Appendix A to Part 191 - Procedure for determining reporting threshold

APPENDIX A TO PART 191 PROCEDURE FOR DETERMINING REPORTING THRESHOLD I. Property Damage Threshold Formula Each year after calendar year 2021, the Administrator will publish a notice on PHMSA's website announcing the updates to the property damage threshold criterion that will take effect on July 1 of that year and will remain in effect until the June 30 of the next year. The property damage threshold used in the definition of an Incident at § 191.3 shall be determined in accordance with the following formula: Where: Tr is the revised damage threshold, Tp is the previous damage threshold, CPIr is the average Consumer Price Indices for all Urban Consumers (CPI-U) published by the Bureau of Labor Statistics each month during the most recent complete calendar year, and CPIp is the average CPI-U for the calendar year used to establish the previous property damage criteria. PART 192 - TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: MINIMUM SAFETY STANDARDS SUBPART A - GENERAL § 192.1 Scope#

(a)Part 192 prescribes minimum safety requirements for pipeline facilities and the transportation of gas within the State of Arkansas. Requirements of the Arkansas Gas Pipeline Code shall take precedence over any other requirements pertaining to construction, operation, and maintenance of gas facilities under the jurisdiction of the Arkansas Public Service Commission.#

(b)This part does not apply to gathering of gas through a pipeline that operates at less than 0 p.s.i.g. (0kPa), and through a pipeline that is not a regulated onshore gathering line (as determined in §192.8); however, it shall apply to the gathering, transmission or distribution of gas containing 100 or more parts-per-million of hydrogen sulfide from the custodial transfer meter through any pipeline, rural or non-rural, to and through any pipeline facility that removes hydrogen sulfide, except that portion of such a pipeline or pipeline facility that is located within the fenced boundary of a petroleum refinery. § 192.3 Definitions As used in this part: Abandoned means permanently removed from service. Active Corrosion means continuing corrosion that, unless controlled, could result in a condition that is detrimental to public safety. Administrator means the Administrator of the Pipeline and Hazardous Materials Safety Administration or any person to whom authority in the matter concerned has been delegated by the U.S. Secretary of Transportation. Alarm means an audible or visible means of indicating to the controller that equipment or processes are outside operator-defined, safety-related parameters. Business District means a location where gas mains are utilized to serve customers that are predominately commercial in nature and where the street and/or sidewalk paving generally extends from the centerline of a thoroughfare to the established building line on either side. Change to a segment of pipeline means a physical change in the pipeline or significant changes in operating pressure. Commission means, unless the context otherwise requires, the Arkansas Public Service Commission or any person or entity to whom the Commission has delegated authority in the matter concerned. Close interval survey means a series of closely and properly spaced pipe-to-electrolyte potential measurements taken over the pipe to assess the adequacy of cathodic protection or to identify locations where a current may be leaving the pipeline that may cause corrosion and for the purpose of quantifying voltage#

(IR)drops other than those across the structure electrolyte boundary, such as when performed as a current interrupted, depolarized, or native survey. Composite Materials means materials used to make pipe or components manufactured with a combination of either steel or plastic, or both, and with a reinforcing material to maintain its circumferential or longitudinal strength. Control Room means an operations center staffed by personnel charged with the responsibility for remotely monitoring and controlling a pipeline facility. Controller means a qualified individual who remotely monitors and controls the safety-related operations of a pipeline facility via a SCADA system from a control room, and who has operational authority and accountability for the remote operational functions of the pipeline facility. Customer Meter means the meter that measures the transfer of gas from an operator to a consumer. Distribution center means the initial point where gas enters piping used primarily to deliver gas to customers who purchase it for consumption, as opposed to customers who purchase it for resale, for example:#

(1)At a metering location;#

(2)A pressure reduction location; or#

(3)Where there is a reduction in the volume of gas, such as a lateral off a transmission line. Distribution Line means a pipeline other than a gathering or transmission line. Dry gas or dry natural gas means gas above its dew point and without condensed liquids. Electrical Survey means a series of closely spaced pipe-to-soil readings over pipelines which are subsequently analyzed to identify locations where a corrosive current is leaving the pipeline. Engineering critical assessment#

(ECA)means a documented analytical procedure based on fracture mechanics principles, relevant material properties (mechanical and fracture resistance properties), operating history, operational environment, in-service degradation, possible failure mechanisms, initial and final defect sizes, and usage of future operating and maintenance procedures to determine the maximum tolerable sizes for imperfections based upon the pipeline segment maximum allowable operating pressure. Entirely replaced onshore transmission pipeline segments means, for the purposes of §§ 192.179 and 192.634, where 2 or more miles, in the aggregate, of onshore transmission pipeline have been replaced within any 5 contiguous miles of pipeline within an 24-month period. This definition does not apply to any gathering line. Gas means natural, manufactured, liquefied natural, flammable gas or gas which is toxic or corrosive. Gathering Line means a pipeline that transports gas from a current production facility to a transmission line or main. Hard spot means an area on steel pipe material with a minimum dimension greater than two inches (50.8 mm) in any direction and hardness greater than or equal to Rockwell 35 HRC (Brinell 327 HB or Vickers 345 HV10). High Pressure Distribution System means a distribution system in which the gas pressure in the main is higher than the pressure provided to the customer. Key Valves means shut off valves in a distribution system or transmission line which may be necessary to isolate segments of a system or line for emergency purposes. In-line inspection#

(ILI)means an inspection of a pipeline from the interior of the pipe using an inspection tool also called intelligent or smart pigging. This definition includes tethered and self- propelled inspection tools. In-line inspection tool or instrumented internal inspection device means an instrumented device or vehicle that uses a non-destructive testing technique to inspect the pipeline from the inside in order to identify and characterize flaws to analyze pipeline integrity; also known as an intelligent or smart pig. Line Section means a continuous run of transmission line between adjacent compressor stations, between a compressor station and storage facilities, between a compressor station and a block valve, or between adjacent block valves. Listed Specification means a specification listed in Section I of Appendix B to Part 192. Low-Pressure Distribution System means a distribution system in which the gas pressure in the main is substantially the same as the pressure provided to the customer. Main means a distribution line that serves as a common source of supply for more than one service line. Master Meter System means a pipeline system for distribution gas within, but not limited to, a definable area (such as a mobile home park, housing project, or apartment complex) where the operator purchases metered gas from an outside source for resale through a gas distribution pipeline system. The gas distribution pipeline system supplies the ultimate consumer who either purchases the gas directly through a meter or by other means, such as rents. Maximum Actual Operating Pressure means the maximum pressure that occurs during normal operations over a period of one year. Maximum Allowable Operating Pressure#

(MAOP)means the maximum pressure at which a pipeline or segment of a pipeline may be operated under this code. Mobile Home Park means two or more mobile homes located on a contiguous tract of land. Moderate consequence area means:#

(1)An onshore area that is within a potential impact circle, as defined in § 192.903, containing either:#

(i)Five or more buildings intended for human occupancy; or#

(ii)Any portion of the paved surface, including shoulders, of a designated interstate, other freeway, or expressway, as well as any other principal arterial roadway with 4 or more lanes, as defined in the Federal Highway Administration's Highway Functional Classification Concepts, Criteria and Procedures, Section 3.1 (see: https://www.fhwa.dot.gov/planning/processes/statewide/related/highway_functional _classifications/fcauab.pdf), and that does not meet the definition of high consequence area, as defined in § 192.903.#

(2)The length of the moderate consequence area extends axially along the length of the pipeline from the outermost edge of the first potential impact circle containing either 5 or more buildings intended for human occupancy; or any portion of the paved surface, including shoulders, of any designated interstate, freeway, or expressway, as well as any other principal arterial roadway with 4 or more lanes, to the outermost edge of the last contiguous potential impact circle that contains either 5 or more buildings intended for human occupancy, or any portion of the paved surface, including shoulders, of any designated interstate, freeway, or expressway, as well as any other principal arterial roadway with 4 or more lanes. Municipality means a city, county or any other political subdivision of the State of Arkansas. Notification of potential rupture means the notification to, or observation by, an operator of indicia identified in § 192.635 of a potential unintentional or uncontrolled release of a large volume of gas from a pipeline. This definition does not apply to any gathering line. Operator means a person who:#

(1)Engages in the transportation of gas; or#

(2)Operates a distribution system within a mobile home park, public housing authority, or multiple building complex if:#

(A)The system:#

(i)Is not owned, nor the responsibility of a public or municipal utility; and#

(ii)Is used to transport gas from a master meter or a public/municipal utility main to consumers who may or may not be metered; and#

(B)The gas distributed is not consumed solely by the owner/operator. Person means an individual, firm, joint venture, partnership, corporation, association, State, municipality, cooperative association, or joint stock association, and includes any trustee, receiver, assignee, or personal representative thereof. Petroleum Gas means propane, propylene, butane (normal butane or isobutanes), and butylene (including isomers), or mixtures composed predominantly of these gases, having a vapor pressure not exceeding 208 p.s.i.g. (1434 kPa) gage at 100°F (38°C). Petroleum Refinery means an industrial or manufacturing facility or plant primarily engaged in producing gasoline, kerosene, distillate fuel oils, residual fuel oils, lubricants or other products through the processing of petroleum crude oil that is subject to:#

