- (i) Develop and implement a program to monitor for and mitigate the presence of, deleterious sion. gas stream constituents. (ii) At points where gas with potentially deleterious contaminants enters the pipeline, use filter separators or separators and gas quality monitoring equipment. (iii) Use gas quality monitoring equipment that includes a moisture analyzer, chromatograph, and periodic hydrogen sulfide sampling. (iv) Use cleaning pigs and sample accumulated liquids. Use inhibitors when corrosive gas or liquids are present. (v) Address deleterious gas stream constituents as follows: (A) Limit carbon dioxide to 3 percent by volume; (B) Allow no free water and otherwise limit water to seven pounds per million cubic feet of gas; and (C) Limit hydrogen sulfide to 1.0 grain per hundred cubic feet (16 ppm) of gas, where the hydrogen sulfide is greater than 0.5 grain per hundred cubic feet (8 ppm) of gas, implement a pigging and inhibitor injection program to address deleterious gas stream constituents, including follow-up sampling and quality testing of liquids at receipt points. (vi) Review the program at least quarterly based on the gas stream experience and implement adjustments to monitor for, and mitigate the presence of, deleterious gas stream constituents. (6) Controlling interference that (i) Prior to operating an existing pipeline segment at an alternate maximum allowable oper- can impact external corrosion. ating pressure calculated under this section, or within six months after placing a new pipeline segment in service at an alternate maximum allowable operating pressure calculated under this section, address any interference currents on the pipeline segment. (ii) To address interference currents, perform the following: (A) Conduct an interference survey to detect the presence and level of any electrical current that could impact external corrosion where interference is suspected; (B) Analyze the results of the survey; and

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

(C) Take any remedial action needed within 6 months after completing the survey to protect the pipeline segment from deleterious current. (7) Confirming external corro- (i) Within six months after placing the cathodic protection of a new pipeline segment in oper- sion control through indirect ation, or within six months after certifying a segment under § 192.620(c)(1) of an existing assessment. pipeline segment under this section, assess the adequacy of the cathodic protection through an indirect method such as close-interval survey, and the integrity of the coating using direct current voltage gradient (DCVG) or alternating current voltage gradient (ACVG). (ii) Remediate any construction damaged coating with a voltage drop classified as moderate or severe (IR drop greater than 35% for DCVG or 50 dBμv for ACVG) under section 4 of NACE RP–0502–2002 (incorporated by reference, see § 192.7). (iii) Within six months after completing the baseline internal inspection required under paragraph (d)(9) of this section, integrate the results of the indirect assessment required under paragraph (d)(7)(i) of this section with the results of the baseline internal inspection and take any needed remedial actions. (iv) For all pipeline segments in high consequence areas, perform periodic assessments as follows: (A) Conduct periodic close interval surveys with current interrupted to confirm voltage drops in association with periodic assessments under subpart O of this part. (B) Locate pipe-to-soil test stations at half-mile intervals within each high consequence area ensuring at least one station is within each high consequence area, if practicable. (C) Integrate the results with those of the baseline and periodic assessments for integrity done under paragraphs (d)(9) and (d)(10) of this section. (8) Controlling external corro- (i) If an annual test station reading indicates cathodic protection below the level of protection sion through cathodic protec- required in subpart I of this part, complete remedial action within six months of the failed tion. reading or notify each PHMSA pipeline safety regional office where the pipeline is in service demonstrating that the integrity of the pipeline is not compromised if the repair takes longer than 6 months. An operator must also notify a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State; and (ii) After remedial action to address a failed reading, confirm restoration of adequate corrosion control by a close interval survey on either side of the affected test station to the next test station unless the reason for the failed reading is determined to be a rectifier connection or power input problem that can be remediated and otherwise verified. (iii) If the pipeline segment has been in operation, the cathodic protection system on the pipeline segment must have been operational within 12 months of the completion of construction. (9) Conducting a baseline as- (i) Except as provided in paragraph (d)(9)(iii) of this section, for a new pipeline segment oper- sessment of integrity. ating at the new alternative maximum allowable operating pressure, perform a baseline internal inspection of the entire pipeline segment as follows: (A) Assess using a geometry tool after the initial hydrostatic test and backfill and within six months after placing the new pipeline segment in service; and (B) Assess using a high resolution magnetic flux tool within three years after placing the new pipeline segment in service at the alternative maximum allowable operating pressure. (ii) Except as provided in paragraph (d)(9)(iii) of this section, for an existing pipeline segment, perform a baseline internal assessment using a geometry tool and a high resolution magnetic flux tool before, but within two years prior to, raising pressure to the alternative maximum allowable operating pressure as allowed under this section. (iii) If headers, mainline valve by-passes, compressor station piping, meter station piping, or other short portion of a pipeline segment operating at alternative maximum allowable operating pressure cannot accommodate a geometry tool and a high resolution magnetic flux tool, use direct assessment (per § 192.925, § 192.927 and/or § 192.929) or pressure testing (per subpart J of this part) to assess that portion. (10) Conducting periodic as- (i) Determine a frequency for subsequent periodic integrity assessments as if all the alternative sessments of integrity. maximum allowable operating pressure pipeline segments were covered by subpart O of this part and (ii) Conduct periodic internal inspections using a high resolution magnetic flux tool on the frequency determined under paragraph (d)(10)(i) of this section, or (iii) Use direct assessment (per § 192.925, § 192.927 and/or § 192.929) or pressure testing (per subpart J of this part) for periodic assessment of a portion of a segment to the extent permitted for a baseline assessment under paragraph (d)(9)(iii) of this section. (11) Making repairs ...... (i) Perform the following when evaluating an anomaly: (A) Use the most conservative calculation for determining remaining strength or an alternative validated calculation based on pipe diameter, wall thickness, grade, operating pressure, operating stress level, and operating temperature: and (B) Take into account the tolerances of the tools used for the inspection. (ii) Repair a defect immediately if any of the following apply: (A) The defect is a dent discovered during the baseline assessment for integrity under paragraph (d)(9) of this section and the defect meets the criteria for immediate repair in § 192.309(b). (B) The defect meets the criteria for immediate repair in § 192.933(d).

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

(C) The alternative maximum allowable operating pressure was based on a design factor of 0.67 under paragraph (a) of this section and the failure pressure is less than 1.25 times the alternative maximum allowable operating pressure. (D) The alternative maximum allowable operating pressure was based on a design factor of 0.56 under paragraph (a) of this section and the failure pressure is less than or equal to 1.4 times the alternative maximum allowable operating pressure. (iii) If paragraph (d)(11)(ii) of this section does not require immediate repair, repair a defect within one year if any of the following apply: (A) The defect meets the criteria for repair within one year in § 192.933(d). (B) The alternative maximum allowable operating pressure was based on a design factor of 0.80 under paragraph (a) of this section and the failure pressure is less than 1.25 times the alternative maximum allowable operating pressure. (C) The alternative maximum allowable operating pressure was based on a design factor of 0.67 under paragraph (a) of this section and the failure pressure is less than 1.50 times the alternative maximum allowable operating pressure. (D) The alternative maximum allowable operating pressure was based on a design factor of 0.56 under paragraph (a) of this section and the failure pressure is less than or equal to 1.80 times the alternative maximum allowable operating pressure. (iv) Evaluate any defect not required to be repaired under paragraph (d)(11)(ii) or (iii) of this section to determine its growth rate, set the maximum interval for repair or re-inspection, and repair or re-inspect within that interval.

(e) Is there any change in overpressure p.s.i. (414 kPa) gage, unless the service protection associated with operating at lines in the segment are equipped with the alternative maximum allowable oper- service regulators or other pressure ating pressure? Notwithstanding the re- limiting devices in series that meet the quired capacity of pressure relieving requirements of § 192.197(c). and limiting stations otherwise re- (3) 25 p.s.i. (172 kPa) gage in segments quired by § 192.201, if an operator estab- of cast iron pipe in which there are lishes a maximum allowable operating unreinforced bell and spigot joints. pressure for a pipeline segment in ac- (4) The pressure limits to which a cordance with paragraph (a) of this sec- joint could be subjected without the tion, an operator must: possibility of its parting. (1) Provide overpressure protection (5) The pressure determined by the that limits mainline pressure to a max- operator to be the maximum safe pres- imum of 104 percent of the maximum sure after considering the history of allowable operating pressure; and the segment, particularly known corro- (2) Develop and follow a procedure for sion and the actual operating pres- establishing and maintaining accurate sures. set points for the supervisory control and data acquisition system. (b) No person may operate a segment of pipeline to which paragraph (a)(5) of [73 FR 62177, Oct. 17, 2008, as amended by this section applies, unless over- Amdt. 192–111, 74 FR 62505, Nov. 30, 2009] pressure protective devices are installed on the segment in a manner § 192.621 Maximum allowable operating pressure: High-pressure dis- that will prevent the maximum allow- tribution systems. able operating pressure from being exceeded, in accordance with § 192.195. (a) No person may operate a segment of a high pressure distribution system [35 FR 13257, Aug. 19, 1970, as amended by at a pressure that exceeds the lowest of Amdt 192–85, 63 FR 37504, July 13, 1998] the following pressures, as applicable: (1) The design pressure of the weak- § 192.623 Maximum and minimum al- est element in the segment, deter- lowable operating pressure; Low- mined in accordance with subparts C pressure distribution systems. and D of this part. (a) No person may operate a low-pres- (2) 60 p.s.i. (414 kPa) gage, for a seg- sure distribution system at a pressure ment of a distribution system other- high enough to make unsafe the oper- wise designed to operate at over 60 ation of any connected and properly

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adjusted low-pressure gas burning the products of combustion will be ex- equipment. posed. (b) No person may operate a low pres- (d) The odorant may not be soluble in sure distribution system at a pressure water to an extent greater than 2.5 lower than the minimum pressure at parts to 100 parts by weight. which the safe and continuing oper- (e) Equipment for odorization must ation of any connected and properly introduce the odorant without wide adjusted low-pressure gas burning variations in the level of odorant. equipment can be assured. (f) To assure the proper concentration of odorant in accordance with this § 192.625 Odorization of gas. section, each operator must conduct (a) A combustible gas in a distribu- periodic sampling of combustible gases tion line must contain a natural odor- using an instrument capable of deter- ant or be odorized so that at a con- mining the percentage of gas in air at centration in air of one-fifth of the which the odor becomes readily detect- lower explosive limit, the gas is readily able. Operators of master meter sys- detectable by a person with a normal tems may comply with this require- sense of smell. ment by— (b) After December 31, 1976, a com- (1) Receiving written verification bustible gas in a transmission line in a from their gas source that the gas has Class 3 or Class 4 location must comply the proper concentration of odorant; with the requirements of paragraph (a) and of this section unless: (1) At least 50 percent of the length of (2) Conducting periodic ‘‘sniff’’ tests the line downstream from that location at the extremities of the system to is in a Class 1 or Class 2 location; confirm that the gas contains odorant. (2) The line transports gas to any of [35 FR 13257, Aug. 19, 1970] the following facilities which received gas without an odorant from that line EDITORIAL NOTE: For FEDERAL REGISTER citations affecting § 192.625, see the List of CFR before May 5, 1975; Sections Affected, which appears in the (i) An underground storage field; Finding Aids section of the printed volume (ii) A gas processing plant; and at www.fdsys.gov. (iii) A gas dehydration plant; or (iv) An industrial plant using gas in a § 192.627 Tapping pipelines under process where the presence of an odor- pressure. ant: Each tap made on a pipeline under (A) Makes the end product unfit for pressure must be performed by a crew the purpose for which it is intended; qualified to make hot taps. (B) Reduces the activity of a cata- lyst; or § 192.629 Purging of pipelines. (C) Reduces the percentage completion of a chemical reaction; (a) When a pipeline is being purged of (3) In the case of a lateral line which air by use of gas, the gas must be re- transports gas to a distribution center, leased into one end of the line in a at least 50 percent of the length of that moderately rapid and continuous flow. line is in a Class 1 or Class 2 location; If gas cannot be supplied in sufficient or quantity to prevent the formation of a (4) The combustible gas is hydrogen hazardous mixture of gas and air, a intended for use as a feedstock in a slug of inert gas must be released into manufacturing process. the line before the gas. (c) In the concentrations in which it (b) When a pipeline is being purged of is used, the odorant in combustible gas by use of air, the air must be re- gases must comply with the following: leased into one end of the line in a (1) The odorant may not be delete- moderately rapid and continuous flow. rious to persons, materials, or pipe. If air cannot be supplied in sufficient (2) The products of combustion from quantity to prevent the formation of a the odorant may not be toxic when hazardous mixture of gas and air, a breathed nor may they be corrosive or slug of inert gas must be released into harmful to those materials to which the line before the air.

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§ 192.631 Control room management. even if the controller is not the first to (a) General. detect the condition, including the con- (1) This section applies to each oper- troller’s responsibility to take specific ator of a pipeline facility with a con- actions and to communicate with oth- troller working in a control room who ers; monitors and controls all or part of a (3) A controller’s role during an pipeline facility through a SCADA sys- emergency, even if the controller is not tem. Each operator must have and fol- the first to detect the emergency, in- low written control room management cluding the controller’s responsibility procedures that implement the require- to take specific actions and to commu- ments of this section, except that for nicate with others; and each control room where an operator’s (4) A method of recording controller activities are limited to either or both shift-changes and any hand-over of re- of: sponsibility between controllers. (i) Distribution with less than 250,000 (c) Provide adequate information. Each services, or operator must provide its controllers (ii) Transmission without a com- with the information, tools, processes pressor station, the operator must have and procedures necessary for the con- and follow written procedures that im- trollers to carry out the roles and re- plement only paragraphs (d) (regarding sponsibilities the operator has defined fatigue), (i) (regarding compliance vali- by performing each of the following: dation), and (j) (regarding compliance (1) Implement sections 1, 4, 8, 9, 11.1, and deviations) of this section. and 11.3 of API RP 1165 (incorporated (2) The procedures required by this by reference, see § 192.7) whenever a section must be integrated, as appro- SCADA system is added, expanded or priate, with operating and emergency replaced, unless the operator dem- procedures required by §§ 192.605 and onstrates that certain provisions of 192.615. An operator must develop the sections 1, 4, 8, 9, 11.1, and 11.3 of API procedures no later than August 1, 2011, RP 1165 are not practical for the and must implement the procedures ac- SCADA system used; cording to the following schedule. The procedures required by paragraphs (b), (2) Conduct a point-to-point (c)(5), (d)(2) and (d)(3), (f) and (g) of this verification between SCADA displays section must be implemented no later and related field equipment when field than October 1, 2011. The procedures re- equipment is added or moved and when quired by paragraphs (c)(1) through (4), other changes that affect pipeline safe- (d)(1), (d)(4), and (e) must be imple- ty are made to field equipment or mented no later than August 1, 2012. SCADA displays; The training procedures required by (3) Test and verify an internal com- paragraph (h) must be implemented no munication plan to provide adequate later than August 1, 2012, except that means for manual operation of the any training required by another para- pipeline safely, at least once each cal- graph of this section must be imple- endar year, but at intervals not to ex- mented no later than the deadline for ceed 15 months; that paragraph. (4) Test any backup SCADA systems (b) Roles and responsibilities. Each op- at least once each calendar year, but at erator must define the roles and re- intervals not to exceed 15 months; and sponsibilities of a controller during (5) Establish and implement proce- normal, abnormal, and emergency op- dures for when a different controller erating conditions. To provide for a assumes responsibility, including the controller’s prompt and appropriate re- content of information to be ex- sponse to operating conditions, an op- changed. erator must define each of the fol- (d) Fatigue mitigation. Each operator lowing: must implement the following methods (1) A controller’s authority and re- to reduce the risk associated with con- sponsibility to make decisions and troller fatigue that could inhibit a con- take actions during normal operations; troller’s ability to carry out the roles (2) A controller’s role when an abnor- and responsibilities the operator has mal operating condition is detected, defined:

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(1) Establish shift lengths and sched- affect control room operations are co- ule rotations that provide controllers ordinated with the control room per- off-duty time sufficient to achieve sonnel by performing each of the fol- eight hours of continuous sleep; lowing: (2) Educate controllers and super- (1) Establish communications be- visors in fatigue mitigation strategies tween control room representatives, and how off-duty activities contribute operator’s management, and associated to fatigue; field personnel when planning and im- (3) Train controllers and supervisors plementing physical changes to pipe- to recognize the effects of fatigue; and line equipment or configuration; (4) Establish a maximum limit on (2) Require its field personnel to con- controller hours-of-service, which may tact the control room when emergency provide for an emergency deviation conditions exist and when making field from the maximum limit if necessary changes that affect control room oper- for the safe operation of a pipeline fa- ations; and cility. (3) Seek control room or control (e) Alarm management. Each operator room management participation in using a SCADA system must have a planning prior to implementation of written alarm management plan to significant pipeline hydraulic or con- provide for effective controller re- figuration changes. sponse to alarms. An operator’s plan (g) Operating experience. Each oper- must include provisions to: ator must assure that lessons learned (1) Review SCADA safety-related from its operating experience are in- alarm operations using a process that corporated, as appropriate, into its ensures alarms are accurate and sup- control room management procedures port safe pipeline operations; by performing each of the following: (2) Identify at least once each cal- (1) Review incidents that must be re- endar month points affecting safety ported pursuant to 49 CFR part 191 to that have been taken off scan in the determine if control room actions con- SCADA host, have had alarms inhib- tributed to the event and, if so, cor- ited, generated false alarms, or that rect, where necessary, deficiencies re- have had forced or manual values for lated to: periods of time exceeding that required (i) Controller fatigue; for associated maintenance or oper- (ii) Field equipment; ating activities; (iii) The operation of any relief de- (3) Verify the correct safety-related vice; alarm set-point values and alarm de- (iv) Procedures; scriptions at least once each calendar (v) SCADA system configuration; and year, but at intervals not to exceed 15 (vi) SCADA system performance. months; (2) Include lessons learned from the (4) Review the alarm management operator’s experience in the training plan required by this paragraph at program required by this section. least once each calendar year, but at (h) Training. Each operator must es- intervals not exceeding 15 months, to tablish a controller training program determine the effectiveness of the plan; and review the training program con- (5) Monitor the content and volume tent to identify potential improve- of general activity being directed to ments at least once each calendar year, and required of each controller at least but at intervals not to exceed 15 once each calendar year, but at inter- months. An operator’s program must vals not to exceed 15 months, that will provide for training each controller to assure controllers have sufficient time carry out the roles and responsibilities to analyze and react to incoming defined by the operator. In addition, alarms; and the training program must include the (6) Address deficiencies identified following elements: through the implementation of para- (1) Responding to abnormal operating graphs (e)(1) through (e)(5) of this sec- conditions likely to occur simulta- tion. neously or in sequence; (f) Change management. Each operator (2) Use of a computerized simulator must assure that changes that could or non-computerized (tabletop) method

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for training controllers to recognize line right-of-way for indications of abnormal operating conditions; leaks, construction activity, and other (3) Training controllers on their re- factors affecting safety and operation. sponsibilities for communication under (b) The frequency of patrols is deter- the operator’s emergency response pro- mined by the size of the line, the oper- cedures; ating pressures, the class location, ter- (4) Training that will provide a con- rain, weather, and other relevant fac- troller a working knowledge of the tors, but intervals between patrols may pipeline system, especially during the not be longer than prescribed in the development of abnormal operating following table: conditions; and (5) For pipeline operating setups that Maximum interval between patrols are periodically, but infrequently used, Class loca- At highway and rail- providing an opportunity for control- tion of line road crossings At all other places lers to review relevant procedures in advance of their application. 1, 2 ...... 71⁄2 months; but at 15 months; but at least twice each cal- least once each cal- (i) Compliance validation. Upon re- endar year. endar year. quest, operators must submit their pro- 3 ...... 41⁄2 months; but at 71⁄2 months; but at cedures to PHMSA or, in the case of an least four times least twice each cal- intrastate pipeline facility regulated each calendar year. endar year. 4 ...... 41⁄2 months; but at 41⁄2 months; but at by a State, to the appropriate State least four times least four times agency. each calendar year. each calendar year. (j) Compliance and deviations. An operator must maintain for review during (c) Methods of patrolling include inspection: walking, driving, flying or other appro- (1) Records that demonstrate compli- priate means of traversing the right-of- ance with the requirements of this sec- way. tion; and (2) Documentation to demonstrate [Amdt. 192–21, 40 FR 20283, May 9, 1975, as that any deviation from the procedures amended by Amdt. 192–43, 47 FR 46851, Oct. required by this section was necessary 21, 1982; Amdt. 192–78, 61 FR 28786, June 6, 1996] for the safe operation of a pipeline facility. § 192.706 Transmission lines: Leakage [Amdt. 192–112, 74 FR 63327, Dec. 3, 2009, as surveys. amended at 75 FR 5537, Feb. 3, 2010; 76 FR Leakage surveys of a transmission 35135, June 16, 2011] line must be conducted at intervals not exceeding 15 months, but at least once Subpart M—Maintenance each calendar year. However, in the case of a transmission line which § 192.701 Scope. transports gas in conformity with This subpart prescribes minimum re- § 192.625 without an odor or odorant, quirements for maintenance of pipeline leakage surveys using leak detector facilities. equipment must be conducted— § 192.703 General. (a) In Class 3 locations, at intervals not exceeding 71⁄2 months, but at least (a) No person may operate a segment twice each calendar year; and of pipeline, unless it is maintained in (b) In Class 4 locations, at intervals accordance with this subpart. not exceeding 41⁄2 months, but at least (b) Each segment of pipeline that be- four times each calendar year. comes unsafe must be replaced, repaired, or removed from service. [Amdt. 192–21, 40 FR 20283, May 9, 1975, as (c) Hazardous leaks must be repaired amended by Amdt. 192–43, 47 FR 46851, Oct. promptly. 21, 1982; Amdt. 192–71, 59 FR 6585, Feb. 11, 1994] § 192.705 Transmission lines: Patrol- ling. § 192.707 Line markers for mains and (a) Each operator shall have a patrol transmission lines. program to observe surface conditions (a) Buried pipelines. Except as pro- on and adjacent to the transmission vided in paragraph (b) of this section, a

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line marker must be placed and main- (a) The date, location, and descrip- tained as close as practical over each tion of each repair made to pipe (in- buried main and transmission line: cluding pipe-to-pipe connections) must (1) At each crossing of a public road be retained for as long as the pipe re- and railroad; and mains in service. (2) Wherever necessary to identify (b) The date, location, and descrip- the location of the transmission line or tion of each repair made to parts of the main to reduce the possibility of dam- pipeline system other than pipe must age or interference. be retained for at least 5 years. How- (b) Exceptions for buried pipelines. Line ever, repairs generated by patrols, sur- markers are not required for the fol- veys, inspections, or tests required by lowing pipelines: subparts L and M of this part must be (1) Mains and transmission lines lo- retained in accordance with paragraph cated offshore, or at crossings of or (c) of this section. under waterways and other bodies of (c) A record of each patrol, survey, water. inspection, and test required by sub- (2) Mains in Class 3 or Class 4 loca- parts L and M of this part must be re- tions where a damage prevention pro- tained for at least 5 years or until the gram is in effect under § 192.614. next patrol, survey, inspection, or test is completed, whichever is longer. (3) Transmission lines in Class 3 or 4 locations until March 20, 1996. [Amdt. 192–78, 61 FR 28786, June 6, 1996] (4) Transmission lines in Class 3 or 4 locations where placement of a line § 192.711 Transmission lines: General marker is impractical. requirements for repair procedures. (c) Pipelines aboveground. Line mark- (a) Temporary repairs. Each operator ers must be placed and maintained must take immediate temporary meas- along each section of a main and trans- ures to protect the public whenever: mission line that is located above- (1) A leak, imperfection, or damage ground in an area accessible to the that impairs its serviceability is found public. in a segment of steel transmission line (d) Marker warning. The following operating at or above 40 percent of the must be written legibly on a back- SMYS; and ground of sharply contrasting color on (2) It is not feasible to make a perma- each line marker: nent repair at the time of discovery. (1) The word ‘‘Warning,’’ ‘‘Caution,’’ (b) Permanent repairs. An operator or ‘‘Danger’’ followed by the words must make permanent repairs on its ‘‘Gas (or name of gas transported) pipeline system according to the fol- Pipeline’’ all of which, except for lowing: markers in heavily developed urban (1) Non integrity management re- areas, must be in letters at least 1 inch pairs: The operator must make perma- (25 millimeters) high with 1⁄4 inch (6.4 nent repairs as soon as feasible. millimeters) stroke. (2) Integrity management repairs: (2) The name of the operator and the When an operator discovers a condition telephone number (including area code) on a pipeline covered under Subpart O– where the operator can be reached at Gas Transmission Pipeline Integrity all times. Management, the operator must remediate the condition as prescribed by [Amdt. 192–20, 40 FR 13505, Mar. 27, 1975; § 192.933(d). Amdt. 192–27, 41 FR 39752, Sept. 16, 1976, as (c) Welded patch. Except as provided amended by Amdt. 192–20A, 41 FR 56808, Dec. in § 192.717(b)(3), no operator may use a 30, 1976; Amdt. 192–44, 48 FR 25208, June 6, 1983; Amdt. 192–73, 60 FR 14650, Mar. 20, 1995; welded patch as a means of repair. Amdt. 192–85, 63 FR 37504, July 13, 1998] [Amdt. 192–114, 75 FR 48604, Aug. 11, 2010]

§ 192.709 Transmission lines: Record § 192.713 Transmission lines: Perma- keeping. nent field repair of imperfections Each operator shall maintain the fol- and damages. lowing records for transmission lines (a) Each imperfection or damage that for the periods specified: impairs the serviceability of pipe in a

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steel transmission line operating at or (2) If the leak is due to a corrosion above 40 percent of SMYS must be— pit, install a properly designed bolt-on- (1) Removed by cutting out and re- leak clamp. placing a cylindrical piece of pipe; or (3) If the leak is due to a corrosion (2) Repaired by a method that reli- pit and on pipe of not more than 40,000 able engineering tests and analyses psi (267 Mpa) SMYS, fillet weld over show can permanently restore the serv- the pitted area a steel plate patch with iceability of the pipe. rounded corners, of the same or greater (b) Operating pressure must be at a thickness than the pipe, and not more safe level during repair operations. than one-half of the diameter of the [Amdt. 192–88, 64 FR 69665, Dec. 14, 1999] pipe in size. (4) If the leak is on a submerged off- § 192.715 Transmission lines: Perma- shore pipeline or submerged pipeline in nent field repair of welds. inland navigable waters, mechanically Each weld that is unacceptable under apply a full encirclement split sleeve of § 192.241(c) must be repaired as follows: appropriate design. (a) If it is feasible to take the seg- (5) Apply a method that reliable engi- ment of transmission line out of serv- neering tests and analyses show can ice, the weld must be repaired in ac- permanently restore the serviceability cordance with the applicable require- of the pipe. ments of § 192.245. [Amdt. 192–88, 64 FR 69665, Dec. 14, 1999] (b) A weld may be repaired in accordance with § 192.245 while the segment of § 192.719 Transmission lines: Testing transmission line is in service if: of repairs. (1) The weld is not leaking; (2) The pressure in the segment is re- (a) Testing of replacement pipe. If a duced so that it does not produce a segment of transmission line is re- stress that is more than 20 percent of paired by cutting out the damaged por- the SMYS of the pipe; and tion of the pipe as a cylinder, the re- (3) Grinding of the defective area can placement pipe must be tested to the be limited so that at least 1⁄8-inch (3.2 pressure required for a new line in- millimeters) thickness in the pipe weld stalled in the same location. This test remains. may be made on the pipe before it is in- (c) A defective weld which cannot be stalled. repaired in accordance with paragraph (b) Testing of repairs made by welding. (a) or (b) of this section must be re- Each repair made by welding in accord- paired by installing a full encirclement ance with §§ 192.713, 192.715, and 192.717 welded split sleeve of appropriate de- must be examined in accordance with sign. § 192.241. [35 FR 13257, Aug. 19, 1970, as amended by [35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192–85, 63 FR 37504, July 13, 1998] Amdt. 192–54, 51 FR 41635, Nov. 18, 1986]

§ 192.717 Transmission lines: Perma- § 192.721 Distribution systems: Patrol- nent field repair of leaks. ling. Each permanent field repair of a leak (a) The frequency of patrolling mains on a transmission line must be made must be determined by the severity of by— the conditions which could cause fail- (a) Removing the leak by cutting out ure or leakage, and the consequent haz- and replacing a cylindrical piece of ards to public safety. pipe; or (b) Mains in places or on structures (b) Repairing the leak by one of the where anticipated physical movement following methods: or external loading could cause failure (1) Install a full encirclement welded or leakage must be patrolled— split sleeve of appropriate design, un- (1) In business districts, at intervals less the transmission line is joined by 1 mechanical couplings and operates at not exceeding 4 ⁄2 months, but at least less than 40 percent of SMYS. four times each calendar year; and

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(2) Outside business districts, at in- ner as a new service line, before recon- tervals not exceeding 71⁄2 months, but necting. However, if provisions are at least twice each calendar year. made to maintain continuous service, such as by installation of a bypass, any [35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192–43, 47 FR 46851, Oct. 21, 1982; Amdt. part of the original service line used to 192–78, 61 FR 28786, June 6, 1996] maintain continuous service need not be tested. § 192.723 Distribution systems: Leak- age surveys. § 192.727 Abandonment or deactiva- (a) Each operator of a distribution tion of facilities. system shall conduct periodic leakage (a) Each operator shall conduct aban- surveys in accordance with this sec- donment or deactivation of pipelines in tion. accordance with the requirements of (b) The type and scope of the leakage this section. control program must be determined (b) Each pipeline abandoned in place by the nature of the operations and the must be disconnected from all sources local conditions, but it must meet the and supplies of gas; purged of gas; in following minimum requirements: the case of offshore pipelines, filled (1) A leakage survey with leak detec- with water or inert materials; and tor equipment must be conducted in sealed at the ends. However, the pipe- business districts, including tests of line need not be purged when the vol- the atmosphere in gas, electric, tele- ume of gas is so small that there is no phone, sewer, and water system man- potential hazard. holes, at cracks in pavement and side- (c) Except for service lines, each in- walks, and at other locations providing active pipeline that is not being main- an opportunity for finding gas leaks, at tained under this part must be discon- intervals not exceeding 15 months, but nected from all sources and supplies of at least once each calendar year. gas; purged of gas; in the case of off- (2) A leakage survey with leak detec- shore pipelines, filled with water or tor equipment must be conducted out- inert materials; and sealed at the ends. side business districts as frequently as However, the pipeline need not be necessary, but at least once every 5 purged when the volume of gas is so calendar years at intervals not exceed- small that there is no potential hazard. ing 63 months. However, for cathodi- (d) Whenever service to a customer is cally unprotected distribution lines discontinued, one of the following must subject to § 192.465(e) on which elec- be complied with: trical surveys for corrosion are imprac- (1) The valve that is closed to prevent tical, a leakage survey must be con- the flow of gas to the customer must be ducted at least once every 3 calendar provided with a locking device or other years at intervals not exceeding 39 means designed to prevent the opening months. of the valve by persons other than [35 FR 13257, Aug. 19, 1970, as amended by those authorized by the operator. Amdt. 192–43, 47 FR 46851, Oct. 21, 1982; Amdt. (2) A mechanical device or fitting 192–70, 58 FR 54528, 54529, Oct. 22, 1993; Amdt. that will prevent the flow of gas must 192–71, 59 FR 6585, Feb. 11, 1994; Amdt. 192–94, be installed in the service line or in the 69 FR 32895, June 14, 2004; Amdt. 192–94, 69 FR 54592, Sept. 9, 2004] meter assembly. (3) The customer’s piping must be § 192.725 Test requirements for rein- physically disconnected from the gas stating service lines. supply and the open pipe ends sealed. (a) Except as provided in paragraph (e) If air is used for purging, the oper- (b) of this section, each disconnected ator shall insure that a combustible service line must be tested in the same mixture is not present after purging. manner as a new service line, before (f) Each abandoned vault must be being reinstated. filled with a suitable compacted mate- (b) Each service line temporarily dis- rial. connected from the main must be test- (g) For each abandoned offshore pipe- ed from the point of disconnection to line facility or each abandoned onshore the service line valve in the same man- pipeline facility that crosses over,

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under or through a commercially navi- (2) [Reserved] gable waterway, the last operator of [Amdt. 192–8, 37 FR 20695, Oct. 3, 1972, as that facility must file a report upon amended by Amdt. 192–27, 41 FR 34607, Aug. abandonment of that facility. 16, 1976; Amdt. 192–71, 59 FR 6585, Feb. 11, (1) The preferred method to submit 1994; Amdt. 192–89, 65 FR 54443, Sept. 8, 2000; data on pipeline facilities abandoned 65 FR 57861, Sept. 26, 2000; 70 FR 11139, Mar. after October 10, 2000 is to the National 8, 2005; Amdt. 192–103, 72 FR 4656, Feb. 1, 2007; 73 FR 16570, Mar. 28, 2008; 74 FR 2894, Jan. 16, Pipeline Mapping System (NPMS) in 2009] accordance with the NPMS ‘‘Standards for Pipeline and Liquefied Natural Gas § 192.731 Compressor stations: Inspec- Operator Submissions.’’ To obtain a tion and testing of relief devices. copy of the NPMS Standards, please (a) Except for rupture discs, each refer to the NPMS homepage at http:// pressure relieving device in a com- www.npms.phmsa.dot.gov or contact the pressor station must be inspected and NPMS National Repository at 703–317– tested in accordance with §§ 192.739 and 3073. A digital data format is preferred, 192.743, and must be operated periodi- but hard copy submissions are accept- cally to determine that it opens at the able if they comply with the NPMS correct set pressure. Standards. In addition to the NPMS-re- (b) Any defective or inadequate quired attributes, operators must sub- equipment found must be promptly re- mit the date of abandonment, diame- paired or replaced. ter, method of abandonment, and cer- (c) Each remote control shutdown de- tification that, to the best of the oper- vice must be inspected and tested at in- ator’s knowledge, all of the reasonably tervals not exceeding 15 months, but at available information requested was least once each calendar year, to determine that it functions properly. provided and, to the best of the operator’s knowledge, the abandonment was [35 FR 13257, Aug. 19, 1970, as amended by completed in accordance with applica- Amdt. 192–43, 47 FR 46851, Oct. 21, 1982] ble laws. Refer to the NPMS Standards § 192.735 Compressor stations: Storage for details in preparing your data for of combustible materials. submission. The NPMS Standards also include details of how to submit data. (a) Flammable or combustible materials in quantities beyond those re- Alternatively, operators may submit quired for everyday use, or other than reports by mail, fax or e-mail to the Of- those normally used in compressor fice of Pipeline Safety, Pipeline and buildings, must be stored a safe dis- Hazardous Materials Safety Adminis- tance from the compressor building. tration, U.S. Department of Transpor- (b) Aboveground oil or gasoline stor- tation, Information Resources Man- age tanks must be protected in accord- ager, PHP–10, 1200 New Jersey Avenue, ance with National Fire Protection As- SE., Washington, DC 20590-0001; fax sociation Standard No. 30. (202) 366–4566; e-mail InformationResourcesManager@phmsa. § 192.736 Compressor stations: Gas detection. dot.gov. The information in the report must contain all reasonably available (a) Not later than September 16, 1996, information related to the facility, in- each compressor building in a com- cluding information in the possession pressor station must have a fixed gas of a third party. The report must con- detection and alarm system, unless the tain the location, size, date, method of building is— abandonment, and a certification that (1) Constructed so that at least 50 percent of its upright side area is per- the facility has been abandoned in ac- manently open; or cordance with all applicable laws. (2) Located in an unattended field compressor station of 1,000 horsepower (746 kW) or less. (b) Except when shutdown of the system is necessary for maintenance under paragraph (c) of this section,