(A)The federal Environmental Protection Agency Standards of Performance for New Stationary Sources set forth in Subpart GGG of 40 CFR part 60 or successor regulations;#

(B)The federal Environmental Protection Agency Chemical Accident Prevention Provisions set forth in Subparts, A, B, D, E, F, G, and H of 40 CFR Part 68 or successor regulations; and#

(C)The federal Occupational Safety and Health Administration Regulations governing process safety management of highly hazardous chemicals set forth in 29 CFR §1910.119 or successor regulations. Pipe means any pipe or tubing used in the transportation of gas, including pipe-type holders. Pipeline or Pipeline System means all parts of those physical facilities through which gas moves in transportation, including, but not limited to, pipe, valves and other appurtenances attached to pipe, compressor units, metering stations, regulator stations, delivery stations, holders, and fabricated assemblies. Pipeline Environment includes soil resistivity (high or low), soil moisture (wet or dry), soil contaminants that may promote corrosive activity, and other known conditions that could affect the probability of active corrosion. Pipeline Facilities includes without limitation, new and existing pipe, pipe rights-of-way, and any equipment, facility or building used in the transportation of gas or the treatment of gas during the course of transportation of gas. Private Line System means a natural gas pipeline or pipeline system that is not a master meter system; is not owned by, nor the responsibility of a public or municipal utility; is used to transport gas that is not consumed solely by the owner/operator from a public or municipal utility meter to consumers who may or may not be metered. Production Facilities includes without limitation, piping or equipment used in the production, extraction, recovery, lifting, stabilization, separation or treatment of natural gas or associated storage or measurement from the wellhead to a meter where the gas is transferred to a custodian other than the well operator for gathering or transport, commonly known as a "custodial transfer meter." Production Process means the extraction of gas from the geological source of supply to the surface of the earth, thence through the lines and equipment used to treat, compress and measure the gas between the wellhead and the meter where it is either sold or delivered to a custodian other than the well operator for gathering and transport to a place of sale, sometimes called "custodial transfer meter." Rupture-mitigation valve#

(RMV)means an automatic shut-off valve#

(ASV)or a remote-control valve#

(RCV)that a pipeline operator uses to minimize the volume of gas released from the pipeline and to mitigate the consequences of a rupture. This definition does not apply to any gathering line. Service Line means a distribution line that transports gas from a common source of supply to an individual customer, to two adjacent or adjoining residential or small commercial customers, or to multiple residential or small commercial customers served through a meter header or manifold. A service line ends at the outlet of the customer meter or at the connection to a piping, whichever is further downstream, or at the connection to customer piping if there is no meter. Service Regulator means the device on a service line that controls the pressure of gas delivered from a higher pressure to the pressure provided to the customer. A service regulator may serve one customer or multiple customers through a meter header or manifold. SMYS means specific minimum yield strength, and is:#

(1)For steel pipe manufactured in accordance with a listed specification, the yield strength specified as a minimum in that specification; or#

(2)For steel pipe manufactured in accordance with an unknown or unlisted specification, the yield strength determined in accordance with § 192.107(b). Supervisory Control and Data Acquisition#

(SCADA)System means a computer-based system or systems used by a controller in a control room that collects and displays information about a pipeline facility and may have the ability to send commands back to the pipeline facility. Test Failure means a break or rupture that occurs during strength proof testing of transmission or gathering lines that are of such magnitude as to require repair before continuation of the test. Transmission Line means a pipeline, other than a gathering line, that:#

(1)Transports gas from a gathering line or storage facility to a gas distribution center, storage facility or large volume customer that is not down-stream from a gas distribution center;#

(2)Operates at a hoop stress of 20 percent or more of SMYS;#

(3)Transports gas within a storage field; or#

(4)Is voluntarily designated by the operator as a transmission pipeline. NOTE: A large volume customer may receive similar volumes of gas as a distribution center, and includes factories, power plants, and institutional users of gas. Transportation of Gas means the gathering, transmission or distribution of gas by pipeline or the storage of gas in or affecting interstate, intrastate, or foreign commerce. Underground natural gas storage facility#

(UNGSF)means a gas pipeline facility that stores natural gas underground incidental to the transportation of natural gas, including:#

(1)#

(i)A depleted hydrocarbon reservoir;#

(ii)An aquifer reservoir; or#

(iii)A solution-mined salt cavern.#

(2)In addition to the reservoir or cavern, a UNGSF includes injection, withdrawal, monitoring, and observation wells; wellbores and downhole components; wellheads and associated wellhead piping; wing-valve assemblies that isolate the wellhead from connected piping beyond the wing-valve assemblies; and any other equipment, facility, right-of-way, or building used in the underground storage of natural gas. Welder means a person who performs manual or semi-automatic welding. Welding operator means a person who operates machine or automatic welding equipment. Weak link means a device or method used when pulling polyethylene pipe, typically through methods such as horizontal directional drilling, to ensure that damage will not occur to the pipeline by exceeding the maximum tensile stresses allowed. Wrinkle bend means a bend in the pipe that:#

(1)Was formed in the field during construction such that the inside radius of the bend has one or more ripples with:#

(i)An amplitude greater than or equal to 1.5 times the wall thickness of the pipe, measured from peak to valley of the ripple; or#

(ii)With ripples less than 1.5 times the wall thickness of the pipe and with a wrinkle length (peak to peak) to wrinkle height (peak to valley) ratio under 12.#

(2)#

(i)If the length of the wrinkle bend cannot be reliably determined, then wrinkle bend means a bend in the pipe where (h/D)*100 exceeds 2 when S is less than 37,000 psi (255 MPa), where (h/D)*100 exceeds (47000-S)/10,000 +1 for psi [(324-S)/69 +1 for MPa] when S is greater than 37,000 psi (255 MPa) but less than 47,000 psi (324 MPa), and where (h/D)*100 exceeds 1 when S is 47,000 psi (324 MPa) or more.#

(ii)Where:#

(A)D = Outside diameter of the pipe, in. (mm);#

(B)h = Crest-to-trough height of the ripple, in. (mm); and#

(C)S = Maximum operating hoop stress, psi (S/145, MPa). § 192.5 Class Locations#

(a)This section classifies pipeline locations for the purposes of this part. The following criteria apply to classifications under this section.#

(1)A "class location unit" is an area that extends 220 yards (200 meters) on either side of the centerline of any continuous 1-mile (1.6 kilometers) length of pipeline.#

(2)Each separate dwelling unit in a multiple dwelling unit building is counted as a separate building intended for human occupancy.#

(b)Except as provided in paragraph#

(c)of this section, pipeline locations are classified as follows:#

(1)A Class 1 location is any class location unit that has 10 or fewer buildings intended for human occupancy.#

(2)A Class 2 location is any class location unit that has more than 10 but fewer than 46 buildings intended for human occupancy.#

(3)A Class 3 location is:#

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

(ii)An area where the pipeline lies within 100 yards (91 meters) of either a building or a small, well-defined outside area (such as a playground, recreation area, outdoor theater, or other place of public assembly) that is occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12-month period. (The days and weeks need not be consecutive.)#

(4)A Class 4 location is any class location unit where buildings with four or more stories above ground are prevalent.#

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

(1)A Class 4 location ends 220 yards (200 meters) from the nearest building with four or more stories above ground.#

(2)When all buildings intended for human occupancy within a Class 2 or 3 location are in a single cluster, the class location ends 220 yards (200 meters) from the nearest building in the cluster.#

(d)An operator must have records that document the current class location of each gas transmission pipeline segment and that demonstrate how the operator determined each current class location in accordance with this section. § 192.7 What documents are incorporated by reference partly or wholly in this part?#

(a)Certain material is incorporated by reference into this part with the approval of the Director of the Federal Register under 5 U.S.C. 552(a) and 1 CFR part 51. All approved incorporation by reference#

(IBR)material is available for inspection at the Pipeline and Hazardous Materials Safety Administration#

(PHMSA)1200 New Jersey Avenue SE, Washington, DC 20590; 202-366-4046; https://www.phmsa.dot.gov/pipeline/regs and at the National Archives and Records Administration (NARA). Contact PHMSA at: Office of Pipeline Safety, Pipeline and Hazardous Material Safety Administration, 1200 New Jersey Avenue SE, Washington, DC 20590; 202-366-4046; www.phmsa.dot.gov/pipeline/regs. For information on the availability of this material at NARA, visit www.archives.gov/federal-register/cfr/ibr-locations.html or email fr.inspection@nara.gov. It is also available from the sources in the following paragraphs of this section#

(b)American Petroleum Institute (API), 200 Massachusetts Ave. NW, Suite 1100, Washington, DC 20001, and phone: 202-682-8000, website: https://www.api.org.#

(1)API Recommended Practice 5L1, "Recommend Practice for Railroad Transportation of Line Pipe," 7th edition, September 2009, (API RP 5L1), IBR approved for § 192.65(a).#

(2)API Recommended Practice 5LT, "Recommended Practice for Truck Transportation of Line Pipe," First edition, March 2012, (API RP 5LT), IBR approved for § 192.65(c).#