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each gas detection and alarm system § 192.741 Pressure limiting and regu- required by this section must— lating stations: Telemetering or re- (1) Continuously monitor the com- cording gauges. pressor building for a concentration of (a) Each distribution system supplied gas in air of not more than 25 percent by more than one district pressure reg- of the lower explosive limit; and (2) If that concentration of gas is de- ulating station must be equipped with tected, warn persons about to enter the telemetering or recording pressure building and persons inside the build- gauges to indicate the gas pressure in ing of the danger. the district. (c) Each gas detection and alarm sys- (b) On distribution systems supplied tem required by this section must be by a single district pressure regulating maintained to function properly. The station, the operator shall determine maintenance must include performance the necessity of installing telemetering tests. or recording gauges in the district, [58 FR 48464, Sept. 16, 1993, as amended by taking into consideration the number Amdt. 192–85, 63 FR 37504, July 13, 1998] of customers supplied, the operating pressures, the capacity of the installa- § 192.739 Pressure limiting and regu- tion, and other operating conditions. lating stations: Inspection and test- (c) If there are indications of abnor- ing. mally high or low pressure, the regu- (a) Each pressure limiting station, lator and the auxiliary equipment relief device (except rupture discs), and must be inspected and the necessary pressure regulating station and its measures employed to correct any un- equipment must be subjected at inter- satisfactory operating conditions. vals not exceeding 15 months, but at least once each calendar year, to in- § 192.743 Pressure limiting and regu- spections and tests to determine that lating stations: Capacity of relief it is— devices. (1) In good mechanical condition; (2) Adequate from the standpoint of (a) Pressure relief devices at pressure capacity and reliability of operation limiting stations and pressure regu- for the service in which it is employed; lating stations must have sufficient ca- (3) Except as provided in paragraph pacity to protect the facilities to which (b) of this section, set to control or re- they are connected. Except as provided lieve at the correct pressure consistent in § 192.739(b), the capacity must be with the pressure limits of § 192.201(a); consistent with the pressure limits of and § 192.201(a). This capacity must be de- (4) Properly installed and protected termined at intervals not exceeding 15 from dirt, liquids, or other conditions months, but at least once each cal- that might prevent proper operation. endar year, by testing the devices in (b) For steel pipelines whose MAOP is place or by review and calculations. determined under § 192.619(c), if the (b) If review and calculations are MAOP is 60 psi (414 kPa) gage or more, used to determine if a device has suffi- the control or relief pressure limit is as cient capacity, the calculated capacity follows: must be compared with the rated or experimentally determined relieving ca- If the MAOP produces a hoop Then the pressure limit is: stress that is: pacity of the device for the conditions Greater than 72 percent of MAOP plus 4 percent. under which it operates. After the ini- SMYS. tial calculations, subsequent calcula- Unknown as a percentage of A pressure that will prevent SMYS. unsafe operation of the tions need not be made if the annual pipeline considering its op- review documents that parameters erating and maintenance have not changed to cause the rated or history and MAOP. experimentally determined relieving capacity to be insufficient. [35 FR 13257, Aug. 19, 1970, as amended by (c) If a relief device is of insufficient Amdt. 192–43, 47 FR 46851, Oct. 21, 1982; Amdt. 192–93, 68 FR 53901, Sept. 15, 2003; Amdt. 192– capacity, a new or additional device 96, 69 FR 27863, May 17, 2004]

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must be installed to provide the capac- (d) Each vault cover must be in- ity required by paragraph (a) of this spected to assure that it does not section. present a hazard to public safety. [Amdt. 192–93, 68 FR 53901, Sept. 15, 2003, as [35 FR 13257, Aug. 19, 1970, as amended by amended by Amdt. 192–96, 69 FR 27863, May Amdt. 192–43, 47 FR 46851, Oct. 21, 1982; Amdt. 17, 2004] 192–85, 63 FR 37504, July 13, 1998]

§ 192.745 Valve maintenance: Trans- § 192.751 Prevention of accidental igni- mission lines. tion. (a) Each transmission line valve that Each operator shall take steps to might be required during any emer- minimize the danger of accidental igni- gency must be inspected and partially tion of gas in any structure or area operated at intervals not exceeding 15 where the presence of gas constitutes a months, but at least once each cal- hazard of fire or explosion, including endar year. the following: (b) Each operator must take prompt (a) When a hazardous amount of gas remedial action to correct any valve is being vented into open air, each po- found inoperable, unless the operator tential source of ignition must be re- designates an alternative valve. moved from the area and a fire extin- [Amdt. 192–43, 47 FR 46851, Oct. 21, 1982, as guisher must be provided. amended by Amdt. 192–93, 68 FR 53901, Sept. (b) Gas or electric welding or cutting 15, 2003] may not be performed on pipe or on pipe components that contain a com- § 192.747 Valve maintenance: Distribu- bustible mixture of gas and air in the tion systems. area of work. (a) Each valve, the use of which may (c) Post warning signs, where appro- be necessary for the safe operation of a priate. distribution system, must be checked and serviced at intervals not exceeding § 192.753 Caulked bell and spigot 15 months, but at least once each cal- joints. endar year. (a) Each cast iron caulked bell and (b) Each operator must take prompt spigot joint that is subject to pressures remedial action to correct any valve of more than 25 psi (172kPa) gage must found inoperable, unless the operator be sealed with: designates an alternative valve. (1) A mechanical leak clamp; or [Amdt. 192–43, 47 FR 46851, Oct. 21, 1982, as (2) A material or device which: amended by Amdt. 192–93, 68 FR 53901, Sept. (i) Does not reduce the flexibility of 15, 2003] the joint; (ii) Permanently bonds, either chemi- § 192.749 Vault maintenance. cally or mechanically, or both, with (a) Each vault housing pressure regu- the bell and spigot metal surfaces or lating and pressure limiting equip- adjacent pipe metal surfaces; and ment, and having a volumetric internal (iii) Seals and bonds in a manner that content of 200 cubic feet (5.66 cubic me- meets the strength, environmental, ters) or more, must be inspected at in- and chemical compatibility require- tervals not exceeding 15 months, but at ments of §§ 192.53 (a) and (b) and 192.143. least once each calendar year, to deter- (b) Each cast iron caulked bell and mine that it is in good physical condi- spigot joint that is subject to pressures tion and adequately ventilated. of 25 psi (172kPa) gage or less and is ex- (b) If gas is found in the vault, the posed for any reason must be sealed by equipment in the vault must be in- a means other than caulking. spected for leaks, and any leaks found must be repaired. [35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192–25, 41 FR 23680, June 11, 1976; (c) The ventilating equipment must Amdt. 192–85, 63 FR 37504, July 13, 1998; also be inspected to determine that it Amdt. 192–93, 68 FR 53901, Sept. 15, 2003] is functioning properly.

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§ 192.755 Protecting cast-iron pipe- (b) Result in a hazard(s) to persons, lines. property, or the environment. When an operator has knowledge Evaluation means a process, estab- that the support for a segment of a lished and documented by the operator, buried cast-iron pipeline is disturbed: to determine an individual’s ability to (a) That segment of the pipeline must perform a covered task by any of the be protected, as necessary, against following: (a) Written examination; damage during the disturbance by: (b) Oral examination; (1) Vibrations from heavy construc- (c) Work performance history review; tion equipment, trains, trucks, buses, (d) Observation during: or blasting; (1) Performance on the job, (2) Impact forces by vehicles; (2) On the job training, or (3) Earth movement; (3) Simulations; (4) Apparent future excavations near (e) Other forms of assessment. the pipeline; or Qualified means that an individual (5) Other foreseeable outside forces has been evaluated and can: which may subject that segment of the (a) Perform assigned covered tasks; pipeline to bending stress. and (b) As soon as feasible, appropriate (b) Recognize and react to abnormal steps must be taken to provide perma- operating conditions. nent protection for the disturbed segment from damage that might result [Amdt. 192–86, 64 FR 46865, Aug. 27, 1999, as amended by Amdt. 192–90, 66 FR 43523, Aug. from external loads, including compli- 20, 2001] ance with applicable requirements of §§ 192.317(a), 192.319, and 192.361(b)–(d). § 192.805 Qualification program. [Amdt. 192–23, 41 FR 13589, Mar. 31, 1976] Each operator shall have and follow a written qualification program. The Subpart N—Qualification of program shall include provisions to: Pipeline Personnel (a) Identify covered tasks; (b) Ensure through evaluation that individuals performing covered tasks SOURCE: Amdt. 192–86, 64 FR 46865, Aug. 27, are qualified; 1999, unless otherwise noted. (c) Allow individuals that are not § 192.801 Scope. qualified pursuant to this subpart to perform a covered task if directed and (a) This subpart prescribes the min- observed by an individual that is quali- imum requirements for operator qualified; fication of individuals performing cov- (d) Evaluate an individual if the oper- ered tasks on a pipeline facility. ator has reason to believe that the in- (b) For the purpose of this subpart, a dividual’s performance of a covered covered task is an activity, identified task contributed to an incident as de- by the operator, that: fined in Part 191; (1) Is performed on a pipeline facility; (e) Evaluate an individual if the oper- (2) Is an operations or maintenance ator has reason to believe that the in- task; dividual is no longer qualified to per- (3) Is performed as a requirement of form a covered task; this part; and (f) Communicate changes that affect (4) Affects the operation or integrity covered tasks to individuals per- of the pipeline. forming those covered tasks; (g) Identify those covered tasks and § 192.803 Definitions. the intervals at which evaluation of Abnormal operating condition means a the individual’s qualifications is need- condition identified by the operator ed; that may indicate a malfunction of a (h) After December 16, 2004, provide component or deviation from normal training, as appropriate, to ensure that operations that may: individuals performing covered tasks (a) Indicate a condition exceeding de- have the necessary knowledge and sign limits; or skills to perform the tasks in a manner

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that ensures the safe operation of pipe- be used as the sole method of evalua- line facilities; and tion. (i) After December 16, 2004, notify the [Amdt. 192–86, 64 FR 46865, Aug. 27, 1999, as Administrator or a state agency par- amended by Amdt. 192–90, 66 FR 43524, Aug. ticipating under 49 U.S.C. Chapter 601 20, 2001; Amdt. 192–100, 70 FR 10335, Mar. 3, if the operator significantly modifies 2005] the program after the Administrator or state agency has verified that it com- Subpart O—Gas Transmission plies with this section. Pipeline Integrity Management [Amdt. 192–86, 64 FR 46865, Aug. 27, 1999, as amended by Amdt. 192–100, 70 FR 10335, Mar. SOURCE: 68 FR 69817, Dec. 15, 2003, unless 3, 2005] otherwise noted.

§ 192.807 Recordkeeping. § 192.901 What do the regulations in Each operator shall maintain records this subpart cover? that demonstrate compliance with this This subpart prescribes minimum re- subpart. quirements for an integrity manage- (a) Qualification records shall in- ment program on any gas transmission clude: pipeline covered under this part. For (1) Identification of qualified indi- gas transmission pipelines constructed vidual(s); of plastic, only the requirements in (2) Identification of the covered tasks §§ 192.917, 192.921, 192.935 and 192.937 the individual is qualified to perform; apply. (3) Date(s) of current qualification; and § 192.903 What definitions apply to this (4) Qualification method(s). subpart? (b) Records supporting an individ- The following definitions apply to ual’s current qualification shall be this subpart: maintained while the individual is per- Assessment is the use of testing tech- forming the covered task. Records of niques as allowed in this subpart to as- prior qualification and records of indi- certain the condition of a covered pipe- viduals no longer performing covered line segment. tasks shall be retained for a period of Confirmatory direct assessment is an in- five years. tegrity assessment method using more focused application of the principles § 192.809 General. and techniques of direct assessment to (a) Operators must have a written identify internal and external corro- qualification program by April 27, 2001. sion in a covered transmission pipeline The program must be available for re- segment. view by the Administrator or by a Covered segment or covered pipeline seg- state agency participating under 49 ment means a segment of gas trans- U.S.C. Chapter 601 if the program is mission pipeline located in a high con- under the authority of that state agen- sequence area. The terms gas and cy. transmission line are defined in § 192.3. (b) Operators must complete the Direct assessment is an integrity as- qualification of individuals performing sessment method that utilizes a proc- covered tasks by October 28, 2002. ess to evaluate certain threats (i.e., ex- (c) Work performance history review ternal corrosion, internal corrosion may be used as a sole evaluation meth- and stress corrosion cracking) to a cov- od for individuals who were performing ered pipeline segment’s integrity. The a covered task prior to October 26, 1999. process includes the gathering and in- (d) After October 28, 2002, work per- tegration of risk factor data, indirect formance history may not be used as a examination or analysis to identify sole evaluation method. areas of suspected corrosion, direct ex- (e) After December 16, 2004, observa- amination of the pipeline in these tion of on-the-job performance may not areas, and post assessment evaluation.

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High consequence area means an area feet) [or 200 meters]/potential impact established by one of the methods de- radius in feet [or meters] 2). scribed in paragraphs (1) or (2) as fol- Identified site means each of the follows: lowing areas: (1) An area defined as— (a) An outside area or open structure (i) A Class 3 location under § 192.5; or that is occupied by twenty (20) or more (ii) A Class 4 location under § 192.5; or persons on at least 50 days in any (iii) Any area in a Class 1 or Class 2 twelve (12)-month period. (The days location where the potential impact ra- need not be consecutive.) Examples in- dius is greater than 660 feet (200 me- clude but are not limited to, beaches, ters), and the area within a potential playgrounds, recreational facilities, impact circle contains 20 or more camping grounds, outdoor theaters, buildings intended for human occu- stadiums, recreational areas near a pancy; or body of water, or areas outside a rural (iv) Any area in a Class 1 or Class 2 building such as a religious facility; or location where the potential impact (b) A building that is occupied by circle contains an identified site. twenty (20) or more persons on at least (2) The area within a potential im- five (5) days a week for ten (10) weeks pact circle containing— in any twelve (12)-month period. (The (i) 20 or more buildings intended for days and weeks need not be consecu- human occupancy, unless the exception tive.) Examples include, but are not in paragraph (4) applies; or limited to, religious facilities, office (ii) An identified site. buildings, community centers, general (3) Where a potential impact circle is stores, 4-H facilities, or roller skating calculated under either method (1) or rinks; or (2) to establish a high consequence (c) A facility occupied by persons area, the length of the high con- who are confined, are of impaired mo- sequence area extends axially along bility, or would be difficult to evac- the length of the pipeline from the out- uate. Examples include but are not ermost edge of the first potential im- limited to hospitals, prisons, schools, pact circle that contains either an day-care facilities, retirement facili- identified site or 20 or more buildings ties or assisted-living facilities. intended for human occupancy to the Potential impact circle is a circle of ra- outermost edge of the last contiguous dius equal to the potential impact ra- potential impact circle that contains dius (PIR). Potential impact radius (PIR) means either an identified site or 20 or more the radius of a circle within which the buildings intended for human occu- potential failure of a pipeline could pancy. (See figure E.I.A. in appendix have significant impact on people or E.) property. PIR is determined by the for- (4) If in identifying a high con- mula r = 0.69* (square root of (p*d 2)), sequence area under paragraph (1)(iii) where ‘r’ is the radius of a circular area of this definition or paragraph (2)(i) of in feet surrounding the point of failure, this definition, the radius of the poten- ‘p’ is the maximum allowable oper- tial impact circle is greater than 660 ating pressure (MAOP) in the pipeline feet (200 meters), the operator may segment in pounds per square inch and identify a high consequence area based ‘d’ is the nominal diameter of the pipe- on a prorated number of buildings in- line in inches. tended for human occupancy with a distance of 660 feet (200 meters) from NOTE: 0.69 is the factor for natural gas. the centerline of the pipeline until De- This number will vary for other gases december 17, 2006. If an operator chooses pending upon their heat of combustion. An operator transporting gas other than natural this approach, the operator must pro- gas must use section 3.2 of ASME/ANSI rate the number of buildings intended B31.8S–2001 (Supplement to ASME B31.8; infor human occupancy based on the corporated by reference, see § 192.7) to cal- ratio of an area with a radius of 660 culate the impact radius formula. feet (200 meters) to the area of the po- Remediation is a repair or mitigation tential impact circle (i.e., the prorated activity an operator takes on a covered number of buildings intended for segment to limit or reduce the prob- human occupancy is equal to 20 × (660 ability of an undesired event occurring