(3)API Recommended Practice 5LW, "Recommended Practice for Transportation of Line Pipe on Barges and Marine Vessels," 3rd edition, September 2009, (API RP 5LW), IBR approved for § 192.65(b).#

(4)API Recommended Practice 80, "Guidelines for the Definition of Onshore Gas Gathering Lines" 1st edition, April 2000, (API RP 80), IBR approved for § 192.8(a).#

(5)API Recommended Practice 1162, "Public Awareness Programs for Pipeline 1st edition, December 2003, (API RP 1162), IBR approved for § 192.616(a), (b), and (c).#

(6)API Recommended Practice 1165, Practice for Pipeline SCADA First edition, January 2007, (API RP 1165), IBR approved for § 192.631(c).#

(7)API Specification 5L, Line Pipe, 46th edition, April 2018, including Errata 1 (May 2018), (API Spec 5L); IBR approved for §§ 192.55(e); 192.112(a), (b), (c), (d), and (e); 192.113; appendix B to part 192.#

(8)API Specification 6D, Specification for Pipeline and Piping Valves, 24th edition, August 2014, including Errata 1 through 10 (October 2014 through July 2021), Addendum 1 (March 2015), and Addendum 2 (June 2016), (API Spec 6D); IBR approved for § 192.145(a).#

(9)API Standard 1104, Welding of Pipelines and Related Facilities, 21st edition, September 2013, including Errata 1 through 5 (April 2014 through September 2018), Addendum 1 (2014), and Addendum 2 (2016), (API Std 1104); IBR approved for §§ 192.225(a); 192.227(a); 192.229(b) and (c); 192.241(c); appendix B to part 192.#

(10)API Recommended Practice 1170, "Designa and Operation of Solution-mined Salt Caverns Used for Natural Gas Storage," First edition, July 2015 (API RP 1170), IBR approved for § 192.12.#

(11)API Recommended Practice 1171, "Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs," First edition, September 2015, (API RP 1171), IBR approved for § 192.12#

(c)American Society of Mechanical Engineers (ASME), Three Park Avenue, New York, NY 10016, 800- 843-2763; email: CustomerCare@asme.org; website: www.asme.org/.#

(1)(ASME/ANSI B16.1-2005, "Gray Iron Pipe Flanges and Flanged Fittings: (Classes 25, 125, and 250)," August 31, 2006, (ASME/ANSI B16.1), IBR approved for § 192.147(c).#

(2)ASME/ANSI B16.5-2003, "Pipe Flanges and Flanged Fittings," October 2004, (ASME/ANSI B16.5), IBR approved for §§ 192.147(a), 192.607(f).#

(3)ASME B16.40-2008, "Manually Operated Thermoplastic Gas Shutoffs and Valves in Gas Distribution Systems," March 18, 2008, approved by ANSI, (ASME B16.40- 2008), IBR approved for Item I, Appendix B to Part 192.#

(4)ASME/ANSI B31G-1991 (Reaffirmed 2004, "Manual for Determining the Remaining Strength of Corroded Pipelines," 2004, (ASME/ANSI B31G), IBR approved for §§ 192.485(c), 192.632(a), 192.712(b), and 192.933(a).#

(5)ASME B31.8-2018, Gas Transmission and Distribution Piping Systems, Issued November 20, 2018, (ASME B31.8); IBR approved for §§ 192.112(b); 192.619(a).#

(6)ASME/ANSI B31.8S-2004, "Supplement to B31.8 on Managing System Integrity of Gas Pipelines," approved January 14, 2005 (ASME/ANSI B31.8S-2004), IBR approved for §§ 192.714(d); 192.933(d).#

(7)ASME B31.8S-2018, Managing System Integrity of Gas Pipelines, Issued November 28, 2018, (ASME B31.8S); IBR approved for §§ 192.13(d); 192.714(c); 192.903 note to Potential impact radius; 192.907 introductory text and (b); 192.911 introductory text, (i), and#

(k)through (m); 192.913(a) through (c); 192.917(a) through (e); 192.921(a); 192.923(b); 192.925(b); 192.933(c); 192.935(b); 192.937(c); 192.939(a); 192.945(a).#

(8)ASME B36.10M-2018, Welded and Seamless Wrought Steel Pipe, Issued October 12, 2018, (ASME B36.10M); IBR approved for § 192.279.#

(9)ASME Boiler & Pressure Vessel Code, Section VIII, Division 2 "Rules, Rules for Construction of Pressure Vessels" 2007 edition, July 1, 2007, (ASME BPVC, Section VIII, Division 2), IBR approved for §§ 192.153(b), (d); and 192.165(b).#

(10)ASME Boiler & Pressure Vessel Code, Section IX: "Qualification Standard for Welding and Brazing Procedures, Welders, Brazers, and Welding and Brazing 2007 edition, July 1, 2007, ASME BPVC, Section IX, IBR approved for §§ 192.225(a); 192.227(a); and Item II, Appendix B to Part 192.#

(11)API Standard 1163, "In-Line Inspection Systems Qualification," Second edition, April 2013, Reaffirmed August 2018, (API STD 1163), IBR approved for § 192.493.#

(d)American Society for Nondestructive Testing (ASNT), P.O. Box 28518, 1711 Arlingate Lane, Columbus, OH 43228, phone: 800-222-2768, website: https://www.asnt.org/.#

(1)ANSI/ASNT ILI-PQ-2005 (2010), "In-line Inspection Personnel Qualification and Certification," Reapproved October 11, 2010, (ANSI/ASNT-PQ), IBR approved for § 192.493.#

(2)[Reserved]#

(e)ASTM International (ASTM), 100 Barr Harbor Drive, P.O. Box C700, West Conshohocken, PA 19428; phone:#

(610)832-9585; email: service@astm.org; website: www.astm.org.#

(1)ASTM A53/A53M-20, Standard Specification for Pipe, Steel, Black and Hot- Dipped, Zinc-Coated, Welded and Seamless, approved July 1, 2020, (ASTM A53/A53M); IBR approved for § 192.113; appendix B to part 192.#

(2)ASTM A106/A106M-19A, Standard Specification for Seamless Carbon Steel Pipe for High-Temperature Service, approved November 1, 2019, (ASTM A106/A106M); IBR approved for § 192.113; appendix B to part 192.#

(3)ASTM A333/A333M-18, Standard Specification for Seamless and Welded Steel Pipe for Low-Temperature Service and Other Applications with Required Notch Toughness, approved November 1, 2018, (ASTM A333/A333M); IBR approved for § 192.113; appendix B to part 192.#

(4)ASTM A372/A372M-10, "Standard Specification for Carbon and Alloy Steel Forgings for Thin-Walled Pressure Vessels," approved October 1, 2010, (ASTM A372/A372M), IBR approved for § 192.177(b).#

(5)ASTM A381/A381M-18, Standard Specification for Metal-Arc-Welded Carbon or High-Strength Low-Alloy Steel Pipe for Use with High-Pressure Transmission Systems, approved November 1, 2018, (ASTM A381); IBR approved for § 192.113; appendix B to part 192.#

(6)ASTM A578/A578M-96 (reapproved 2001), "Standard Specification for Straight- Beam Ultrasonic Examination of Plain and Clad Steel Plates for Special Applications," (ASTM A578/A578M), IBR approved for § 192.112(c).#

(7)ASTM A671/A671M-20, Standard Specification for Electric-Fusion-Welded Steel Pipe for Atmospheric and Lower Temperatures, approved March 1, 2020, (ASTM A671/A671M); IBR approved for § 192.113; appendix B to part 192.#

(8)ASTM A672/A672M 09, "Standard Specification for Electric- Fusion-Welded Steel Pipe for High-Pressure Service at Moderate Temperature," approved October 1, 2009, (ASTM A672/672M), IBR approved for § 192.113 and Item I, Appendix B to Part 192.#

(9)ASTM A691/A691M-19, Standard Specification for Carbon and Alloy Steel Pipe, Electric-Fusion-Welded for High-Pressure Service at High Temperatures, approved November 1, 2019, (ASTM A691/A691M); IBR approved for § 192.113; appendix B to part 192.#

(10)ASTM D638-03, "Standard Test Method for Tensile Properties of Plastics," 2003, (ASTM D638), IBR approved for § 192.283(a) and (b).#

(11)ASTM D2513-18a, "Standard Specification for Polyethylene#

(PE)Gas Pressure Pipe, Tubing, and Fittings," approved August 1, 2018, (ASTM D2513), IBR approved for Item I, Appendix B to Part 192.#

(12)ASTM D2517-00, "Standard Specification for Reinforced Epoxy Resin Gas Pressure Pipe and Fittings," (ASTM D 2517), IBR approved for §§ 192.191(a); 192.281(d); 192.283(a); and Item I, Appendix B to Part 192.#

(13)ASTM D2564-12, "Standard Specification for Solvent Cements for Poly (Vinyl Chloride)(PVC) Plastic Piping Systems," August 1, 2012, (ASTM D2564- 12), IBR approved for §192.281(b)(2).#