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or the expected consequences from the (c) Newly identified areas. When an op- event. erator has information that the area [68 FR 69817, Dec. 15, 2003, as amended by around a pipeline segment not pre- Amdt. 192–95, 69 FR 18231, Apr. 6, 2004; Amdt. viously identified as a high con- 192–95, 69 FR 29904, May 26, 2004; Amdt. 192– sequence area could satisfy any of the 103, 72 FR 4657, Feb. 1, 2007] definitions in § 192.903, the operator must complete the evaluation using § 192.905 How does an operator iden- method (1) or (2). If the segment is de- tify a high consequence area? termined to meet the definition as a (a) General. To determine which seg- high consequence area, it must be in- ments of an operator’s transmission corporated into the operator’s baseline pipeline system are covered by this assessment plan as a high consequence subpart, an operator must identify the area within one year from the date the high consequence areas. An operator area is identified. must use method (1) or (2) from the definition in § 192.903 to identify a high § 192.907 What must an operator do to consequence area. An operator may implement this subpart? apply one method to its entire pipeline (a) General. No later than December system, or an operator may apply one 17, 2004, an operator of a covered pipe- method to individual portions of the line segment must develop and follow a pipeline system. An operator must de- written integrity management pro- scribe in its integrity management program that contains all the elements de- gram which method it is applying to scribed in § 192.911 and that addresses each portion of the operator’s pipeline the risks on each covered transmission system. The description must include pipeline segment. The initial integrity the potential impact radius when uti- management program must consist, at lized to establish a high consequence a minimum, of a framework that de- area. (See appendix E.I. for guidance on scribes the process for implementing identifying high consequence areas.) each program element, how relevant (b)(1) Identified sites. An operator decisions will be made and by whom, a must identify an identified site, for time line for completing the work to purposes of this subpart, from informa- implement the program element, and tion the operator has obtained from how information gained from experi- routine operation and maintenance ac- ence will be continuously incorporated tivities and from public officials with into the program. The framework will safety or emergency response or plan- evolve into a more detailed and com- ning responsibilities who indicate to prehensive program. An operator must the operator that they know of loca- make continual improvements to the tions that meet the identified site cri- program. teria. These public officials could include officials on a local emergency (b) Implementation Standards. In car- planning commission or relevant Na- rying out this subpart, an operator tive American tribal officials. must follow the requirements of this (2) If a public official with safety or subpart and of ASME/ANSI B31.8S (in- emergency response or planning re- corporated by reference, see § 192.7) and sponsibilities informs an operator that its appendices, where specified. An op- it does not have the information to erator may follow an equivalent stand- identify an identified site, the operator ard or practice only when the operator must use one of the following sources, demonstrates the alternative standard as appropriate, to identify these sites. or practice provides an equivalent level (i) Visible marking (e.g., a sign); or of safety to the public and property. In (ii) The site is licensed or registered the event of a conflict between this by a Federal, State, or local govern- subpart and ASME/ANSI B31.8S, the re- ment agency; or quirements in this subpart control. (iii) The site is on a list (including a list on an internet web site) or map § 192.909 How can an operator change maintained by or available from a Fed- its integrity management program? eral, State, or local government agency (a) General. An operator must docu- and available to the general public. ment any change to its program and

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the reasons for the change before im- (e) Provisions meeting the require- plementing the change. ments of § 192.933 for remediating con- (b) Notification. An operator must no- ditions found during an integrity as- tify OPS, in accordance with § 192.949, sessment. of any change to the program that may (f) A process for continual evaluation substantially affect the program’s im- and assessment meeting the require- plementation or may significantly ments of § 192.937. modify the program or schedule for (g) If applicable, a plan for confirm- carrying out the program elements. An atory direct assessment meeting the operator must also notify a State or requirements of § 192.931. local pipeline safety authority when either a covered segment is located in a (h) Provisions meeting the require- State where OPS has an interstate ments of § 192.935 for adding preventive agent agreement, or an intrastate cov- and mitigative measures to protect the ered segment is regulated by that high consequence area. State. An operator must provide the (i) A performance plan as outlined in notification within 30 days after adopt- ASME/ANSI B31.8S, section 9 that in- ing this type of change into its pro- cludes performance measures meeting gram. the requirements of § 192.945. [68 FR 69817, Dec. 15, 2003, as amended by (j) Record keeping provisions meet- Amdt. 192–95, 69 FR 18231, Apr. 6, 2004] ing the requirements of § 192.947. (k) A management of change process § 192.911 What are the elements of an as outlined in ASME/ANSI B31.8S, sec- integrity management program? tion 11. An operator’s initial integrity man- (l) A quality assurance process as agement program begins with a frame- outlined in ASME/ANSI B31.8S, section work (see § 192.907) and evolves into a 12. more detailed and comprehensive in- (m) A communication plan that integrity management program, as infor- cludes the elements of ASME/ANSI mation is gained and incorporated into B31.8S, section 10, and that includes the program. An operator must make procedures for addressing safety con- continual improvements to its pro- cerns raised by— gram. The initial program framework (1) OPS; and and subsequent program must, at min- (2) A State or local pipeline safety imum, contain the following elements. (When indicated, refer to ASME/ANSI authority when a covered segment is B31.8S (incorporated by reference, see located in a State where OPS has an § 192.7) for more detailed information interstate agent agreement. on the listed element.) (n) Procedures for providing (when (a) An identification of all high con- requested), by electronic or other sequence areas, in accordance with means, a copy of the operator’s risk § 192.905. analysis or integrity management pro- (b) A baseline assessment plan meet- gram to— ing the requirements of § 192.919 and (1) OPS; and § 192.921. (2) A State or local pipeline safety (c) An identification of threats to authority when a covered segment is each covered pipeline segment, which located in a State where OPS has an must include data integration and a interstate agent agreement. risk assessment. An operator must use (o) Procedures for ensuring that each the threat identification and risk as- integrity assessment is being con- sessment to prioritize covered seg- ducted in a manner that minimizes en- ments for assessment (§ 192.917) and to vironmental and safety risks. evaluate the merits of additional pre- (p) A process for identification and ventive and mitigative measures assessment of newly-identified high (§ 192.935) for each covered segment. consequence areas. (See § 192.905 and (d) A direct assessment plan, if applicable, meeting the requirements of § 192.921.) § 192.923, and depending on the threat [68 FR 69817, Dec. 15, 2003, as amended by assessed, of §§ 192.925, 192.927, or 192.929. Amdt. 192–95, 69 FR 18231, Apr. 6, 2004]

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§ 192.913 When may an operator devi- (viii) An analysis that supports the ate its program from certain re- desired integrity reassessment interval quirements of this subpart? and the remediation methods to be (a) General. ASME/ANSI B31.8S (in- used for all covered segments. corporated by reference, see § 192.7) pro- (2) In addition to the requirements vides the essential features of a per- for the performance-based plan, an op- formance-based or a prescriptive integ- erator must— rity management program. An oper- (i) Have completed at least two in- ator that uses a performance-based ap- tegrity assessments on each covered proach that satisfies the requirements pipeline segment the operator is infor exceptional performance in para- cluding under the performance-based graph (b) of this section may deviate approach, and be able to demonstrate from certain requirements in this sub- that each assessment effectively ad- part, as provided in paragraph (c) of dressed the identified threats on the this section. covered segment. (b) Exceptional performance. An oper- (ii) Remediate all anomalies identi- ator must be able to demonstrate the fied in the more recent assessment ac- exceptional performance of its integ- cording to the requirements in § 192.933, rity management program through the and incorporate the results and lessons following actions. learned from the more recent assess- (1) To deviate from any of the re- ment into the operator’s data integra- quirements set forth in paragraph (c) of tion and risk assessment. this section, an operator must have a (c) Deviation. Once an operator has performance-based integrity manage- demonstrated that it has satisfied the ment program that meets or exceed the requirements of paragraph (b) of this performance-based requirements of section, the operator may deviate from ASME/ANSI B31.8S and includes, at a the prescriptive requirements of minimum, the following elements— ASME/ANSI B31.8S and of this subpart (i) A comprehensive process for risk only in the following instances. analysis; (1) The time frame for reassessment (ii) All risk factor data used to sup- as provided in § 192.939 except that reas- port the program; sessment by some method allowed (iii) A comprehensive data integra- under this subpart (e.g., confirmatory tion process; direct assessment) must be carried out (iv) A procedure for applying lessons at intervals no longer than seven learned from assessment of covered years; pipeline segments to pipeline segments (2) The time frame for remediation as not covered by this subpart; provided in § 192.933 if the operator (v) A procedure for evaluating every demonstrates the time frame will not incident, including its cause, within jeopardize the safety of the covered the operator’s sector of the pipeline in- segment. dustry for implications both to the op- [68 FR 69817, Dec. 15, 2003, as amended by erator’s pipeline system and to the op- Amdt. 192–95, 69 FR 18231, Apr. 6, 2004] erator’s integrity management program; § 192.915 What knowledge and training (vi) A performance matrix that dem- must personnel have to carry out onstrates the program has been effec- an integrity management program? tive in ensuring the integrity of the (a) Supervisory personnel. The integ- covered segments by controlling the rity management program must pro- identified threats to the covered seg- vide that each supervisor whose re- ments; sponsibilities relate to the integrity (vii) Semi-annual performance meas- management program possesses and ures beyond those required in § 192.945 maintains a thorough knowledge of the that are part of the operator’s perform- integrity management program and of ance plan. (See § 192.911(i).) An operator the elements for which the supervisor must submit these measures, by elec- is responsible. The program must pro- tronic or other means, on a semi-an- vide that any person who qualifies as a nual frequency to OPS in accordance supervisor for the integrity manage- with § 192.951; and ment program has appropriate training

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or experience in the area for which the in ASME/ANSI B31.8S, section 4. At a person is responsible. minimum, an operator must gather and (b) Persons who carry out assessments evaluate the set of data specified in Ap- and evaluate assessment results. The in- pendix A to ASME/ANSI B31.8S, and tegrity management program must consider both on the covered segment provide criteria for the qualification of and similar non-covered segments, past any person— incident history, corrosion control (1) Who conducts an integrity assess- records, continuing surveillance ment allowed under this subpart; or records, patrolling records, mainte- (2) Who reviews and analyzes the re- nance history, internal inspection sults from an integrity assessment and records and all other conditions spe- evaluation; or cific to each pipeline. (3) Who makes decisions on actions (c) Risk assessment. An operator must to be taken based on these assess- conduct a risk assessment that follows ments. ASME/ANSI B31.8S, section 5, and con- (c) Persons responsible for preventive siders the identified threats for each and mitigative measures. The integrity covered segment. An operator must use management program must provide criteria for the qualification of any the risk assessment to prioritize the person— covered segments for the baseline and (1) Who implements preventive and continual reassessments (§§ 192.919, mitigative measures to carry out this 192.921, 192.937), and to determine what subpart, including the marking and lo- additional preventive and mitigative cating of buried structures; or measures are needed (§ 192.935) for the (2) Who directly supervises exca- covered segment. vation work carried out in conjunction (d) Plastic transmission pipeline. An op- with an integrity assessment. erator of a plastic transmission pipeline must assess the threats to each § 192.917 How does an operator iden- covered segment using the information tify potential threats to pipeline in- in sections 4 and 5 of ASME B31.8S, and tegrity and use the threat identi- consider any threats unique to the in- fication in its integrity program? tegrity of plastic pipe. (a) Threat identification. An operator (e) Actions to address particular must identify and evaluate all poten- threats. If an operator identifies any of tial threats to each covered pipeline the following threats, the operator segment. Potential threats that an op- must take the following actions to ad- erator must consider include, but are dress the threat. not limited to, the threats listed in (1) Third party damage. An operator ASME/ANSI B31.8S (incorporated by must utilize the data integration re- reference, see § 192.7), section 2, which quired in paragraph (b) of this section are grouped under the following four categories: and ASME/ANSI B31.8S, Appendix A7 (1) Time dependent threats such as to determine the susceptibility of each internal corrosion, external corrosion, covered segment to the threat of third and stress corrosion cracking; party damage. If an operator identifies (2) Static or resident threats, such as the threat of third party damage, the fabrication or construction defects; operator must implement comprehen- (3) Time independent threats such as sive additional preventive measures in third party damage and outside force accordance with § 192.935 and monitor damage; and the effectiveness of the preventive (4) Human error. measures. If, in conducting a baseline (b) Data gathering and integration. To assessment under § 192.921, or a reas- identify and evaluate the potential sessment under § 192.937, an operator threats to a covered pipeline segment, uses an internal inspection tool or ex- an operator must gather and integrate ternal corrosion direct assessment, the existing data and information on the operator must integrate data from entire pipeline that could be relevant these assessments with data related to to the covered segment. In performing any encroachment or foreign line this data gathering and integration, an crossing on the covered segment, to de- operator must follow the requirements fine where potential indications of

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third party damage may exist in the any covered or noncovered segment in covered segment. the pipeline system with such pipe has An operator must also have proce- experienced seam failure, or operating dures in its integrity management pro- pressure on the covered segment has gram addressing actions it will take to increased over the maximum operating respond to findings from this data inte- pressure experienced during the pre- gration. ceding five years, an operator must se- (2) Cyclic fatigue. An operator must lect an assessment technology or tech- evaluate whether cyclic fatigue or nologies with a proven application ca- other loading condition (including pable of assessing seam integrity and ground movement, suspension bridge seam corrosion anomalies. The oper- condition) could lead to a failure of a ator must prioritize the covered seg- deformation, including a dent or gouge, ment as a high risk segment for the or other defect in the covered segment. An evaluation must assume the pres- baseline assessment or a subsequent re- ence of threats in the covered segment assessment. that could be exacerbated by cyclic fa- (5) Corrosion. If an operator identifies tigue. An operator must use the results corrosion on a covered pipeline seg- from the evaluation together with the ment that could adversely affect the criteria used to evaluate the signifi- integrity of the line (conditions speci- cance of this threat to the covered seg- fied in § 192.933), the operator must ment to prioritize the integrity base- evaluate and remediate, as necessary, line assessment or reassessment. all pipeline segments (both covered and (3) Manufacturing and construction de- non-covered) with similar material fects. If an operator identifies the coating and environmental character- threat of manufacturing and construc- istics. An operator must establish a tion defects (including seam defects) in schedule for evaluating and remedi- the covered segment, an operator must ating, as necessary, the similar seg- analyze the covered segment to deter- ments that is consistent with the oper- mine the risk of failure from these de- ator’s established operating and main- fects. The analysis must consider the tenance procedures under part 192 for results of prior assessments on the cov- testing and repair. ered segment. An operator may consider manufacturing and construction [68 FR 69817, Dec. 15, 2003, as amended by related defects to be stable defects if Amdt. 192–95, 69 FR 18231, Apr. 6, 2004] the operating pressure on the covered segment has not increased over the § 192.919 What must be in the baseline maximum operating pressure experi- assessment plan? enced during the five years preceding An operator must include each of the identification of the high consequence following elements in its written base- area. If any of the following changes line assessment plan: occur in the covered segment, an oper- (a) Identification of the potential ator must prioritize the covered seg- threats to each covered pipeline segment as a high risk segment for the ment and the information supporting baseline assessment or a subsequent re- the threat identification. (See assessment. § 192.917.); (i) Operating pressure increases (b) The methods selected to assess above the maximum operating pressure the integrity of the line pipe, including experienced during the preceding five years; an explanation of why the assessment (ii) MAOP increases; or method was selected to address the (iii) The stresses leading to cyclic fa- identified threats to each covered seg- tigue increase. ment. The integrity assessment meth- (4) ERW pipe. If a covered pipeline od an operator uses must be based on segment contains low frequency elec- the threats identified to the covered tric resistance welded pipe (ERW), lap segment. (See § 192.917.) More than one welded pipe or other pipe that satisfies method may be required to address all the conditions specified in ASME/ANSI the threats to the covered pipeline seg- B31.8S, Appendices A4.3 and A4.4, and ment;