(14)ASTM F1055- 98 (Reapproved 2006), "Standard Specification for Electrofusion Type Polyethylene Fittings for Outside Diameter Controlled Polyethylene Pipe and Tubing," March 1, 2006, (ASTM F1055-98 (2006)), IBR approved for § 192.283(a), Item I, Appendix B to Part 192.#

(15)ASTM F1055-98 (Reapproved 2006), "Standard Specification for Electrofusion Type Polyethylene Fittings for Outside Diameter Controlled Polyethylene Pipe and Tubing," March 1,2006, ASTM F1055-98 (2006)), IBR approved for §192.283(a), Item I Appendix B to Part 192 ASTM F1924-12), "Standard Specification for Plastic Mechanical Fittings for Use on Outside Diameter Controlled Polyethylene Gas Distribution Pipe and Tubing, " April 1, 2012 (ASTM F1924-12), IBR approved for Item 1 Appendix B to Part 192.#

(16)ASTM F1948-12, (Standard Specification for Metallic Mechanical Fittings for Use on Outside Diameter Controlled Thermoplastic Gas Distribution Pipe and Tubing," April 1, 2012, (ASTM F1948-12), IBR approved for Item I, Appendix B to Part 192.#

(17)ASTM F1973-13, "Standard Specification for Factory Assembled Anodeless Risers and Transition Fittings in Polyethylene#

(PE)and Polyamide 11#

(PA11)and Polyamide 12#

(PA12)Fuel Gas Distribution Systems," May 1, 2013, (ASTM F1973- 13), IBR approved for §192.204(b); and Item I, Appendix B to Part 192.#

(18)ASTM F2145-13, 'Standard Specification for Polyamide 11#

(PA11)and Polyamide 12#

(PA12)Mechanical Fittings for Use on Outside Diameter Controlled Polyamide 11 and Polyamide 12 Pipe and Tubing," May 1, 2013, (ASTM F2145-13), IBR approved for Item 1, Appendix B to Part 192.#

(19)ASTM F2600-09, "Standard Specification for Electrofusion Type Polyamide-11 Fittings for Outside Diameter Controlled Polyamide-11 Pipe an Tubing," April 1, 2009, (ASTM F 2600-09) IBR approved for Item I, Appendix B to Part 192.#

(20)ASTM F2620-19,"Standard Practice for Heat Fusion Joining of Polyethylene Pipe and Fittings," approved February 1, 2019, (ASTM F2620), IBR approved for §§192.281(c) and 192.285(b).#

(21)ASTM 2767-12, "Specification for Electrofusion Type Polyamide-12 Fittings for Outside Diameter Controlled Polyamide-12 Pipe and Tubing for Gas Distribution." Oct 15, 2012, (ASTM F2767-12), IBR approved for Item I, Appendix B to Part 192.#

(22)ASTM F2785-12, "Standard Specification for Polyamide 12 Gas Pressure Pipe, Tubing and Fittings," Aug. 1 2012, (ASTM F2785-12), IBR approved for Item 1, Appendix B to Part 192.#

(23)ASTM F2817-10, "Standard Specification for Poly (Vinyl Chloride)#

(PVC)Gas Pressure Pipe and Fittings for Maintenance or Repair," Feb. 1, 2010 (ASTM F2817-10), IBR approved for Item 1, Appendix B to Pat 192.#

(24)ASTM F2945-12a "Standard Specification for Polyamide 11 Gas Pressure Pipe, Tubing and Fittings," Nov 27, 2012 (ASTM F2945-12a), IBR approved for Item I, Appendix B to Part 192.#

(f)[Reserved]#

(g)Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS), 127 Park St. NE., Vienna, VA 22180, phone: 703-281-6613, email: info@msshq.org; website: http://www.msshq.org/.#

(1)ANSI/MSS SP-44-2019, Steel Pipeline Flanges, published April 2020, (MSS SP- 44); IBR approved for § 192.147(a).#

(2)[Reserved]#

(h)NACE International (NACE), 1440 South Creek Drive, Houston, TX 77084: phone: 281-228- 6223 or 800-797-6223 Web site: http://www.nace.org/Publications/.#

(1)NACE Standard Practice 0102-2010 "In-Line Inspection of Pipelines," Revised 2010-03-13, (NACE SP0102), IBR approved for §§ 192.150(a) and 192.493.#

(2)NACE SP0204-2008, Standard Practice, "Stress Corrosion Cracking#

(SCC)Direct Assessment Methodology," reaffirmed September 18, 2008, (NACE SP0204); IBR approved for §§ 192.923(b); 192.929(b) introductory text,#

(b)(1)through (3),#

(b)(5)introductory text, and (b)(5)(i).#

(3)NACE SP0206-2006, Standard Practice, "Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas (DG-ICDA)," approved December 1, 2006, (NACE SP0206), IBR approved for §§ 192.923(b); 192.927(b),#

(c)introductory text, and#

(c)(1)through (4).#

(4)ANSI/NACE SP0502-2010, Standard Practice, "Pipeline External Corrosion Direct Assessment revised June 24, 2010, (NACE SP0502), IBR approved for §§ 192.923(b); 192.925(b); 192.931(d); 192.935(b) and 192.939(a).#

(i)National Fire Protection Association (NFPA), 1 Batterymarch Park, Quincy, Massachusetts 02169, phone:#

(617)984-7275; website: www.nfpa.org.#

(1)NFPA-30 (2012), "Flammable and Combustible Liquids Code," 2012 edition, June 20, 2011, including Errata 30-12-1 (September 27, 2011) and Errata 30-12-2 (November 14, 2011), (NFPA-30), IBR approved for § 192.735(b).#

(2)NFPA 58, Liquefied Petroleum Gas Code, 2020 edition, effective August 25, 2019, (NFPA 58); IBR approved for § 192.11.#

(3)NFPA 59, Utility LP-Gas Plant Code, 2018 edition, effective September 6, 2017, (NFPA 59); IBR approved for § 192.11.#

(4)NFPA 70, National Electrical Code (NEC), 2017 edition, effective August 24, 2016, (NFPA 70); IBR approved for §§ 192.163(e); 192.189(c).#

(j)Pipeline Research Council International, Inc. (PRCI), c/o Technical Toolboxes, 3801 Kirby Drive, Suite 520, P.O. Box 980550, Houston, TX 77098, phone: 713-630-0505, toll free: 866-866-6766, Web site: http://www.ttoolboxes.com/. (Contract number PR3-805.)#

(1)AGA, Pipeline Research Committee Project, PR-3-805, "A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe," (December 22, 1989), (PRCI PR-3-805 (R-STRENG)), IBR approved for §§ 192.485(c); 192.632(a); 192.712(b); 192.933(a) and (d).#

(2)[Reserved]#

(k)Plastics Pipe Institute, Inc. (PPI),105 Decker Court, Suite 825 Irving TX 75062, phone: 469-499-1044, http://www.plasticpipe.org/.#

(1)PPI TR-3/2012,HDB/HDS/PDB/SDB/MRS/CRS, Policies, "Policies and Procedures for Developing Hydrostatic Design Basis (HDB), Hydrostatic Design Stresses (HDS), Pressure Design Basis (PDB), Strength Design Basis (SDB), Minimum Required Strength#

(MRS)Ratings, and Categorized Required Strength#

(CRS)for Thermoplastic Piping Materials or Pipe," updated November 2012, (PPI TR-3/2012), IBR approved for §192.121.#

(2)PPI TR-4, HDB/HDS/SDB/MRS, Listed Materials, "PPI Listing of Hydrostatic Design Basis (HDB), Hydrostatic Design Stress (HDS), Strength Design Basis (SDB), Pressure Design Basis#

(PDB)and Minimum Required Strength#

(MRS)Rating For Thermoplastic Piping Materials or Pipe," updated March 2011, (PPI TR- 4/2012), IBR approved for § 192.121. § 192.8 How are onshore gathering lines and regulated onshore gathering lines determined?#

(a)An operator must use API RP 80 (incorporated by reference, see § 192.7), to determine if an onshore pipeline (or part of a connected series of pipelines) is an onshore gathering line. The determination is subject to the limitations listed below. After making this determination, an operator must determine if the onshore gathering line is a regulated onshore gathering line under paragraph#

(b)of this section.#

(1)The beginning of gathering, under section 2.2(a)(1) of API RP 80, may not extend beyond the furthermost downstream point in a production operation as defined in section 2.3 of API RP 80. This furthermost downstream point does not include equipment that can be used in either production or transportation, such as separators or dehydrators, unless that equipment is involved in the processes of "production and preparation for transportation or delivery of hydrocarbon gas" within the meaning of "production operation."#

(2)The endpoint of gathering, under section 2.2(a)(1)(A) of API RP 80, may not extend beyond the first downstream natural gas processing plant, unless the operator can demonstrate, using sound engineering principles, that gathering extends to a further downstream plant.#

(3)If the endpoint of gathering, under section 2.2(a)(1)(C) of API RP 80, is determined by the commingling of gas from separate production fields, the fields may not be more than 50 miles from each other, unless the Administrator finds a longer separation distance is justified in a particular case (see 49 CFR § 190.9).#