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(c) A schedule for completing the in- notify a State or local pipeline safety tegrity assessment of all covered seg- authority when either a covered segments, including risk factors consid- ment is located in a State where OPS ered in establishing the assessment has an interstate agent agreement, or schedule; an intrastate covered segment is regu- (d) If applicable, a direct assessment lated by that State. plan that meets the requirements of (b) Prioritizing segments. An operator §§ 192.923, and depending on the threat must prioritize the covered pipeline to be addressed, of § 192.925, § 192.927, or segments for the baseline assessment § 192.929; and according to a risk analysis that con- (e) A procedure to ensure that the siders the potential threats to each baseline assessment is being conducted covered segment. The risk analysis in a manner that minimizes environ- must comply with the requirements in mental and safety risks. § 192.917. (c) Assessment for particular threats. In § 192.921 How is the baseline assessment to be conducted? choosing an assessment method for the baseline assessment of each covered (a) Assessment methods. An operator segment, an operator must take the ac- must assess the integrity of the line tions required in § 192.917(e) to address pipe in each covered segment by apply- particular threats that it has identi- ing one or more of the following meth- fied. ods depending on the threats to which (d) Time period. An operator must the covered segment is susceptible. An prioritize all the covered segments for operator must select the method or assessment in accordance with § 192.917 methods best suited to address the (c) and paragraph (b) of this section. threats identified to the covered seg- An operator must assess at least 50% of ment (See § 192.917). the covered segments beginning with (1) Internal inspection tool or tools the highest risk segments, by Decem- capable of detecting corrosion, and any ber 17, 2007. An operator must complete other threats to which the covered segment is susceptible. An operator must the baseline assessment of all covered follow ASME/ANSI B31.8S (incor- segments by December 17, 2012. porated by reference, see § 192.7), sec- (e) Prior assessment. An operator may tion 6.2 in selecting the appropriate in- use a prior integrity assessment con- ternal inspection tools for the covered ducted before December 17, 2002 as a segment. baseline assessment for the covered (2) Pressure test conducted in accord- segment, if the integrity assessment ance with subpart J of this part. An op- meets the baseline requirements in this erator must use the test pressures subpart and subsequent remedial ac- specified in Table 3 of section 5 of tions to address the conditions listed in ASME/ANSI B31.8S, to justify an ex- § 192.933 have been carried out. In addi- tended reassessment interval in accord- tion, if an operator uses this prior as- ance with § 192.939. sessment as its baseline assessment, (3) Direct assessment to address the operator must reassess the line threats of external corrosion, internal pipe in the covered segment according corrosion, and stress corrosion crack- to the requirements of § 192.937 and ing. An operator must conduct the di- § 192.939. rect assessment in accordance with the (f) Newly identified areas. When an op- requirements listed in § 192.923 and erator identifies a new high con- with, as applicable, the requirements sequence area (see § 192.905), an operator specified in §§ 192.925, 192.927 or 192.929; must complete the baseline assessment (4) Other technology that an operator of the line pipe in the newly identified demonstrates can provide an equiva- high consequence area within ten (10) lent understanding of the condition of years from the date the area is identi- the line pipe. An operator choosing this fied. option must notify the Office of Pipe- (g) Newly installed pipe. An operator line Safety (OPS) 180 days before con- must complete the baseline assessment ducting the assessment, in accordance of a newly-installed segment of pipe with § 192.949. An operator must also covered by this subpart within ten (10)

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years from the date the pipe is in- § 192.925 What are the requirements stalled. An operator may conduct a for using External Corrosion Direct pressure test in accordance with para- Assessment (ECDA)? graph (a)(2) of this section, to satisfy (a) Definition. ECDA is a four-step the requirement for a baseline assess- process that combines preassessment, ment. indirect inspection, direct examina- (h) Plastic transmission pipeline. If the tion, and post assessment to evaluate threat analysis required in § 192.917(d) the threat of external corrosion to the on a plastic transmission pipeline indi- integrity of a pipeline. cates that a covered segment is suscep- (b) General requirements. An operator tible to failure from causes other than that uses direct assessment to assess third-party damage, an operator must the threat of external corrosion must conduct a baseline assessment of the follow the requirements in this section, segment in accordance with the rein ASME/ANSI B31.8S (incorporated by quirements of this section and of reference, see § 192.7), section 6.4, and in § 192.917. The operator must justify the NACE SP0502–2008 (incorporated by ref- use of an alternative assessment meth- erence, see § 192.7). An operator must od that will address the identified develop and implement a direct assess- threats to the covered segment. ment plan that has procedures address- [68 FR 69817, Dec. 15, 2003, as amended by ing preassessment, indirect examina- Amdt. 192–95, 69 FR 18232, Apr. 6, 2004] tion, direct examination, and post-assessment. If the ECDA detects pipeline § 192.923 How is direct assessment coating damage, the operator must used and for what threats? also integrate the data from the ECDA (a) General. An operator may use di- with other information from the data rect assessment either as a primary as- integration (§ 192.917(b)) to evaluate the sessment method or as a supplement to covered segment for the threat of third the other assessment methods allowed party damage, and to address the under this subpart. An operator may threat as required by § 192.917(e)(1). only use direct assessment as the pri- (1) Preassessment. In addition to the mary assessment method to address requirements in ASME/ANSI B31.8S the identified threats of external corro- section 6.4 and NACE SP0502–2008, sec- sion (ECDA), internal corrosion tion 3, the plan’s procedures for (ICDA), and stress corrosion cracking preassessment must include— (SCCDA). (i) Provisions for applying more re- (b) Primary method. An operator using strictive criteria when conducting direct assessment as a primary assess- ECDA for the first time on a covered ment method must have a plan that segment; and complies with the requirements in— (ii) The basis on which an operator (1) ASME/ANSI B31.8S (incorporated selects at least two different, but com- by reference, see § 192.7), section 6.4; plementary indirect assessment tools NACE SP0502–2008 (incorporated by ref- to assess each ECDA Region. If an op- erence, see § 192.7); and § 192.925 if ad- erator utilizes an indirect inspection dressing external corrosion (ECDA). method that is not discussed in Appen- (2) ASME/ANSI B31.8S, section 6.4 dix A of NACE SP0502–2008, the oper- and appendix B2, and § 192.927 if ad- ator must demonstrate the applica- dressing internal corrosion (ICDA). bility, validation basis, equipment (3) ASME/ANSI B31.8S, appendix A3, used, application procedure, and utili- and § 192.929 if addressing stress corro- zation of data for the inspection meth- sion cracking (SCCDA). od. (c) Supplemental method. An operator (2) Indirect examination. In addition to using direct assessment as a supple- the requirements in ASME/ANSI B31.8S mental assessment method for any ap- section 6.4 and NACE SP0502–2008, sec- plicable threat must have a plan that tion 4, the plan’s procedures for indi- follows the requirements for confirm- rect examination of the ECDA regions atory direct assessment in § 192.931. must include— [68 FR 69817, Dec. 15, 2003, as amended by (i) Provisions for applying more re- Amdt. 192–114, 75 FR 48604, Aug. 11, 2010] strictive criteria when conducting

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ECDA for the first time on a covered of the effectiveness of the ECDA proc- segment; ess must include— (ii) Criteria for identifying and docu- (i) Measures for evaluating the long- menting those indications that must be term effectiveness of ECDA in address- considered for excavation and direct ing external corrosion in covered seg- examination. Minimum identification ments; and criteria include the known sensitivities (ii) Criteria for evaluating whether of assessment tools, the procedures for conditions discovered by direct exam- using each tool, and the approach to be ination of indications in each ECDA re- used for decreasing the physical spac- gion indicate a need for reassessment ing of indirect assessment tool read- of the covered segment at an interval ings when the presence of a defect is less than that specified in § 192.939. (See suspected; Appendix D of NACE SP0502–2008.) (iii) Criteria for defining the urgency of excavation and direct examination [68 FR 69817, Dec. 15, 2003, as amended by of each indication identified during the Amdt. 192–95, 69 FR 29904, May 26, 2004; Amdt. indirect examination. These criteria 192–114, 75 FR 48604, Aug. 11, 2010] must specify how an operator will de- § 192.927 What are the requirements fine the urgency of excavating the indi- for using Internal Corrosion Direct cation as immediate, scheduled or Assessment (ICDA)? monitored; and (iv) Criteria for scheduling exca- (a) Definition. Internal Corrosion Di- vation of indications for each urgency rect Assessment (ICDA) is a process an level. operator uses to identify areas along (3) Direct examination. In addition to the pipeline where fluid or other elec- the requirements in ASME/ANSI B31.8S trolyte introduced during normal oper- section 6.4 and NACE SP0502–2008, sec- ation or by an upset condition may re- tion 5, the plan’s procedures for direct side, and then focuses direct examina- examination of indications from the in- tion on the locations in covered seg- direct examination must include— ments where internal corrosion is most (i) Provisions for applying more re- likely to exist. The process identifies strictive criteria when conducting the potential for internal corrosion ECDA for the first time on a covered caused by microorganisms, or fluid segment; with CO2, O2, hydrogen sulfide or other (ii) Criteria for deciding what action contaminants present in the gas. should be taken if either: (b) General requirements. An operator (A) Corrosion defects are discovered using direct assessment as an assess- that exceed allowable limits (Section ment method to address internal corro- 5.5.2.2 of NACE SP0502–2008), or sion in a covered pipeline segment (B) Root cause analysis reveals con- must follow the requirements in this ditions for which ECDA is not suitable section and in ASME/ANSI B31.8S (in- (Section 5.6.2 of NACE SP0502–2008); corporated by reference, see § 192.7), sec- (iii) Criteria and notification proce- tion 6.4 and appendix B2. The ICDA dures for any changes in the ECDA process described in this section ap- Plan, including changes that affect the plies only for a segment of pipe trans- severity classification, the priority of porting nominally dry natural gas, and direct examination, and the time frame not for a segment with electrolyte for direct examination of indications; nominally present in the gas stream. If and an operator uses ICDA to assess a cov- (iv) Criteria that describe how and on ered segment operating with electro- what basis an operator will reclassify lyte present in the gas stream, the op- and reprioritize any of the provisions erator must develop a plan that dem- that are specified in section 5.9 of onstrates how it will conduct ICDA in NACE SP0502–2008. the segment to effectively address in- (4) Post assessment and continuing ternal corrosion, and must provide no- evaluation. In addition to the require- tification in accordance with § 192.921 ments in ASME/ANSI B31.8S section 6.4 (a)(4) or § 192.937(c)(4). and NACE SP0502–2008, section 6, the (c) The ICDA plan. An operator must plan’s procedures for post assessment develop and follow an ICDA plan that

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provides for preassessment, identifica- the identification process, an operator tion of ICDA regions and excavation lo- must use the model in GRI 02–0057, cations, detailed examination of pipe ‘‘Internal Corrosion Direct Assessment at excavation locations, and post-as- of Gas Transmission Pipelines—Meth- sessment evaluation and monitoring. odology,’’ (incorporated by reference, (1) Preassessment. In the see § 192.7). An operator may use an- preassessment stage, an operator must other model if the operator dem- gather and integrate data and informa- onstrates it is equivalent to the one tion needed to evaluate the feasibility shown in GRI 02–0057. A model must of ICDA for the covered segment, and consider changes in pipe diameter, lo- to support use of a model to identify cations where gas enters a line (poten- the locations along the pipe segment tial to introduce liquid) and locations where electrolyte may accumulate, to down stream of gas draw-offs (where identify ICDA regions, and to identify gas velocity is reduced) to define the areas within the covered segment critical pipe angle of inclination above where liquids may potentially be en- which water film cannot be transported trained. This data and information in- by the gas. cludes, but is not limited to— (3) Identification of locations for exca- (i) All data elements listed in appen- vation and direct examination. An opera- dix A2 of ASME/ANSI B31.8S; tor’s plan must identify the locations (ii) Information needed to support where internal corrosion is most likely use of a model that an operator must in each ICDA region. In the location use to identify areas along the pipeline identification process, an operator where internal corrosion is most likely must identify a minimum of two loca- to occur. (See paragraph (a) of this sections for excavation within each ICDA tion.) This information, includes, but is Region within a covered segment and not limited to, location of all gas input must perform a direct examination for and withdrawal points on the line; lo- internal corrosion at each location, cation of all low points on covered seg- using ultrasonic thickness measurements such as sags, drips, inclines, ments, radiography, or other generally valves, manifolds, dead-legs, and traps; accepted measurement technique. One the elevation profile of the pipeline in location must be the low point (e.g., sufficient detail that angles of inclina- sags, drips, valves, manifolds, dead- tion can be calculated for all pipe seg- legs, traps) within the covered segment ments; and the diameter of the pipe- nearest to the beginning of the ICDA line, and the range of expected gas ve- Region. The second location must be locities in the pipeline; further downstream, within a covered (iii) Operating experience data that segment, near the end of the ICDA Re- would indicate historic upsets in gas conditions, locations where these up- gion. If corrosion exists at either loca- sets have occurred, and potential dam- tion, the operator must— age resulting from these upset condi- (i) Evaluate the severity of the defect tions; and (remaining strength) and remediate (iv) Information on covered segments the defect in accordance with § 192.933; where cleaning pigs may not have been (ii) As part of the operator’s current used or where cleaning pigs may de- integrity assessment either perform posit electrolytes. additional excavations in each covered (2) ICDA region identification. An oper- segment within the ICDA region, or use ator’s plan must identify where all an alternative assessment method al- ICDA Regions are located in the trans- lowed by this subpart to assess the line mission system, in which covered seg- pipe in each covered segment within ments are located. An ICDA Region ex- the ICDA region for internal corrosion; tends from the location where liquid and may first enter the pipeline and encom- (iii) Evaluate the potential for inter- passes the entire area along the pipe- nal corrosion in all pipeline segments line where internal corrosion may (both covered and non-covered) in the occur and where further evaluation is operator’s pipeline system with similar needed. An ICDA Region may encom- characteristics to the ICDA region con- pass one or more covered segments. In taining the covered segment in which

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the corrosion was found, and as appro- ICDA for the first time on a covered priate, remediate the conditions the segment and that become less strin- operator finds in accordance with gent as the operator gains experience; § 192.933. and (4) Post-assessment evaluation and (iii) Provisions that analysis be car- monitoring. An operator’s plan must ried out on the entire pipeline in which provide for evaluating the effectiveness covered segments are present, except of the ICDA process and continued that application of the remediation cri- monitoring of covered segments where teria of § 192.933 may be limited to cov- internal corrosion has been identified. ered segments. The evaluation and monitoring process includes— [68 FR 69817, Dec. 15, 2003, as amended by (i) Evaluating the effectiveness of Amdt. 192–95, 69 FR 18232, Apr. 6, 2004] ICDA as an assessment method for addressing internal corrosion and deter- § 192.929 What are the requirements mining whether a covered segment for using Direct Assessment for should be reassessed at more frequent Stress Corrosion Cracking intervals than those specified in (SCCDA)? § 192.939. An operator must carry out (a) Definition. Stress Corrosion this evaluation within a year of con- Cracking Direct Assessment (SCCDA) ducting an ICDA; and is a process to assess a covered pipe (ii) Continually monitoring each cov- segment for the presence of SCC pri- ered segment where internal corrosion marily by systematically gathering has been identified using techniques and analyzing excavation data for pipe such as coupons, UT sensors or elec- having similar operational characteris- tronic probes, periodically drawing off tics and residing in a similar physical liquids at low points and chemically environment. analyzing the liquids for the presence (b) General requirements. An operator of corrosion products. An operator using direct assessment as an integrity must base the frequency of the moni- assessment method to address stress toring and liquid analysis on results from all integrity assessments that corrosion cracking in a covered pipe- have been conducted in accordance line segment must have a plan that with the requirements of this subpart, provides, at minimum, for— and risk factors specific to the covered (1) Data gathering and integration. An segment. If an operator finds any evi- operator’s plan must provide for a sys- dence of corrosion products in the cov- tematic process to collect and evaluate ered segment, the operator must take data for all covered segments to iden- prompt action in accordance with one tify whether the conditions for SCC are of the two following required actions present and to prioritize the covered and remediate the conditions the oper- segments for assessment. This process ator finds in accordance with § 192.933. must include gathering and evaluating (A) Conduct excavations of covered data related to SCC at all sites an oper- segments at locations downstream ator excavates during the conduct of from where the electrolyte might have its pipeline operations where the cri- entered the pipe; or teria in ASME/ANSI B31.8S (incor- (B) Assess the covered segment using porated by reference, see § 192.7), appen- another integrity assessment method dix A3.3 indicate the potential for SCC. allowed by this subpart. This data includes at minimum, the (5) Other requirements. The ICDA plan data specified in ASME/ANSI B31.8S, must also include— appendix A3. (i) Criteria an operator will apply in (2) Assessment method. The plan must making key decisions (e.g., ICDA feasibility, definition of ICDA Regions, con- provide that if conditions for SCC are ditions requiring excavation) in imple- identified in a covered segment, an op- menting each stage of the ICDA proc- erator must assess the covered segment ess; using an integrity assessment method (ii) Provisions for applying more re- strictive criteria when conducting

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specified in ASME/ANSI B31.8S, appen- ment using one of the assessment tech- dix A3, and remediate the threat in ac- niques allowed in § 192.937. cordance with ASME/ANSI B31.8S, ap- [68 FR 69817, Dec. 15, 2003, as amended by pendix A3, section A3.4. Amdt. 192–114, 75 FR 48604, Aug. 11, 2010] [68 FR 69817, Dec. 15, 2003, as amended by § 192.933 What actions must be taken Amdt. 192–95, 69 FR 18233, Apr. 6, 2004] to address integrity issues? § 192.931 How may Confirmatory Di- (a) General requirements. An operator rect Assessment (CDA) be used? must take prompt action to address all anomalous conditions the operator dis- An operator using the confirmatory covers through the integrity assess- direct assessment (CDA) method as al- ment. In addressing all conditions, an lowed in § 192.937 must have a plan that operator must evaluate all anomalous meets the requirements of this section conditions and remediate those that and of §§ 192.925 (ECDA) and § 192.927 could reduce a pipeline’s integrity. An (ICDA). operator must be able to demonstrate (a) Threats. An operator may only use that the remediation of the condition CDA on a covered segment to identify will ensure the condition is unlikely to damage resulting from external corro- pose a threat to the integrity of the sion or internal corrosion. pipeline until the next reassessment of (b) External corrosion plan. An opera- the covered segment. tor’s CDA plan for identifying external (1) Temporary pressure reduction. If an corrosion must comply with § 192.925 operator is unable to respond within with the following exceptions. the time limits for certain conditions (1) The procedures for indirect exam- specified in this section, the operator ination may allow use of only one indi- must temporarily reduce the operating rect examination tool suitable for the pressure of the pipeline or take other application. action that ensures the safety of the (2) The procedures for direct exam- covered segment. An operator must de- ination and remediation must provide termine any temporary reduction in that— operating pressure required by this section using ASME/ANSI B31G (incor- (i) All immediate action indications porated by reference, see § 192.7) or AGA must be excavated for each ECDA re- Pipeline Research Committee Project gion; and PR–3–805 (‘‘RSTRENG,’’ incorporated (ii) At least one high risk indication by reference, see § 192.7) or reduce the that meets the criteria of scheduled ac- operating pressure to a level not ex- tion must be excavated in each ECDA ceeding 80 percent of the level at the region. time the condition was discovered. (See (c) Internal corrosion plan. An opera- appendix A to this part for information tor’s CDA plan for identifying internal on availability of incorporation by ref- corrosion must comply with § 192.927 erence information.) An operator must except that the plan’s procedures for notify PHMSA in accordance with identifying locations for excavation § 192.949 if it cannot meet the schedule may require excavation of only one for evaluation and remediation re- high risk location in each ICDA region. quired under paragraph (c) of this sec- (d) Defects requiring near-term remedi- tion and cannot provide safety through ation. If an assessment carried out temporary reduction in operating pres- under paragraph (b) or (c) of this sec- sure or other action. An operator must tion reveals any defect requiring reme- also notify a State pipeline safety au- diation prior to the next scheduled as- thority when either a covered segment sessment, the operator must schedule is located in a State where PHMSA has the next assessment in accordance with an interstate agent agreement, or an NACE SP0502–2008 (incorporated by ref- intrastate covered segment is regu- erence, see § 192.7), section 6.2 and 6.3. If lated by that State. the defect requires immediate remedi- (2) Long-term pressure reduction. When ation, then the operator must reduce a pressure reduction exceeds 365 days, pressure consistent with § 192.933 until the operator must notify PHMSA the operator has completed reassess- under § 192.949 and explain the reasons

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for the remediation delay. This notice following conditions as immediate re- must include a technical justification pair conditions: that the continued pressure reduction (i) A calculation of the remaining will not jeopardize the integrity of the strength of the pipe shows a predicted pipeline. The operator also must notify failure pressure less than or equal to a State pipeline safety authority when 1.1 times the maximum allowable oper- either a covered segment is located in ating pressure at the location of the a State where PHMSA has an inter- anomaly. Suitable remaining strength state agent agreement, or an intrastate calculation methods include, ASME/ covered segment is regulated by that ANSI B31G; RSTRENG; or an alter- State. native equivalent method of remaining (b) Discovery of condition. Discovery strength calculation. These documents of a condition occurs when an operator are incorporated by reference and has adequate information about a con- available at the addresses listed in ap- dition to determine that the condition pendix A to part 192. presents a potential threat to the in- (ii) A dent that has any indication of tegrity of the pipeline. A condition metal loss, cracking or a stress riser. that presents a potential threat in- (iii) An indication or anomaly that in cludes, but is not limited to, those con- the judgment of the person designated ditions that require remediation or by the operator to evaluate the assess- monitoring listed under paragraphs ment results requires immediate ac- (d)(1) through (d)(3) of this section. An tion. (2) One-year conditions. Except for operator must promptly, but no later conditions listed in paragraph (d)(1) than 180 days after conducting an in- and (d)(3) of this section, an operator tegrity assessment, obtain sufficient must remediate any of the following information about a condition to make within one year of discovery of the con- that determination, unless the oper- dition: ator demonstrates that the 180-day pe- (i) A smooth dent located between riod is impracticable. the 8 o’clock and 4 o’clock positions (c) Schedule for evaluation and remedi- (upper 2⁄3 of the pipe) with a depth ation. An operator must complete re- greater than 6% of the pipeline diame- mediation of a condition according to a ter (greater than 0.50 inches in depth schedule prioritizing the conditions for for a pipeline diameter less than Nomi- evaluation and remediation. Unless a nal Pipe Size (NPS) 12). special requirement for remediating (ii) A dent with a depth greater than certain conditions applies, as provided 2% of the pipeline’s diameter (0.250 in paragraph (d) of this section, an op- inches in depth for a pipeline diameter erator must follow the schedule in less than NPS 12) that affects pipe cur- ASME/ANSI B31.8S (incorporated by vature at a girth weld or at a longitu- reference, see § 192.7), section 7, Figure dinal seam weld. 4. If an operator cannot meet the (3) Monitored conditions. An operator schedule for any condition, the oper- does not have to schedule the following ator must explain the reasons why it conditions for remediation, but must cannot meet the schedule and how the record and monitor the conditions dur- changed schedule will not jeopardize ing subsequent risk assessments and public safety. integrity assessments for any change (d) Special requirements for scheduling that may require remediation: remediation—(1) Immediate repair condi- (i) A dent with a depth greater than tions. An operator’s evaluation and re- 6% of the pipeline diameter (greater mediation schedule must follow ASME/ than 0.50 inches in depth for a pipeline ANSI B31.8S, section 7 in providing for diameter less than NPS 12) located be- immediate repair conditions. To main- tween the 4 o’clock position and the 8 tain safety, an operator must tempo- o’clock position (bottom 1⁄3 of the pipe). rarily reduce operating pressure in ac- (ii) A dent located between the 8 cordance with paragraph (a) of this sec- o’clock and 4 o’clock positions (upper tion or shut down the pipeline until the 2⁄3 of the pipe) with a depth greater operator completes the repair of these than 6% of the pipeline diameter conditions. An operator must treat the (greater than 0.50 inches in depth for a

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pipeline diameter less than Nominal an existing damage prevention pro- Pipe Size (NPS) 12), and engineering gram include, at a minimum— analyses of the dent demonstrate crit- (i) Using qualified personnel (see ical strain levels are not exceeded. § 192.915) for work an operator is con- (iii) A dent with a depth greater than ducting that could adversely affect the 2% of the pipeline’s diameter (0.250 integrity of a covered segment, such as inches in depth for a pipeline diameter marking, locating, and direct super- less than NPS 12) that affects pipe cur- vision of known excavation work. vature at a girth weld or a longitudinal (ii) Collecting in a central database seam weld, and engineering analyses of information that is location specific on the dent and girth or seam weld dem- excavation damage that occurs in cov- onstrate critical strain levels are not ered and non covered segments in the exceeded. These analyses must consider transmission system and the root weld properties. cause analysis to support identification [68 FR 69817, Dec. 15, 2003, as amended by of targeted additional preventative and Amdt. 192–95, 69 FR 18233, Apr. 6, 2004; Amdt. mitigative measures in the high con- 192–104, 72 FR 39016, July 17, 2007] sequence areas. This information must include recognized damage that is not § 192.935 What additional preventive required to be reported as an incident and mitigative measures must an under part 191. operator take? (iii) Participating in one-call systems (a) General requirements. An operator in locations where covered segments must take additional measures beyond are present. those already required by Part 192 to (iv) Monitoring of excavations con- prevent a pipeline failure and to miti- ducted on covered pipeline segments by gate the consequences of a pipeline pipeline personnel. If an operator finds failure in a high consequence area. An physical evidence of encroachment in- operator must base the additional volving excavation that the operator measures on the threats the operator did not monitor near a covered seg- has identified to each pipeline segment, an operator must either exca- ment. (See § 192.917) An operator must vate the area near the encroachment or conduct, in accordance with one of the conduct an above ground survey using risk assessment approaches in ASME/ methods defined in NACE SP0502–2008 ANSI B31.8S (incorporated by ref- (incorporated by reference, see § 192.7). erence, see § 192.7), section 5, a risk An operator must excavate, and reme- analysis of its pipeline to identify addi- diate, in accordance with ANSI/ASME tional measures to protect the high B31.8S and § 192.933 any indication of consequence area and enhance public coating holidays or discontinuity war- safety. Such additional measures in- ranting direct examination. clude, but are not limited to, installing (2) Outside force damage. If an oper- Automatic Shut-off Valves or Remote ator determines that outside force (e.g., Control Valves, installing computer- earth movement, floods, unstable sus- ized monitoring and leak detection sys- pension bridge) is a threat to the integ- tems, replacing pipe segments with rity of a covered segment, the operator pipe of heavier wall thickness, pro- must take measures to minimize the viding additional training to personnel consequences to the covered segment on response procedures, conducting from outside force damage. These drills with local emergency responders measures include, but are not limited and implementing additional inspec- to, increasing the frequency of aerial, tion and maintenance programs. foot or other methods of patrols, add- (b) Third party damage and outside ing external protection, reducing exter- force damage— nal stress, and relocating the line. (1) Third party damage. An operator (c) Automatic shut-off valves (ASV) or must enhance its damage prevention Remote control valves (RCV). If an oper- program, as required under § 192.614 of ator determines, based on a risk anal- this part, with respect to a covered seg- ysis, that an ASV or RCV would be an ment to prevent and minimize the con- efficient means of adding protection to sequences of a release due to third a high consequence area in the event of party damage. Enhanced measures to a gas release, an operator must install

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the ASV or RCV. In making that deter- this section. An operator must reassess mination, an operator must, at least, a covered segment on which a prior as- consider the following factors—swift- sessment is credited as a baseline ness of leak detection and pipe shut- under § 192.921(e) by no later than De- down capabilities, the type of gas being cember 17, 2009. An operator must reas- transported, operating pressure, the sess a covered segment on which a rate of potential release, pipeline pro- baseline assessment is conducted dur- file, the potential for ignition, and lo- ing the baseline period specified in cation of nearest response personnel. § 192.921(d) by no later than seven years (d) Pipelines operating below 30% after the baseline assessment of that SMYS. An operator of a transmission covered segment unless the evaluation pipeline operating below 30% SMYS lo- under paragraph (b) of this section in- cated in a high consequence area must dicates earlier reassessment. follow the requirements in paragraphs (b) Evaluation. An operator must con- (d)(1) and (d)(2) of this section. An oper- duct a periodic evaluation as fre- ator of a transmission pipeline oper- quently as needed to assure the integ- ating below 30% SMYS located in a rity of each covered segment. The peri- Class 3 or Class 4 area but not in a high odic evaluation must be based on a consequence area must follow the re- data integration and risk assessment of quirements in paragraphs (d)(1), (d)(2) the entire pipeline as specified in and (d)(3) of this section. § 192.917. For plastic transmission pipe- (1) Apply the requirements in para- lines, the periodic evaluation is based graphs (b)(1)(i) and (b)(1)(iii) of this on the threat analysis specified in section to the pipeline; and 192.917(d). For all other transmission (2) Either monitor excavations near pipelines, the evaluation must consider the pipeline, or conduct patrols as re- the past and present integrity assess- quired by § 192.705 of the pipeline at bi- ment results, data integration and risk monthly intervals. If an operator finds assessment information (§ 192.917), and any indication of unreported construc- decisions about remediation (§ 192.933) tion activity, the operator must con- and additional preventive and mitiga- duct a follow up investigation to deter- tive actions (§ 192.935). An operator mine if mechanical damage has oc- must use the results from this evalua- curred. tion to identify the threats specific to (3) Perform semi-annual leak surveys each covered segment and the risk rep- (quarterly for unprotected pipelines or resented by these threats. cathodically protected pipe where electrical surveys are impractical). (c) Assessment methods. In conducting (e) Plastic transmission pipeline. An op- the integrity reassessment, an operator erator of a plastic transmission pipe- must assess the integrity of the line line must apply the requirements in pipe in the covered segment by any of paragraphs (b)(1)(i), (b)(1)(iii) and the following methods as appropriate (b)(1)(iv) of this section to the covered for the threats to which the covered segments of the pipeline. segment is susceptible (see § 192.917), or by confirmatory direct assessment [68 FR 69817, Dec. 15, 2003, as amended by under the conditions specified in Amdt. 192–95, 69 FR 18233, Apr. 6, 2004; Amdt. § 192.931. 192–95, 69 FR 29904, May 26, 2004; Amdt. 192– 114, 75 FR 48604, Aug. 11, 2010] (1) Internal inspection tool or tools capable of detecting corrosion, and any § 192.937 What is a continual process other threats to which the covered seg- of evaluation and assessment to ment is susceptible. An operator must maintain a pipeline’s integrity? follow ASME/ANSI B31.8S (incor- (a) General. After completing the porated by reference, see § 192.7), sec- baseline integrity assessment of a cov- tion 6.2 in selecting the appropriate in- ered segment, an operator must con- ternal inspection tools for the covered tinue to assess the line pipe of that segment. segment at the intervals specified in (2) Pressure test conducted in accord- § 192.939 and periodically evaluate the ance with subpart J of this part. An op- integrity of each covered pipeline seg- erator must use the test pressures ment as provided in paragraph (b) of specified in Table 3 of section 5 of

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ASME/ANSI B31.8S, to justify an ex- this section sets forth the maximum tended reassessment interval in accord- allowed reassessment intervals. ance with § 192.939. (1) Pressure test or internal inspection (3) Direct assessment to address or other equivalent technology. An oper- threats of external corrosion, internal ator that uses pressure testing or in- corrosion, or stress corrosion cracking. ternal inspection as an assessment An operator must conduct the direct method must establish the reassess- assessment in accordance with the re- ment interval for a covered pipeline quirements listed in § 192.923 and with segment by— as applicable, the requirements speci- (i) Basing the interval on the identified in §§ 192.925, 192.927 or 192.929; fied threats for the covered segment (4) Other technology that an operator (see § 192.917) and on the analysis of the demonstrates can provide an equiva- results from the last integrity assess- lent understanding of the condition of ment and from the data integration the line pipe. An operator choosing this and risk assessment required by option must notify the Office of Pipe- § 192.917; or line Safety (OPS) 180 days before con- (ii) Using the intervals specified for ducting the assessment, in accordance different stress levels of pipeline (oper- with § 192.949. An operator must also ating at or above 30% SMYS) listed in notify a State or local pipeline safety ASME/ANSI B31.8S, section 5, Table 3. authority when either a covered seg- (2) External Corrosion Direct Assess- ment is located in a State where OPS ment. An operator that uses ECDA that has an interstate agent agreement, or meets the requirements of this subpart an intrastate covered segment is regu- must determine the reassessment in- lated by that State. terval according to the requirements in (5) Confirmatory direct assessment paragraphs 6.2 and 6.3 of NACE SP0502– when used on a covered segment that is 2008 (incorporated by reference, see scheduled for reassessment at a period § 192.7). longer than seven years. An operator (3) Internal Corrosion or SCC Direct As- using this reassessment method must sessment. An operator that uses ICDA comply with § 192.931. or SCCDA in accordance with the re- [68 FR 69817, Dec. 15, 2003, as amended by quirements of this subpart must deter- Amdt. 192–95, 69 FR 18234, Apr. 6, 2004] mine the reassessment interval according to the following method. However, § 192.939 What are the required reas- the reassessment interval cannot ex- sessment intervals? ceed those specified for direct assess- An operator must comply with the ment in ASME/ANSI B31.8S, section 5, following requirements in establishing Table 3. the reassessment interval for the oper- (i) Determine the largest defect most ator’s covered pipeline segments. likely to remain in the covered seg- (a) Pipelines operating at or above 30% ment and the corrosion rate appro- SMYS. An operator must establish a re- priate for the pipe, soil and protection assessment interval for each covered conditions; segment operating at or above 30% (ii) Use the largest remaining defect SMYS in accordance with the require- as the size of the largest defect discov- ments of this section. The maximum ered in the SCC or ICDA segment; and reassessment interval by an allowable (iii) Estimate the reassessment inter- reassessment method is seven years. If val as half the time required for the an operator establishes a reassessment largest defect to grow to a critical size. interval that is greater than seven (b) Pipelines Operating Below 30% years, the operator must, within the SMYS. An operator must establish a re- seven-year period, conduct a confirm- assessment interval for each covered atory direct assessment on the covered segment operating below 30% SMYS in segment, and then conduct the follow- accordance with the requirements of up reassessment at the interval the op- this section. The maximum reassess- erator has established. A reassessment ment interval by an allowable reassess- carried out using confirmatory direct ment method is seven years. An oper- assessment must be done in accordance ator must establish reassessment by at with § 192.931. The table that follows least one of the following—

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(1) Reassessment by pressure test, in- accordance with § 192.931, with reassess- ternal inspection or other equivalent ment by one of the methods listed in technology following the requirements paragraphs (b)(1) through (b)(3) of this in paragraph (a)(1) of this section ex- section by year 20 of the interval. cept that the stress level referenced in (5) Reassessment by the low stress paragraph (a)(1)(ii) of this section assessment method at 7-year intervals would be adjusted to reflect the lower in accordance with § 192.941 with reas- operating stress level. If an established sessment by one of the methods listed interval is more than seven years, the in paragraphs (b)(1) through (b)(3) of operator must conduct by the seventh this section by year 20 of the interval. year of the interval either a confirm- (6) The following table sets forth the atory direct assessment in accordance maximum reassessment intervals. Also with § 192.931, or a low stress reassess- refer to Appendix E.II for guidance on ment in accordance with § 192.941. Assessment Methods and Assessment (2) Reassessment by ECDA following Schedule for Transmission Pipelines the requirements in paragraph (a)(2) of Operating Below 30% SMYS. In case of this section. conflict between the rule and the guid- (3) Reassessment by ICDA or SCCDA ance in the Appendix, the requirements following the requirements in para- of the rule control. An operator must graph (a)(3) of this section. comply with the following require- (4) Reassessment by confirmatory di- ments in establishing a reassessment rect assessment at 7-year intervals in interval for a covered segment:

MAXIMUM REASSESSMENT INTERVAL

Pipeline operating at or above Pipeline operating at or above Pipeline operating below 30% Assessment method 50% SMYS 30% SMYS, up to 50% SMYS SMYS