(4)The endpoint of gathering, under section 2.2(a)(1)(D) of API RP 80, may not extend beyond the furthermost downstream compressor used to increase gathering line pressure for delivery to another pipeline.#

(5)For new, replaced, relocated, or otherwise changed gas gathering pipelines installed after May 16, 2022, the endpoint of gathering under sections 2.2(a)(1)(E) and 2.2.1.2.6 of API RP 80 (incorporated by reference, see § 192.7) - also known as "incidental gathering" - may not be used if the pipeline terminates 10 or more miles downstream from the furthermost downstream endpoint as defined in paragraphs 2.2(a)(1)(A) through (a)(1)(D) of API RP 80 (incorporated by reference, see § 192.7) and this section. If an "incidental gathering" pipeline is 10 miles or more in length, the entire portion of the pipeline that is designated as an incidental gathering line under 2.2(a)(1)(E) and 2.2.1.2.6 of API RP 80 shall be classified as a transmission pipeline subject to all applicable regulations in this chapter for transmission pipelines.#

(b)Each operator must determine and maintain for the life of the pipeline records documenting the methodology by which it calculated the beginning and end points of each onshore gathering pipeline it operates, as described in the second column of table 1 to paragraph#

(c)(2)of this section, by:#

(1)November 16, 2022, or before the pipeline is placed into operation, whichever is later; or#

(2)An alternative deadline approved by the Pipeline and Hazardous Materials Safety Administration (PHMSA). The operator must notify PHMSA and State or local pipeline safety authorities, as applicable, no later than 90 days in advance of the deadline in paragraph#

(b)(1)of this section. The notification must be made in accordance with § 192.18 and must include the following information: i. Description of the affected facilities and operating environment; ii. Justification for an alternative compliance deadline; and iii. Proposed alternative deadline.#

(c)For purposes of part 191 of this chapter and § 192.9, the term "regulated onshore gathering pipeline" means:#

(1)Each Type A, Type B, or Type C onshore gathering pipeline (or segment of onshore gathering pipeline) with a feature described in the second column of table 1to paragraph#

(c)(2)of this section that lies in an area described in the third column; and#

(2)As applicable, additional lengths of pipeline described in the fourth column to provide a safety buffer: Table 1 to Paragraph#

(c)(2)Type Feature Area Additional Safety Buffer -Metallic and the MAOP produces a hoop stress of 20 percent or more of SMYS A -If the stress level is unknown, an operator must determine the stress level according to the applicable provisions in subpart C of this part Class 2, 3, or 4 location (see § 192.5) None. -Non-metallic and the MAOP is more than 125 psig (862 kPa) -Metallic and the MAOP produces a hoop stress of less than 20 percent of SMYS. If the stress level is unknown, an operator must determine the stress level according to the applicable provisions in subpart C of this part B -Non-metallic and the MAOP is 125 psig (862 kPa) or less Area 1. Class 3 or 4 location. Area 2. An area within a Class 2 location the operator determines by using any of the following three methods:#

(a)A Class 2 location;#

(b)An area extending 150 feet (45.7 m) on each side of the centerline of any continuous 1 mile (1.6 km) of pipeline and including more than 10 but If the gathering pipeline is in Area 2(b) or 2(c), the additional lengths of line extend upstream and downstream from the area to a point were the line is at least 150 feet (45.7 m) from the nearest dwelling in the area. However, if a cluster of dwellings in Area 2(b) or 2(c) qualifies a pipeline as Type B, the Type B classification ends 150 feet (45.7m) from the nearest dwelling in the cluster. fewer than 46 dwellings; or#

(c)An area extending 150 feet (45.7 m) on each side of the centerline of any continuous 1000 feet (305 m) of pipeline and including 5 or more dwellings C Outside diameter greater than or equal to 8.625 inches and any of the following: -Metallic and the MAOP produces a hoop stress of 20 percent or more of SMYS; -If the stress level is unknown, segment is metallic and the MAOP is more than 125 psig (862 kPa); or -Non-metallic and the MAOP is more than 125 psig (862 kPa) Class 1 location None. R -All other onshore gathering lines Class 1 and Class 2 locations None.#

(3)A Type R gathering line is subject to reporting requirements under part 191 of this chapter but is not a regulated onshore gathering line under this part.#

(4)For the purpose of identifying Type C lines in table 1 to paragraph#

(c)(2)of this section, if an operator has not calculated MAOP consistent with the methods at § 192.619(a) or (c)(1), the operator must either:#

(i)Calculate MAOP consistent with the methods at § 192.619(a) or (c)(1); or#

(ii)Use as a substitute for MAOP the highest operating pressure to which the segment was subjected during the preceding 5 operating years. § 192.9 What requirements apply to gathering lines?#

(a)Requirements. An operator of a gathering line must follow the safety requirements of this part as prescribed by this section.#

(b)Offshore lines. An operator of an offshore gathering line must comply with requirements of this part applicable to transmission lines, except the requirements in §§ 192.13(d),192.150, 192.285(e), 192.319(d) through (g), 192.461(f) through (i), 192.465(d) and (f), 192.473(c), 192.478, 192.465(d),192.485(c),192.493, 192.506, 192.607, 192.613(c), 192.619(e), 192.624, 192.710, 192.712, and 192.714 and in subpart O of this part.#

(c)Type A lines. An operator of a Type A regulated onshore gathering line must comply with the requirements of this part applicable to transmission lines, except the requirements in §§192.13(d), 192.150, 192.285(e), 192.319(d) through (g), 192.461(f) through (i), 192.465(d) and (f), 192.473(c), 192.478, 192.485(c), 192.493, 192.506, 192.607, 192.613(c),192.619(e), 192.624, 192.710, 192.712, and 192.714 and in subpart O of this part. However, operators of a Type A regulated onshore gathering line in a Class 2 location may demonstrate compliance with subpart N by describing the processes it uses to determine the qualification of persons performing operations and maintenance tasks. Further, operators of Type A regulated onshore gathering lines are exempt from the requirements of §§ 192.179(e) through (g), 192.610, 192.617(b) through (d), 192.634, 192.635, 192.636, and 192.745(c) through (f). Lastly, operators of Type A regulated onshore gathering lines are exempt from the requirements of § 192.615 (but an operator of a Type A regulated onshore gathering line must comply with the requirements of 49 CFR 192.615, effective as of October 4, 2022).#

(d)Type B lines. An operator of a Type B regulated onshore gathering line must comply with the following requirements:#

(1)If a line is new, replaced, relocated, or otherwise changed, the design, installation, construction, initial inspection, and initial testing must be in accordance with requirements of this part applicable to transmission lines, compliance with §§ 192.67, 192.127, 192.179(e) and (f)192.205, 192.227(c), 192.285(e), 192.319(d) through (g), 192.506, 192.634, and 192.636 is not required.;#

(2)If the pipeline is metallic, control corrosion according to requirements of subpart I of this part applicable to transmission lines except the requirements in §§192.461(f) through (i), 192.465(d) and (f), 192.473(c), 192.478, 192.485(c), and 192.493;#

(3)If the pipeline contains plastic pipe or components, the operator must comply with all applicable requirements of this part for plastic pipe components;#

(4)Carry out a damage prevention program under § 192.614;#

(5)Establish a public education program under § 192.616;#

(6)Establish the MAOP of the line under § 192.619(a), (b), and (c);#

(7)Install and maintain line markers according to the requirements for transmission lines in § 192.707; and#

(8)Conduct leakage surveys in accordance with the requirements for transmission lines in § 192.706 using leak detection equipment and promptly repair hazardous leaks in accordance with § 192.703(c).#

(e)Type C lines. The requirements for Type C gathering lines are as follows:#

(1)An operator of a Type C onshore gathering line with an outside diameter greater than or equal to 8.625 inches must comply with the following requirements:#

(i)Except as provided in paragraph#

(h)of this section for pipe and components made with composite materials, the design, installation, construction, initial inspection, and initial testing of a new, replaced, relocated, or otherwise changed Type C gathering line, must be done in accordance with the requirements in subparts B through G and J of this part applicable to transmission lines. Compliance with §§ 192.67, 192.127, 192.179(e) and (f), 192.205, 192.227(c), 192.285(e), 192.319(d) through (g),and 192.506, 192.634, and 192.636 is not required.#

(ii)If the pipeline is metallic, control corrosion according to requirements of subpart I of this part applicable to transmission lines except for §§192.461(f) through (i), 192.465(d) and (f), 192.473(c), 192.478, 192.485(c), and 192.493;#

(iii)Carry out a damage prevention program under § 192.614;#

(iv)Develop and implement procedures for emergency plans in accordance with § 192.615, effective as of October 4, 2022;#

(v)Develop and implement a written public awareness program in accordance with 192.616;#

(vi)Install and maintain line markers according to the requirements for transmission lines in §192.707; and#

(vii)Conduct leakage surveys in accordance with the requirements for transmission lines in § 192.706 using leak-detection equipment, and promptly repair hazardous leaks in accordance with § 192.703(c).#

(2)An operator of a Type C onshore gathering line with outside diameter greater than 12.75 inches must comply with the requirements paragraph#