Internal Inspection Tool, Pres- 10 years (*) ...... 15 years (*) ...... 20 years.(**) sure Test or Direct Assess- ment. Confirmatory Direct Assess- 7 years ...... 7 years ...... 7 years. ment. 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.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192–95, 69 FR 18234, Apr. 6, 2004; 192–114, 75 FR 48604, Aug. 11, 2010]

§ 192.941 What is a low stress reassess- on cathodically protected pipe in a cov- ment? ered segment, an operator must per- (a) General. An operator of a trans- form an electrical survey (i.e. indirect mission line that operates below 30% examination tool/method) at least SMYS may use the following method every 7 years on the covered segment. to reassess a covered segment in ac- An operator must use the results of cordance with § 192.939. This method of each survey as part of an overall eval- reassessment addresses the threats of uation of the cathodic protection and external and internal corrosion. The corrosion threat for the covered seg- operator must have conducted a base- ment. This evaluation must consider, line assessment of the covered segment at minimum, the leak repair and in- in accordance with the requirements of spection records, corrosion monitoring §§ 192.919 and 192.921. records, exposed pipe inspection (b) External corrosion. An operator records, and the pipeline environment. must take one of the following actions (2) Unprotected pipe or cathodically to address external corrosion on the protected pipe where electrical surveys are low stress covered segment. impractical. If an electrical survey is (1) Cathodically protected pipe. To ad- impractical on the covered segment an dress the threat of external corrosion operator must—

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(i) Conduct leakage surveys as re- ment if the operator demonstrates that quired by § 192.706 at 4-month intervals; it cannot maintain local product sup- and ply if it conducts the reassessment (ii) Every 18 months, identify and re- within the required interval. mediate areas of active corrosion by (b) How to apply. If one of the condi- evaluating leak repair and inspection tions specified in paragraph (a) (1) or records, corrosion monitoring records, (a) (2) of this section applies, an oper- exposed pipe inspection records, and ator may seek a waiver of the required the pipeline environment. reassessment interval. An operator (c) Internal corrosion. To address the must apply for a waiver in accordance threat of internal corrosion on a cov- with 49 U.S.C. 60118(c), at least 180 days ered segment, an operator must— (1) Conduct a gas analysis for corro- before the end of the required reassess- sive agents at least once each calendar ment interval, unless local product year; supply issues make the period imprac- (2) Conduct periodic testing of fluids tical. If local product supply issues removed from the segment. At least make the period impractical, an oper- once each calendar year test the fluids ator must apply for the waiver as soon removed from each storage field that as the need for the waiver becomes may affect a covered segment; and known. (3) At least every seven (7) years, in- [68 FR 69817, Dec. 15, 2003, as amended by tegrate data from the analysis and Amdt. 192–95, 69 FR 18234, Apr. 6, 2004] testing required by paragraphs (c)(1)– (c)(2) with applicable internal corro- § 192.945 What methods must an oper- sion leak records, incident reports, ator use to measure program effec- safety-related condition reports, repair tiveness? records, patrol records, exposed pipe reports, and test records, and define and (a) General. An operator must include implement appropriate remediation ac- in its integrity management program tions. methods to measure whether the program is effective in assessing and eval- [68 FR 69817, Dec. 15, 2003, as amended by uating the integrity of each covered Amdt. 192–95, 69 FR 18234, Apr. 6, 2004] pipeline segment and in protecting the § 192.943 When can an operator devi- high consequence areas. These meas- ate from these reassessment inter- ures must include the four overall per- vals? formance measures specified in ASME/ (a) Waiver from reassessment interval in ANSI B31.8S (incorporated by ref- limited situations. In the following lim- erence, see § 192.7 of this part), section ited instances, OPS may allow a waiver 9.4, and the specific measures for each from a reassessment interval required identified threat specified in ASME/ by § 192.939 if OPS finds a waiver would ANSI B31.8S, Appendix A. An operator not be inconsistent with pipeline safe- must submit the four overall perform- ty. ance measures as part of the annual re- (1) Lack of internal inspection tools. An port required by § 191.17 of this sub- operator who uses internal inspection chapter. as an assessment method may be able (b) External Corrosion Direct assess- to justify a longer reassessment period ment. In addition to the general re- for a covered segment if internal in- quirements for performance measures spection tools are not available to as- in paragraph (a) of this section, an op- sess the line pipe. To justify this, the erator using direct assessment to as- operator must demonstrate that it can- sess the external corrosion threat must not obtain the internal inspection tools define and monitor measures to deter- within the required reassessment pe- mine the effectiveness of the ECDA riod and that the actions the operator is taking in the interim ensure the in- process. These measures must meet the tegrity of the covered segment. requirements of § 192.925. (2) Maintain product supply. An oper- [68 FR 69817, Dec. 15, 2003, as amended by ator may be able to justify a longer re- Amdt. 192–95, 69 FR 18234, Apr. 6, 2004; 75 FR assessment period for a covered seg- 72906, Nov. 26, 2010]

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§ 192.947 What records must an oper- (a) Sending the notification to the ator keep? Office of Pipeline Safety, Pipeline and An operator must maintain, for the Hazardous Materials Safety Adminis- useful life of the pipeline, records that tration, U.S. Department of Transpor- demonstrate compliance with the re- tation, Information Resources Man- quirements of this subpart. At min- ager, PHP–10, 1200 New Jersey Avenue, imum, an operator must maintain the SE., Washington, DC 20590-0001; following records for review during an (b) Sending the notification to the inspection. Information Resources Manager by fac- (a) A written integrity management simile to (202) 366–7128; or program in accordance with § 192.907; (c) Entering the information directly (b) Documents supporting the threat on the Integrity Management Database identification and risk assessment in (IMDB) Web site at http:// accordance with § 192.917; primis.rspa.dot.gov/gasimp/. (c) A written baseline assessment [68 FR 69817, Dec. 15, 2003, as amended at 70 plan in accordance with § 192.919; FR 11139, Mar. 8, 2005; Amdt. 192–103, 72 FR (d) Documents to support any deci- 4657, Feb. 1, 2007; 73 FR 16570, Mar. 28, 2008; 74 sion, analysis and process developed FR 2894, Jan. 16, 2009] and used to implement and evaluate each element of the baseline assess- § 192.951 Where does an operator file a ment plan and integrity management report? program. Documents include those de- An operator must file any report re- veloped and used in support of any quired by this subpart electronically to identification, calculation, amend- the Pipeline and Hazardous Materials ment, modification, justification, devi- Safety Administration in accordance ation and determination made, and any with § 191.7 of this subchapter. action taken to implement and evalu- [Amdt. No. 192—115, 75 FR 72906, Nov. 26, 2010] ate any of the program elements; (e) Documents that demonstrate personnel have the required training, in- Subpart P—Gas Distribution Pipe- cluding a description of the training line Integrity Management program, in accordance with § 192.915; (IM) (f) Schedule required by § 192.933 that prioritizes the conditions found during SOURCE: 74 FR 63934, Dec. 4, 2009, unless an assessment for evaluation and reme- otherwise noted. diation, including technical justifica- tions for the schedule. § 192.1001 What definitions apply to (g) Documents to carry out the re- this subpart? quirements in §§ 192.923 through 192.929 The following definitions apply to for a direct assessment plan; this subpart: (h) Documents to carry out the re- Excavation Damage means any impact quirements in § 192.931 for confirmatory that results in the need to repair or re- direct assessment; place an underground facility due to a (i) Verification that an operator has weakening, or the partial or complete provided any documentation or notifi- destruction, of the facility, including, cation required by this subpart to be but not limited to, the protective coat- provided to OPS, and when applicable, ing, lateral support, cathodic protec- a State authority with which OPS has tion or the housing for the line device an interstate agent agreement, and a or facility. State or local pipeline safety authority Hazardous Leak means a leak that that regulates a covered pipeline seg- represents an existing or probable haz- ment within that State. ard to persons or property and requires [68 FR 69817, Dec. 15, 2003, as amended by immediate repair or continuous action Amdt. 192–95, 69 FR 18234, Apr. 6, 2004] until the conditions are no longer hazardous. § 192.949 How does an operator notify Integrity Management Plan or IM Plan PHMSA? means a written explanation of the An operator must provide any notifi- mechanisms or procedures the operator cation required by this subpart by— will use to implement its integrity

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management program and to ensure gas distribution system developed from compliance with this subpart. reasonably available information. Integrity Management Program or IM (1) Identify the characteristics of the Program means an overall approach by pipeline’s design and operations and an operator to ensure the integrity of the environmental factors that are nec- its gas distribution system. essary to assess the applicable threats Mechanical fitting means a mechan- and risks to its gas distribution pipe- ical device used to connect sections of line. pipe. The term ‘‘Mechanical fitting’’ (2) Consider the information gained applies only to: from past design, operations, and main- (1) Stab Type fittings; tenance. (2) Nut Follower Type fittings; (3) Identify additional information (3) Bolted Type fittings; or needed and provide a plan for gaining (4) Other Compression Type fittings. that information over time through normal activities conducted on the Small LPG Operator means an oper- pipeline (for example, design, construc- ator of a liquefied petroleum gas (LPG) tion, operations or maintenance activi- distribution pipeline that serves fewer ties). than 100 customers from a single (4) Develop and implement a process source. by which the IM program will be re- [74 FR 63934, Dec. 4, 2009, as amended at 76 viewed periodically and refined and im- FR 5499, Feb. 1, 2011] proved as needed. (5) Provide for the capture and reten- § 192.1003 What do the regulations in tion of data on any new pipeline in- this subpart cover? stalled. The data must include, at a General. This subpart prescribes min- minimum, the location where the new imum requirements for an IM program pipeline is installed and the material of for any gas distribution pipeline cov- which it is constructed. ered under this part, including lique- (b) Identify threats. The operator fied petroleum gas systems. A gas dis- must consider the following categories tribution operator, other than a master of threats to each gas distribution meter operator or a small LPG oper- pipeline: corrosion, natural forces, ex- ator, must follow the requirements in cavation damage, other outside force §§ 192.1005–192.1013 of this subpart. A damage, material or welds, equipment master meter operator or small LPG failure, incorrect operations, and other operator of a gas distribution pipeline concerns that could threaten the integ- must follow the requirements in rity of its pipeline. An operator must § 192.1015 of this subpart. consider reasonably available information to identify existing and potential § 192.1005 What must a gas distribu- threats. Sources of data may include, tion operator (other than a master but are not limited to, incident and meter or small LPG operator) do to leak history, corrosion control records, implement this subpart? continuing surveillance records, pa- No later than August 2, 2011 a gas dis- trolling records, maintenance history, tribution operator must develop and and excavation damage experience. implement an integrity management (c) Evaluate and rank risk. An oper- program that includes a written integ- ator must evaluate the risks associated rity management plan as specified in with its distribution pipeline. In this § 192.1007. evaluation, the operator must determine the relative importance of each § 192.1007 What are the required ele- threat and estimate and rank the risks ments of an integrity management posed to its pipeline. This evaluation plan? must consider each applicable current A written integrity management and potential threat, the likelihood of plan must contain procedures for devel- failure associated with each threat, oping and implementing the following and the potential consequences of such elements: a failure. An operator may subdivide (a) Knowledge. An operator must its pipeline into regions with similar demonstrate an understanding of its characteristics (e.g., contiguous areas

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within a distribution pipeline con- gram re-evaluation at least every five sisting of mains, services and other ap- years. The operator must consider the purtenances; areas with common mate- results of the performance monitoring rials or environmental factors), and for in these evaluations. which similar actions likely would be (g) Report results. Report, on an an- effective in reducing risk. nual basis, the four measures listed in (d) Identify and implement measures to paragraphs (e)(1)(i) through (e)(1)(iv) of address risks. Determine and implement this section, as part of the annual re- measures designed to reduce the risks port required by § 191.11. An operator from failure of its gas distribution also must report the four measures to pipeline. These measures must include the state pipeline safety authority if a an effective leak management program state exercises jurisdiction over the op- (unless all leaks are repaired when erator’s pipeline. found). (e) Measure performance, monitor re- [74 FR 63934, Dec. 4, 2009, as amended at 76 FR 5499, Feb. 1, 2011] sults, and evaluate effectiveness. (1) Develop and monitor performance § 192.1009 What must an operator re- measures from an established baseline port when a mechanical fitting to evaluate the effectiveness of its IM fails? program. An operator must consider (a) Except as provided in paragraph the results of its performance moni- (b) of this section, each operator of a toring in periodically re-evaluating the distribution pipeline system must sub- threats and risks. These performance mit a report on each mechanical fit- measures must include the following: ting failure, excluding any failure that (i) Number of hazardous leaks either results only in a nonhazardous leak, on eliminated or repaired as required by a Department of Transportation Form § 192.703(c) of this subchapter (or total PHMSA F–7100.1–2. The report(s) must number of leaks if all leaks are re- be submitted in accordance with paired when found), categorized by § 191.12. cause; (b) The mechanical fitting failure re- (ii) Number of excavation damages; porting requirements in paragraph (a) (iii) Number of excavation tickets of this section do not apply to the fol- (receipt of information by the under- lowing: ground facility operator from the noti- (1) Master meter operators; fication center); (2) Small LPG operator as defined in (iv) Total number of leaks either § 192.1001; or eliminated or repaired, categorized by (3) LNG facilities. cause; (v) Number of hazardous leaks either [76 FR 5499, Feb. 1, 2011] eliminated or repaired as required by § 192.703(c) (or total number of leaks if § 192.1011 What records must an oper- all leaks are repaired when found), cat- ator keep? egorized by material; and An operator must maintain records (vi) Any additional measures the op- demonstrating compliance with the re- erator determines are needed to evalu- quirements of this subpart for at least ate the effectiveness of the operator’s 10 years. The records must include cop- IM program in controlling each identi- ies of superseded integrity manage- fied threat. ment plans developed under this sub- (f) Periodic Evaluation and Improve- part. ment. An operator must re-evaluate threats and risks on its entire pipeline § 192.1013 When may an operator devi- and consider the relevance of threats in ate from required periodic inspec- one location to other areas. Each oper- tions under this part? ator must determine the appropriate (a) An operator may propose to re- period for conducting complete produce the frequency of periodic inspec- gram evaluations based on the com- tions and tests required in this part on plexity of its system and changes in the basis of the engineering analysis factors affecting the risk of failure. An and risk assessment required by this operator must conduct a complete pro- subpart.

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(b) An operator must submit its pro- (3) Rank risks. The operator must posal to the PHMSA Associate Admin- evaluate the risks to its pipeline and istrator for Pipeline Safety or, in the estimate the relative importance of case of an intrastate pipeline facility each identified threat. regulated by the State, the appropriate (4) Identify and implement measures to State agency. The applicable oversight mitigate risks. The operator must deter- agency may accept the proposal on its mine and implement measures de- own authority, with or without condi- signed to reduce the risks from failure tions and limitations, on a showing of its pipeline. that the operator’s proposal, which in- (5) Measure performance, monitor re- cludes the adjusted interval, will pro- sults, and evaluate effectiveness. The op- vide an equal or greater overall level of erator must monitor, as a performance safety. measure, the number of leaks elimi- (c) An operator may implement an nated or repaired on its pipeline and approved reduction in the frequency of their causes. a periodic inspection or test only where (6) Periodic evaluation and improve- the operator has developed and implement. The operator must determine the mented an integrity management pro- appropriate period for conducting IM gram that provides an equal or im- program evaluations based on the com- proved overall level of safety despite plexity of its pipeline and changes in the reduced frequency of periodic in- factors affecting the risk of failure. An spections. operator must re-evaluate its entire program at least every five years. The § 192.1015 What must a master meter operator must consider the results of or small liquefied petroleum gas the performance monitoring in these (LPG) operator do to implement evaluations. this subpart? (c) Records. The operator must main- (a) General. No later than August 2, tain, for a period of at least 10 years, 2011 the operator of a master meter the following records: system or a small LPG operator must (1) A written IM plan in accordance develop and implement an IM program with this section, including superseded that includes a written IM plan as IM plans; specified in paragraph (b) of this sec- (2) Documents supporting threat tion. The IM program for these pipe- identification; and lines should reflect the relative sim- (3) Documents showing the location plicity of these types of pipelines. and material of all piping and appur- tenances that are installed after the ef- (b) Elements. A written integrity fective date of the operator’s IM pro- management plan must address, at a gram and, to the extent known, the lo- minimum, the following elements: cation and material of all pipe and ap- (1) Knowledge. The operator must purtenances that were existing on the demonstrate knowledge of its pipeline, effective date of the operator’s pro- which, to the extent known, should in- gram. clude the approximate location and material of its pipeline. The operator APPENDIX A TO PART 192 [RESERVED] must identify additional information needed and provide a plan for gaining APPENDIX B TO PART 192— knowledge over time through normal QUALIFICATION OF PIPE activities conducted on the pipeline I. Listed Pipe Specifications (for example, design, construction, op- API 5L—Steel pipe, ‘‘API Specification for erations or maintenance activities). Line Pipe’’ (incorporated by reference, see (2) Identify threats. The operator must § 192.7). consider, at minimum, the following ASTM A53/A53M—Steel pipe, ‘‘Standard categories of threats (existing and po- Specification for Pipe, Steel Black and Hot- tential): Corrosion, natural forces, ex- Dipped, Zinc-Coated, Welded and Seamless’’ (incorporated by reference, see § 192.7). cavation damage, other outside force ASTM A106—Steel pipe, ‘‘Standard Speci- damage, material or weld failure, fication for Seamless Carbon Steel Pipe for equipment failure, and incorrect oper- High Temperature Service’’ (incorporated by ation. reference, see § 192.7).