(e)(1)of this section and the following:#

(i)If the pipeline contains plastic pipe, the operator must comply with all applicable requirements of this part for plastic pipe or components. This does not include pipe and components made of composite materials that incorporate plastic in the design; and#

(ii)Establish the MAOP of the pipeline under § 192.619(a) or#

(c)and maintain records used to establish the MAOP for the life of the pipeline.#

(f)Exceptions.#

(1)Compliance with paragraphs (e)(1)(ii), (v), (vi), and#

(vii)and (e)(2)(i) and#

(ii)of this section is not required for pipeline sements that are 16 inches or less in outside diameter if one of the following criteria are met:#

(i)Method 1. The segment is not located within a potential impact circle containing a building intended for human occupancy or other impacted site. The potential impact circle must be calculated as specified in § 192.903, except that a factor of 0.73 must be used instead of 0.69. The MAOP used in this calculation must be determined and documented in accordance with paragraph (e)(2)(ii) of this section.#

(ii)Method 2. The segment is not located within a class location unit (see § 192.5) containing a building intended for human occupancy or other impacted site.#

(2)Paragraph (e)(1)(i) of this section is not applicable to pipeline segments 40 feet or shorter in length that are replaced, relocated, or changed on a pipeline existing on or before May 16, 2022.#

(3)For purposes of this section, the term "building intended for human occupancy or other impacted site" means any of the following:#

(i)Any building that may be occupied by humans, including homes, office buildings, factories,outside recreation areas, plant facilities, etc.;#

(ii)A small, well-defined outside area (such as a playground, recreation area, outdoor theater, or other place of public assembly) that is occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12 month period (the days and weeks need not be consecutive); or#

(iii)Any portion of the paved surface, including shoulders, of a designated interstate, other freeway, or expressway, as well as any other principal arterial roadway with 4 or more lanes.#

(g)Compliance deadlines. An operator of a regulated onshore gathering line must comply with the following deadlines, as applicable.#

(3)An operator of a new, replaced, relocated, or otherwise changed line must be in compliance with the applicable requirements of this section by the date the line goes into service, unless an exception in § 192.13 applies.#

(4)If a Type A or Type B regulated onshore gathering line existing on April 14, 2006 was not previously subject to this part, an operator has until the date stated in the second column to comply with the applicable requirement for the line listed in the first column, unless the Administrator finds a later deadline is justified in a particular case: Requirement Compliance deadline#

(i)Control corrosion according to requirements for transmission lines in subpart I of this part April 15, 2009#

(ii)Carry out a damage prevention program under § 192.614 October 15, 2007#

(iii)Establish MAOP under § 192.619 October 15, 2007#

(iv)Install and maintain line markers under § 192.707 April 15, 2008#

(v)Establish a public education program under § 192.616 April 15, 2008#

(vi)Other provisions of this part as required by paragraph#

(c)of this section for Type A lines April 15, 2009#

(3)If, after April 14, 2006, a change in class location or increase in dwelling density causes an onshore gathering line to be a regulated onshore gathering line, the operator has 1 year for Type B lines and 2 years for Type A lines after the line becomes a regulated onshore gathering line to comply with this section.#

(4)If a Type C gathering pipeline existing on or before May 16, 2022, was not previously subject to this part, an operator must comply with the applicable requirements of this section, except for paragraph#

(h)of this section, on or before:#

(i)May 16, 2023; or#

(ii)An alternative deadline approved by PHMSA. The operator must notify PHMSA and State or local pipeline safety authorities, as applicable, not later than 90 days in advance of the deadline in paragraph#

(b)(1)of this section. The notification must be made in accordance with § 192.18 and must include a description of the affected facilities and operating environment, the proposed alterative deadline for each affected requirement, the justification for each alternative compliance deadline, and actions the operator will take to ensure the safety of affected facilities.#

(5)If, after May 16, 2022, a change in class location, an increase in dwelling density, or an increase in MAOP causes a pipeline to become a Type C gathering pipeline, or causes a Type C gathering pipeline to become subject to additional Type C requirements (see paragraph#

(f)of this section), the operator has 1 year after the pipeline becomes subject to the additional requirements to comply with this section.#

(h)Composite Materials. Pipe and components made with composite materials not otherwise authorized for use under this part may be used on Type C gathering pipelines if the following requirements are met:#

(1)Steel and plastic pipe and components must mee the installation, construction, initial inspection, and initial testing requirements in subparts B through G and J of this part applicable to transmission lines.#

(2)Operators must notify PHMSA in accordance with § 192.18 at least 90 days prior to installing new or replacement pipe or components made of composite materials otherwise not authorized for use under this part in a Type C gathering pipeline. The notifications required by this section must include a detailed description of the pipeline facilities in which pipe or components made of composite materials would be used, including:#

(i)The beginning and end points (stationing by footage and mileage with latitude and longitude coordinates) of the pipeline segment containing composite pipeline material and the counties and States in which it is located;#

(ii)A general description of the right-of-way including high consequence areas, as defined in § 192.905;#

(iii)Relevant pipeline design and construction information including the year of installation, the specific composite material, diameter, wall thickness, and any manufacturing and construction specifications for the pipeline;#

(iv)Relevant operating information, including MAOP, leak and failure history, and the most recent pressure test (identification of the actual pipe tested, minimum and maximum test pressure, duration of test, any leaks and any test logs and charts) or assessment results;#

(v)An explanation of the circumstances that the operator believes make the use of composite pipeline material appropriate and how the design, construction, operations, and maintenance will mitigate safety and environmental risks;#

(vi)An explanation of procedures and tests that will be conducted periodically over the life of the composite pipeline material to document that its strength is being maintained;#

(vii)Operations and maintenance procedures that will be applied to the alternative materials. These include procedures that will be used to evaluate and remediate anomalies and how the operator will determine safe operating pressures for composite pipe when defects are found;#

(viii)An explanation of how the use of composite pipeline material would be in the public interest; and#

(ix)A certification signed by a vice president (or equivalent or higher officer) of the operator's company that operation of the applicant's pipeline using composite pipeline material would be consistent with pipeline safety.#

(3)Repairs or replacements using materials authorized under this part do not require notification under this section. §192.12 Underground natural gas storage facilities Underground natural gas storage facilities ("UNGSFs"), as defined in §192.3, are not subject to any requirements of this part aside from this section.#

(a)Salt cavern UNGSFs.#

(1)Each UNGSF that uses a solution-mined salt cavern for natural gas storage and was constructed after March 13, 2020, must meet all the provisions of API RP 1170 (incorporated by reference, see § 192.7), the provisions of section 8 of API RP 1171 (incorporated by reference, see § 192.7) that are applicable to the physical characteristics and operations of a solution-mined salt cavern UNGSF, and paragraphs#

(c)and#

(d)of this section prior to commencing operations.#

(2)Each UNGSF that uses a solution-mined salt cavern for natural gas storage and was constructed between July 18, 2017, and March 13, 2020, must meet all the provisions of API RP 1170 (incorporated by reference, see § 192.7) and paragraph#

(c)of this section prior to commencing operations, and must meet all the provisions of section 8 of API RP 1171 (incorporated by reference, see § 192.7) that are applicable to the physical characteristics and operations of a solution-mined salt cavern UNGSF, and paragraph#

(d)of this section, by March 13, 2021.#

(3)Each UNGSF that uses a solution-mined salt cavern for natural gas storage and was constructed on or before July 18, 2017, must meet the provisions of API RP 1170 (incorporated by reference, see § 192.7), sections 9, 10, and 11, and paragraph#

(c)of this section, by January 18, 2018, and must meet all provisions of section 8 of API RP 1171 (incorporated by reference, see § 192.7) that are applicable to the physical characteristics and operations of a solution-mined salt cavern UNGSF, and paragraph#

(d)of this section, by March 13, 2021.#

(b)Depleted hydrocarbon and aquifer reservoir UNGSFs.#

(1)Each UNGSF that uses a depleted hydrocarbon reservoir or an aquifer reservoir for natural gas storage and was constructed after July 18, 2017, must meet all provisions of API RP 1171 (incorporated by reference, see § 192.7), and paragraphs#

(c)and#

(d)of this section, prior to commencing operations.#

(2)Each UNGSF that uses a depleted hydrocarbon reservoir or an aquifer reservoir for natural gas storage and was constructed on or before July 18, 2017, must meet the provisions of API RP 1171 (incorporated by reference, see § 192.7), sections 8, 9, 10, and 11, and paragraph#

(c)of this section, by January 18, 2018, and must meet all provisions of paragraph#

(d)of this section by March 13, 2021.#

(c)Procedural manuals. Each operator of a UNGSF must prepare and follow for each facility one or more manuals of written procedures for conducting operations, maintenance, and emergency preparedness and response activities under paragraphs#

(a)and#

(b)of this section. Each operator must keep records necessary to administer such procedures and review and update these manuals at intervals not exceeding 15 months, but at least once each calendar year. Each operator must keep the appropriate parts of these manuals accessible at locations where UNGSF work is being performed. Each operator must have written procedures in place before commencing operations or beginning an activity not yet implemented.#

(d)Integrity management program-#

(1)Integrity management program elements. The integrity management program for each UNGSF under this paragraph#

(d)must consist, at a minimum, of a framework developed under API RP 1171 (incorporated by reference, see § 192.7), section 8 ("Risk Management for Gas Storage Operations"), and that also describes how relevant decisions will be made and by whom. An operator must make continual improvements to the program and its execution. The integrity management program must include the following elements:#

(i)A plan for developing and implementing each program element to meet the requirements of this section;#

(ii)An outline of the procedures to be developed;#

(iii)The roles and responsibilities of UNGSF staff assigned to develop and implement the procedures required by this paragraph (d);#

(iv)A plan for how staff will be trained in awareness and application of the procedures required by this paragraph (d);#

(v)Timelines for implementing each program element, including the risk analysis and baseline risk assessments; and#

(vi)A plan for how to incorporate information gained from experience into the integrity management program on a continuous basis.#

(2)Integrity management baseline risk-assessment intervals. No later than March 13, 2024, each UNGSF operator must complete the baseline risk assessments of all reservoirs and caverns, and at least 40% of the baseline risk assessments for each of its UNGSF wells (including wellhead assemblies), beginning with the highest- risk wells, as identified by the risk analysis process. No later than March 13, 2027, an operator must complete baseline risk assessments on all its wells (including wellhead assemblies). Operators may use prior risk assessments for a well as a baseline (or part of the baseline) risk assessment in implementing its initial integrity management program, so long as the prior assessments meet the requirements of API RP 1171 (incorporated by reference, see § 192.7), section 8, and continue to be relevant and valid for the current operating and environmental conditions. When evaluating prior risk-assessment results, operators must account for the growth and effects of indicated defects since the time the assessment was performed.#

(3)Integrity management re-assessment intervals. The operator must determine the appropriate interval for risk assessments under API RP 1171 (incorporated by reference, see § 192.7), subsection 8.7.1, and this paragraph#

(d)for each reservoir, cavern, and well, using the results from earlier assessments and updated risk analyses. The re-assessment interval for each reservoir, cavern, and well must not exceed seven years from the date of the baseline assessment for each reservoir, cavern, and well.#

(4)Integrity management procedures and recordkeeping. Each UNGSF operator must establish and follow written procedures to carry out its integrity management program under API RP 1171 (incorporated by reference, see § 192.7), section 8 ("Risk Management for Gas Storage Operations"), and this paragraph (d). The operator must also maintain, for the useful life of the UNGSF, records that demonstrate compliance with the requirements of this paragraph (d). This includes records developed and used in support of any identification, calculation, amendment, modification, justification, deviation, and determination made, and any action taken to implement and evaluate any integrity management program element. § 192.13 What general requirements apply to pipelines regulated under this part?#

(a)No person may operate a segment of pipeline listed in the first column of paragraph#

(a)(3)of this section that is readied for service after the date in the second column, unless:#

(1)The pipeline has been designed, installed, constructed, initially inspected, and initially tested in accordance with this part; or#

(2)The pipeline qualifies for use under this part according to the requirements in § 192.14.#

(3)The compliance deadlines are as follows: Pipeline Date#

(i)Offshore gathering pipeline July 31, 1977#

(ii)Regulated onshore gathering pipeline to which this part did March 15, 2007 not apply until April 14, 2006#

(iii)Regulated onshore gathering pipeline to which this part did May 16, 2023 not apply until May 16, 2022#

(iv)All other pipelines March 12, 1971#

(b)No person may operate a segment of pipeline listed in the first column of this paragraph#

(b)that is replaced, relocated, or otherwise changed after the date in the second column of this paragraph (b), unless the replacement, relocation or change has been made according to the requirements in this part. Pipeline Date#

(1)Offshore gathering pipeline July 31, 1977#

(2)Regulated onshore gathering pipeline to which this part did March 15, 2007 not apply until April 14, 2006#

(3)Regulated onshore gathering pipeline to which this part did May 16, 2023 not apply until May 16, 2022#

(4)All other pipelines November 12, 1970#

(c)Each operator shall maintain, modify as appropriate, and follow the plans, procedures, and programs that it is required to establish under this part.#

(d)Each operator of an onshore gas transmission pipeline must evaluate and mitigate, as necessary, significant changes that pose a risk to safety or the environment through a management of change process. Each operator of an onshore gas transmission pipeline must develop and follow a management of change process, as outlined in ASME B31.8S, section 11 (incorporated by reference, see § 192.7), that addresses technical, design, physical, environmental, procedural, operational, maintenance, and organizational changes to the pipeline or processes, whether permanent or temporary. A management of change process must include the following: reason for change, authority for approving changes, analysis of implications, acquisition of required work permits, documentation, communication of change to affected parties, time limitations, and qualification of staff. For pipeline segments other than those covered in subpart O of this part, this management of change process must be implemented by February 26, 2024. The requirements of this paragraph#

(d)do not apply to gas gathering pipelines. Operators may request an extension of up to 1 year by submitting a notification to PHMSA at least 90 days before February 26, 2024, in accordance with § 192.18. The notification must include a reasonable and technically justified basis, an up-to-date plan for completing all actions required by this section, the reason for the requested extension, current safety or mitigation status of the pipeline segment, the proposed completion date, and any needed temporary safety measures to mitigate the impact on safety. § 192.14 Conversion to Service Subject to this Part#

(a)A steel pipeline previously used in service not subject to this part qualifies for use under this part if the operator prepares and follows a written procedure to carry out the following requirements:#

(1)The design, construction, operation, and maintenance history of the pipeline must be reviewed and, where sufficient historical records are not available, appropriate tests must be performed to determine if the pipeline is in a satisfactory condition for safe operation.#

(2)The pipeline right-of-way, all above-ground segments of the pipeline, and appropriately selected underground segments must be visually inspected for physical defects and operating conditions which reasonably could be expected to impair the strength or tightness of the pipeline.#

(3)All known unsafe defects and conditions must be corrected in accordance with this part.#

(4)The pipeline must be tested in accordance with Subpart J of this part to substantiate the maximum allowable operating pressure permitted by Subpart L of this part.#

(b)Each operator must keep for the life of the pipeline a record of investigations, tests, repairs, replacements, and alterations made under the requirements of paragraph#

(a)of this section.#

(c)An operator converting a pipeline from service not previously covered by this part must notify PHMSA 60 days before the conversion occurs as required by § 191.22 of this chapter. § 192.15 Rules of Regulatory Construction#

(a)As used in this part: Includes means "including but not limited to." May means "is permitted to" or "is authorized to." May not means "is not permitted to" or "is not authorized to." Shall is used in the mandatory and imperative sense.#

(b)In this part:#

(1)Words importing the singular include the plural;#

(2)Words importing the plural include the singular; and#

(3)Words importing the masculine gender include the feminine. § 192.16 Customer Notification#

(a)This section applies to each operator of a service line who does not maintain the customer's buried piping up to entry of the first building downstream, or, if the customer's buried piping does not enter a building, up to the principal gas utilization equipment or the first fence (or wall) that surrounds that equipment. For the purpose of this section, "customer's buried piping" does not include branch lines that serve yard lanterns, pool heaters, or other types of secondary equipment. Also, "maintain" means monitor for corrosion according to § 192.465 if the customer's buried piping is metallic, survey for leaks according to § 192.723, and if an unsafe condition is found, shut off the flow of gas, advise the customer of the need to repair the unsafe condition, or repair the unsafe condition.#

(b)Each operator shall notify each customer once in writing of the following information:#

(1)The operator does not maintain the customer's buried piping.#

(2)If the customer's buried piping is not maintained, it may be subject to the potential hazards of corrosion and leakage.#

(3)Buried gas piping should be-#

(i)Periodically inspected for leaks;#

(ii)Periodically inspected for corrosion if the buried piping is metallic; and#

(iii)Repaired if any unsafe condition is discovered.#

(4)When excavating near buried gas piping, the piping should be located in advance, and the excavation done by hand.#

(5)The operator (if applicable), plumbing contractors, and heating contractors can assist in locating, inspecting, and repairing the buried piping.#

(c)Each operator shall notify each customer not later than August 14, 1996, or 90 days after the customer first receives gas at a particular location, whichever is later. However, operators of master meter systems may continuously post a general notice in a prominent location frequented by customers.#

(d)Each operator must make the following records available for inspection by the Administrator or a State agency participating under 49 U.S.C. 60105 or 60106:#

(1)A copy of the notice currently in use; and#

(2)Evidence that notices have been sent to customers within the previous 3 years. § 192.17 Filing of Operation, Inspection, and Maintenance Plan Each operator shall file with the Pipeline Safety Office of the Arkansas Public Service Commission#

(PSO)a plan for operation, inspection, and maintenance of each pipeline facility which the operator owns or operates. In addition, each change to this plan must be filed with the PSO within 20 days after the change is made. Once filed, this plan becomes a part of these standards as though incorporated and must be followed by the operator. § 192.18 How to Notify PHMSA#

(a)An operator must provide any notification required by this part by -#

(1)Sending the notification by electronic mail to: InformationResourcesManager@dot.gov; or#