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ASTM A333/A333M—Steel pipe, ‘‘Standard ceeding in accordance with section IX of the Specification for Seamless and Welded Steel ASME Boiler and Pressure Vessel Code (ibr, Pipe for Low Temperature Service’’ (incor- see 192.7). The same number of chemical tests porated by reference, see § 192.7). must be made as are required for testing a ASTM A381—Steel pipe, ‘‘Standard Speci- girth weld. fication for Metal-Arc-Welded Steel Pipe for C. Inspection. The pipe must be clean Use with High-Pressure Transmission Sys- enough to permit adequate inspection. It tems’’ (incorporated by reference, see § 192.7). must be visually inspected to ensure that it ASTM A671—Steel pipe, ‘‘Standard Speci- is reasonably round and straight and there fication for Electric-Fusion-Welded Pipe for are no defects which might impair the Atmospheric and Lower Temperatures’’ (in- strength or tightness of the pipe. corporated by reference, see § 192.7). D. Tensile Properties. If the tensile prop- ASTM A672—Steel pipe, ‘‘Standard Speci- erties of the pipe are not known, the min- fication for Electric-Fusion-Welded Steel imum yield strength may be taken as 24,000 Pipe for High-Pressure Service at Moderate p.s.i. (165 MPa) or less, or the tensile prop- Temperatures’’ (incorporated by reference, erties may be established by performing ten- see § 192.7). sile tests as set forth in API Specification 5L ASTM A691—Steel pipe, ‘‘Standard Speci- (incorporated by reference, see § 192.7). All fication for Carbon and Alloy Steel Pipe, test specimens shall be selected at random Electric-Fusion-Welded for High Pressure and the following number of tests must be Service at High Temperatures’’ (incor- performed: porated by reference, see § 192.7). ASTM D2513–99—Thermoplastic pipe and NUMBER OF TENSILE TESTS—ALL SIZES tubing, ‘‘Standard Specification for Thermo- plastic Gas Pressure Pipe, Tubing, and Fit- 10 lengths or less ...... 1 set of tests for each length. tings’’ (incorporated by reference, see § 192.7). 11 to 100 lengths ...... 1 set of tests for each 5 ASTM D2517—Thermosetting plastic pipe lengths, but not less than and tubing, ‘‘Standard Specification for Re- 10 tests. inforced Epoxy Resin Gas Pressure Pipe and Over 100 lengths ...... 1 set of tests for each 10 Fittings’’ (incorporated by reference, see lengths, but not less than § 192.7). 20 tests. II. Steel pipe of unknown or unlisted specification. If the yield-tensile ratio, based on the prop- A. Bending Properties. For pipe 2 inches (51 erties determined by those tests, exceeds millimeters) or less in diameter, a length of 0.85, the pipe may be used only as provided in pipe must be cold bent through at least 90 § 192.55(c). degrees around a cylindrical mandrel that III. Steel pipe manufactured before November has a diameter 12 times the diameter of the 12, 1970, to earlier editions of listed specifica- pipe, without developing cracks at any portions. Steel pipe manufactured before Novem- tion and without opening the longitudinal ber 12, 1970, in accordance with a specifica- weld. tion of which a later edition is listed in sec- For pipe more than 2 inches (51 millime- tion I of this appendix, is qualified for use ters) in diameter, the pipe must meet the re- under this part if the following requirements quirements of the flattening tests set forth are met: in ASTM A53 (incorporated by reference, see A. Inspection. The pipe must be clean § 192.7), except that the number of tests must enough to permit adequate inspection. It be at least equal to the minimum required in must be visually inspected to ensure that it paragraph II-D of this appendix to determine is reasonably round and straight and that yield strength. there are no defects which might impair the B. Weldability. A girth weld must be made strength or tightness of the pipe. in the pipe by a welder who is qualified under B. Similarity of specification requirements. subpart E of this part. The weld must be The edition of the listed specification under made under the most severe conditions under which the pipe was manufactured must have which welding will be allowed in the field substantially the same requirements with re- and by means of the same procedure that spect to the following properties as a later will be used in the field. On pipe more than edition of that specification listed in section 4 inches (102 millimeters) in diameter, at I of this appendix: least one test weld must be made for each 100 (1) Physical (mechanical) properties of lengths of pipe. On pipe 4 inches (102 milli- pipe, including yield and tensile strength, meters) or less in diameter, at least one test elongation, and yield to tensile ratio, and weld must be made for each 400 lengths of testing requirements to verify those prop- pipe. The weld must be tested in accordance erties. with API Standard 1104 (incorporated by ref- (2) Chemical properties of pipe and testing erence, see § 192.7). If the requirements of API requirements to verify those properties. Standard 1104 cannot be met, weldability C. Inspection or test of welded pipe. On pipe may be established by making chemical with welded seams, one of the following re- tests for carbon and manganese, and pro- quirements must be met:

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(1) The edition of the listed specification to III. Periodic tests for welders of small service which the pipe was manufactured must have lines. Two samples of the welder’s work, each substantially the same requirements with re- about 8 inches (203 millimeters) long with spect to nondestructive inspection of welded the weld located approximately in the cen- seams and the standards for acceptance or ter, are cut from steel service line and tested rejection and repair as a later edition of the as follows: specification listed in section I of this appen- (1) One sample is centered in a guided bend dix. testing machine and bent to the contour of (2) The pipe must be tested in accordance the die for a distance of 2 inches (51 millime- with subpart J of this part to at least 1.25 ters) on each side of the weld. If the sample times the maximum allowable operating shows any breaks or cracks after removal pressure if it is to be installed in a class 1 lo- from the bending machine, it is unaccept- cation and to at least 1.5 times the max- able. imum allowable operating pressure if it is to (2) The ends of the second sample are flat- be installed in a class 2, 3, or 4 location. Not- tened and the entire joint subjected to a ten- withstanding any shorter time period per- sile strength test. If failure occurs adjacent mitted under subpart J of this part, the test to or in the weld metal, the weld is unaccept- pressure must be maintained for at least 8 able. If a tensile strength testing machine is hours. not available, this sample must also pass the [35 FR 13257, Aug. 19, 1970] bending test prescribed in subparagraph (1) of this paragraph. EDITORIAL NOTE: For FEDERAL REGISTER citations affecting appendix B of part 192, see [35 FR 13257, Aug. 19, 1970, as amended by the List of CFR Sections Affected, which ap- Amdt. 192–85, 63 FR 37504, July 13, 1998; pears in the Finding Aids section of the Amdt. 192–94, 69 FR 32896, June 14, 2004] printed volume and at www.fdsys.gov. APPENDIX D TO PART 192—CRITERIA FOR APPENDIX C TO PART 192—QUALIFICA- CATHODIC PROTECTION AND DETER- TION OF WELDERS FOR LOW STRESS MINATION OF MEASUREMENTS LEVEL PIPE I. Criteria for cathodic protection— A. Steel, I. Basic test. The test is made on pipe 12 cast iron, and ductile iron structures. (1) A neg- inches (305 millimeters) or less in diameter. ative (cathodic) voltage of at least 0.85 volt, The test weld must be made with the pipe in with reference to a saturated copper-copper a horizontal fixed position so that the test sulfate half cell. Determination of this volt- weld includes at least one section of over- age must be made with the protective cur- head position welding. The beveling, root rent applied, and in accordance with sections opening, and other details must conform to II and IV of this appendix. the specifications of the procedure under (2) A negative (cathodic) voltage shift of at which the welder is being qualified. Upon least 300 millivolts. Determination of this completion, the test weld is cut into four voltage shift must be made with the protec- coupons and subjected to a root bend test. If, tive current applied, and in accordance with as a result of this test, two or more of the sections II and IV of this appendix. This cri- four coupons develop a crack in the weld ma- terion of voltage shift applies to structures terial, or between the weld material and base not in contact with metals of different an- metal, that is more than 1⁄8-inch (3.2 millime- odic potentials. ters) long in any direction, the weld is unacceptable. Cracks that occur on the corner of (3) A minimum negative (cathodic) polar- the specimen during testing are not consid- ization voltage shift of 100 millivolts. This ered. A welder who successfully passes a polarization voltage shift must be deter- butt-weld qualification test under this sec- mined in accordance with sections III and IV tion shall be qualified to weld on all pipe di- of this appendix. ameters less than or equal to 12 inches. (4) A voltage at least as negative (cathodic) II. Additional tests for welders of service line as that originally established at the begin- connections to mains. A service line connec- ning of the Tafel segment of the E-log-I tion fitting is welded to a pipe section with curve. This voltage must be measured in ac- the same diameter as a typical main. The cordance with section IV of this appendix. weld is made in the same position as it is (5) A net protective current from the elec- made in the field. The weld is unacceptable trolyte into the structure surface as meas- if it shows a serious undercutting or if it has ured by an earth current technique applied rolled edges. The weld is tested by attempt- at predetermined current discharge (anodic) ing to break the fitting off the run pipe. The points of the structure. weld is unacceptable if it breaks and shows B. Aluminum structures. (1) Except as pro- incomplete fusion, overlap, or poor penetra- vided in paragraphs (3) and (4) of this para- tion at the junction of the fitting and run graph, a minimum negative (cathodic) volt- pipe. age shift of 150 millivolts, produced by the

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application of protective current. The volt- current and measuring the polarization age shift must be determined in accordance decay. When the current is initially inter- with sections II and IV of this appendix. rupted, an immediate voltage shift occurs. (2) Except as provided in paragraphs (3) and The voltage reading after the immediate (4) of this paragraph, a minimum negative shift must be used as the base reading from (cathodic) polarization voltage shift of 100 which to measure polarization decay in para- millivolts. This polarization voltage shift graphs A(3), B(2), and C of section I of this must be determined in accordance with sec- appendix. tions III and IV of this appendix. IV. Reference half cells. A. Except as pro- (3) Notwithstanding the alternative min- vided in paragraphs B and C of this section, imum criteria in paragraphs (1) and (2) of negative (cathodic) voltage must be meas- this paragraph, aluminum, if cathodically ured between the structure surface and a protected at voltages in excess of 1.20 volts saturated copper-copper sulfate half cell con- as measured with reference to a copper-cop- tacting the electrolyte. per sulfate half cell, in accordance with sec- B. Other standard reference half cells may tion IV of this appendix, and compensated be substituted for the saturated cooper-cop- for the voltage (IR) drops other than those per sulfate half cell. Two commonly used ref- across the structure-electrolyte boundary erence half cells are listed below along with may suffer corrosion resulting from the ¥ build-up of alkali on the metal surface. A their voltage equivalent to 0.85 volt as re- voltage in excess of 1.20 volts may not be ferred to a saturated copper-copper sulfate used unless previous test results indicate no half cell: appreciable corrosion will occur in the par- (1) Saturated KCl calomel half cell: ¥0.78 ticular environment. volt. (4) Since aluminum may suffer from corro- (2) Silver-silver chloride half cell used in sion under high pH conditions, and since ap- sea water: ¥0.80 volt. plication of cathodic protection tends to in- C. In addition to the standard reference crease the pH at the metal surface, careful half cells, an alternate metallic material or investigation or testing must be made before structure may be used in place of the satu- applying cathodic protection to stop pitting rated copper-copper sulfate half cell if its po- attack on aluminum structures in environ- tential stability is assured and if its voltage ments with a natural pH in excess of 8. equivalent referred to a saturated copper- C. Copper structures. A minimum negative copper sulfate half cell is established. (cathodic) polarization voltage shift of 100 millivolts. This polarization voltage shift [Amdt. 192–4, 36 FR 12305, June 30, 1971] must be determined in accordance with sections III and IV of this appendix. APPENDIX E TO PART 192—GUIDANCE ON D. Metals of different anodic potentials. A DETERMINING HIGH CONSEQUENCE negative (cathodic) voltage, measured in ac- AREAS AND ON CARRYING OUT RE- cordance with section IV of this appendix, QUIREMENTS IN THE INTEGRITY MAN- equal to that required for the most anodic AGEMENT RULE metal in the system must be maintained. If amphoteric structures are involved that I. GUIDANCE ON DETERMINING A HIGH could be damaged by high alkalinity covered CONSEQUENCE AREA by paragraphs (3) and (4) of paragraph B of this section, they must be electrically iso- To determine which segments of an opera- lated with insulating flanges, or the equiva- tor’s transmission pipeline system are cov- lent. ered for purposes of the integrity manage- II. Interpretation of voltage measurement. ment program requirements, an operator Voltage (IR) drops other than those across must identify the high consequence areas. the structure-electrolyte boundary must be An operator must use method (1) or (2) from considered for valid interpretation of the the definition in § 192.903 to identify a high voltage measurement in paragraphs A(1) and consequence area. An operator may apply (2) and paragraph B(1) of section I of this ap- one method to its entire pipeline system, or pendix. an operator may apply one method to indi- III. Determination of polarization voltage vidual portions of the pipeline system. (Refer shift. The polarization voltage shift must be to figure E.I.A for a diagram of a high con- determined by interrupting the protective sequence area).

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II. GUIDANCE ON ASSESSMENT METHODS AND (i.e. outside of potential impact circle) but ADDITIONAL PREVENTIVE AND MITIGATIVE located within a Class 3 or Class 4 Location. MEASURES FOR TRANSMISSION PIPELINES (b) Table E.II.2 gives guidance to help an operator implement requirements on assess- (a) Table E.II.1 gives guidance to help an operator implement requirements on addi- ment methods for addressing time dependent tional preventive and mitigative measures and independent threats for a transmission for addressing time dependent and inde- pipeline in an HCA. pendent threats for a transmission pipeline (c) Table E.II.3 gives guidance on preventa- operating below 30% SMYS not in an HCA tive & mitigative measures addressing time

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dependent and independent threats for transmission pipelines that operate below 30% SMYS, in HCAs.

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[Amdt. 192–95, 69 FR 18234, Apr. 6, 2004, as 193.2305–193.2319 [Reserved] amended by Amdt. 192–95, May 26, 2004] 193.2321 Nondestructive tests. 193.2323–193.2329 [Reserved]

PART 193—LIQUEFIED NATURAL Subpart E—Equipment GAS FACILITIES: FEDERAL SAFETY STANDARDS 193.2401 Scope. VAPORIZATION EQUIPMENT Subpart A—General 193.2403–193.2439 [Reserved] Sec. 193.2441 Control center. 193.2001 Scope of part. 193.2443 [Reserved] 193.2003 [Reserved] 193.2445 Sources of power. 193.2005 Applicability. 193.2007 Definitions. Subpart F—Operations 193.2009 Rules of regulatory construction. 193.2011 Reporting. 193.2501 Scope. 193.2013 Incorporation by reference. 193.2503 Operating procedures. 193.2015 [Reserved] 193.2505 Cooldown. 193.2017 Plans and procedures. 193.2507 Monitoring operations. 193.2019 Mobile and temporary LNG facili- 193.2509 Emergency procedures. ties. 193.2511 Personnel safety. 193.2513 Transfer procedures. Subpart B—Siting Requirements 193.2515 Investigations of failures. 193.2517 Purging. 193.2051 Scope. 193.2519 Communication systems. 193.2055 [Reserved] 193.2521 Operating records. 193.2057 Thermal radiation protection. 193.2059 Flammable vapor-gas dispersion Subpart G—Maintenance protection. 193.2061–193.2065 [Reserved] 193.2601 Scope. 193.2067 Wind forces. 193.2603 General. 193.2069–193.2073 [Reserved] 193.2605 Maintenance procedures. 193.2607 Foreign material. Subpart C—Design 193.2609 Support systems. 193.2101 Scope. 193.2611 Fire protection. 193.2613 Auxiliary power sources. MATERIALS 193.2615 Isolating and purging. 193.2617 Repairs. 193.2103–193.2117 [Reserved] 193.2619 Control systems. 193.2119 Records. 193.2621 Testing transfer hoses. DESIGN OF COMPONENTS AND BUILDINGS 193.2623 Inspecting LNG storage tanks. 193.2625 Corrosion protection. 193.2121–193.2153 [Reserved] 193.2627 Atmospheric corrosion control. 193.2629 External corrosion control: buried IMPOUNDMENT DESIGN AND CAPACITY or submerged components. 193.2155 Structural requirements. 193.2631 Internal corrosion control. 193.2157–193.2159 [Reserved] 193.2633 Interference currents. 193.2161 Dikes, general. 193.2635 Monitoring corrosion control. 193.2163–193.2165 [Reserved] 193.2637 Remedial measures. 193.2167 Covered systems. 193.2639 Maintenance records. 193.2169–193.2171 [Reserved] 193.2173 Water removal. Subpart H—Personnel Qualifications and 193.2175–193.2179 [Reserved] Training 193.2181 Impoundment capacity: LNG storage tanks. 193.2701 Scope. 193.2183–193.2185 [Reserved] 193.2703 Design and fabrication. 193.2705 Construction, installation, inspec- LNG STORAGE TANKS tion, and testing. 193.2187 Nonmetallic membrane liner. 193.2707 Operations and maintenance. 193.2189–193.2233 [Reserved] 193.2709 Security. 193.2711 Personnel health. Subpart D—Construction 193.2713 Training: operations and maintenance. 193.2301 Scope. 193.2715 Training: security. 193.2303 Construction acceptance. 193.2717 Training: fire protection. 193.2304 Corrosion control overview. 193.2719 Training: records.

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