(2)Sending the notification by mail to ATTN: Information Resources Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, 1200 New Jersey Ave. SE, Washington, DC 20590.#

(b)An operator must also notify the appropriate State or local pipeline safety authority when an applicable pipeline segment is located in a State where OPS has an interstate agent agreement, or an intrastate applicable pipeline segment is regulated by that State.#

(c)Unless otherwise specified, if an operator submits, pursuant to § 192.8, § 192.9, §192.13, §192.179, § 192.319, § 192.461, § 192.506, § 192.607,, §192.619, § 192.624§ 192.632, §192.634, § 192.636, § 192.710, § 192.712, § 192.714, § 192.745, §192.917, § 192.921,§192.927, § 192.933, or § 192.937a notification for use of a different integrity assessment method, analytical method, compliance period, sampling approach, pipeline material, or technique (i.e., "other technology") or "alternative equivalent technology") than otherwise prescribed in those sections, that notification must be submitted to PHMSA for review at least 90 days in advance of using the other method, approach, compliance timeline, or technique. An operator may proceed to use the other method, approach, compliance timeline, or technique 91 days after submitting the notification unless it receives a letter from the Associate Administrator for Pipeline Safety informing the operator that PHMSA objects to the proposal or that PHMSA requires additional time and/or more information to conduct its review. SUBPART B - MATERIALS § 192.51 Scope This subpart prescribes minimum requirements for the selection and qualification of pipe and components for use in pipelines. § 192.53 General Materials for pipe and components must be:#

(a)Able to maintain the structural integrity of the pipeline under t emperature and other environmental conditions that may be anticipated;#

(b)Chemically compatible with any gas that they transport and with any other material in the pipeline with which they are in contact; and#

(c)Qualified in accordance with the applicable requirements of this subpart. § 192.55 Steel Pipe#

(a)New steel pipe is qualified for use under this part if:#

(1)It was manufactured in accordance with a listed specification;#

(2)It meets the requirements of:#

(i)Section II of Appendix B to this part; or#

(ii)If it was manufactured before November 12, 1970, either Section II or III of Appendix B to this part; or#

(3)It is used in accordance with paragraph#

(c)or#

(d)of this section.#

(b)Used steel pipe is qualified for use under this part if:#

(1)It was manufactured in accordance with a listed specification, and it meets the requirements of paragraph II-C of Appendix B to this part;#

(2)It meets the requirements of:#

(i)Section II of Appendix B to this part; or#

(ii)It was manufactured before November 12, 1970, either Section II or III of Appendix B to this part; or#

(3)It has been used in an existing line of the same or higher pressure and meets the requirements of paragraph II-C of Appendix B to this part; or#

(4)It is used in accordance with paragraph#

(c)of this section.#

(c)New or used steel pipe may be used at a pressure resulting in a hoop stress of less than 6,000 p.s.i. (41 MPa) where no close coiling or close bending is to be done, if visual examination indicates that the pipe is in good condition and that it is free of split seams and other defects that would cause leakage. If it is to be welded, steel pipe that has not been manufactured to a listed specification must also pass the weldability tests prescribed in paragraph II-B of Appendix B to this part.#

(d)Steel pipe that has not been previously used may be used as replacement pipe in a segment of pipeline if it has been manufactured prior to November 12, 1970, in accordance with the same specification as the pipe used in constructing that segment of pipeline.#

(e)New steel pipe that has been cold expanded must comply with the mandatory provisions of API Spec 5L (incorporated by reference, see § 192.7). § 192.57 [Removed and Reserved] § 192.59 Plastic Pipe#

(a)New plastic pipe is qualified for use under this part if:#

(1)It is manufactured in accordance with a listed specification;#

(2)It is resistant to chemicals with which contact may be anticipated; and#

(3)It is free of visible defects.#

(b)Used plastic pipe is qualified for use under this part if:#

(1)It was manufactured in accordance with a listed specification;#

(2)It is resistant to chemicals with which contact may be anticipated;#

(3)It has been used only in gas service;#

(4)Its dimensions are still within the tolerances of the specification to which it was manufactured; and#

(5)It is free of visible defects.#

(c)For the purpose of paragraphs#

(a)(1)and#

(b)(1)of this section, when a pipe of a diameter included in a listed specification is impractical to use, pipe of a diameter between the sizes included in a listed specification may be used if it:#

(1)Meets the strength and design criteria required of pipe included in the listed specification; and#

(2)Is manufactured from plastic compounds which meet the criteria for material required of pipe included in that listed specification.#

(d)Rework and/or regrind material is not allowed in plastic pipe produced after March 6, 2015, used under this part. § 192.61 [Removed and Reserved] § 192.63 Marking of Materials#

(a)Except as provided in paragraph#

(d)and#

(e)of this section, each valve, fitting, length of pipe, and other component must be marked as prescribed in the specification or standard to which it was manufactured.#

(b)Surfaces of pipe and components that are subject to stress from internal pressure may not be field die stamped.#

(c)If any item is marked by die stamping, the die must have blunt or rounded edges that will minimize stress concentrations.#

(d)Paragraph#

(a)of this section does not apply to items manufactured before November 12, 1970, that meet all of the following:#

(1)The item is identifiable as to type, manufacturer, and model.#

(2)Specifications or standards giving pressure, temperature, and other appropriate criteria for the use of items are readily available.#

(e)All plastic pipe and components must also meet the following requirements:#

(1)All markings on plastic pipe prescribed in the listed specification and the requirements of paragraph(e)(2) of this section must be repeated at intervals not exceeding two feet.#

(2)Plastic pipe and components manufactured after December 31, 2019, must be marked in accordance with the listed specification.#

(3)All physical markings on plastic pipelines prescribed in the listed specification and paragraph(e)(2) of this section must be legible until the time of installation.#

(f)Operators shall reidentify pipe if specification markings are obliterated during the coating and/or wrapping process. This reidentification is not necessary if pipe is immediately installed in a system. § 192.65 Transportation of Pipe#

(a)Railroad. In a pipeline to be operated at a hoop stress of 20 percent or more of SMYS, an operator may not install pipe having an outer diameter to wall thickness ratio of 70 to 1, or more, that is transported by railroad unless the transportation is performed by API RP 5L1 (incorporated by reference, see § 192.7).#

(b)Ship or barge. In a pipeline to be operated at a hoop stress of 20 percent or more of SMYS, an operator may not use pipe having an outer diameter to wall thickness ratio of 70 to 1, or more, that is transported by ship or barge on both inland and marine waterways unless the transportation is performed in accordance with API RP 5LW (incorporated by reference, see § 192.7).#

(c)Truck. In a pipeline to be operated at a hoop stress of 20 percent or more of SMYS, an operator may not use pipe having an outer diameter to wall thickness ratio of 70 to 1, or more, that is transported by truck unless the transportation is performed in accordance with API RP 5LT (incorporated by reference, see § 192.7). §192.67 Records: Material properties.#

(a)For steel transmission pipelines installed after July 1, 2020, an operator must collect or make, and retain for the life of the pipeline, records that document the physical characteristics of the pipeline, including diameter, yield strength, ultimate tensile strength, wall thickness, seam type, and chemical composition of materials for pipe in accordance with §§192.53 and 192.55. Records must include tests, inspections, and attributes required by the manufacturing specifications applicable at the time the pipe was manufactured or installed.#

(b)For steel transmission pipelines installed on or before July 1, 2020, if operators have records that document tests, inspections, and attributes required by the manufacturing specifications applicable at the time the pipe was manufactured or installed, including diameter, yield strength, ultimate tensile strength, wall thickness, seam type, and chemical composition in accordance with §§192.53 and 192.55, operators must retain such records for the life of the pipeline.#

(c)For steel transmission pipeline segments installed on or before July 1, 2020, if an operator does not have records necessary to establish the MAOP of a pipeline segment, the operator may be subject to the requirements of §192.624 according to the terms of that section. §192.69 Storage and Handling of Plastic Pipe and Associated Components. Each operator must have and follow written procedures for the storage and handling of plastic pipe and associated components that meet the applicable listed specifications. SUBPART C - PIPE DESIGN § 192.101 Scope This subpart prescribes the minimum requirements for the design of pipe. § 192.103 General Pipe must be designed with sufficient wall thickness, or must be installed with adequate protection, to withstand anticipated external pressures and loads that will be imposed on the pipe after installation. § 192.105 Design Formula for Steel Pipe#

(a)The design pressure for steel pipe is determined in accordance with the following formula: P = Design pressure in pounds per square inch#

(kPa)gage. S = Yield strength in pounds per square inch#

(kPa)determined in accordance with § 192.107. D = Nominal outside diameter of the pipe in inches (millimeters). T = Nominal wall thickness of the pipe in inches (millimeters). If this is unknown, it is determined in accordance with § 192.109. Additional wall thickness required for concurrent external loads in accordance with § 192.103 may not be included in computing design pressure. F = Design factor determined in accordance with § 192.111. E = Longitudinal joint factor determined in accordance with § 192.113. T = Temperature derating factor determined in accordance with § 192.115.#

(b)If steel pipe that has been subjected to cold expansion to meet the SMYS is subsequently heated, other than by welding or stress relieving as a part of welding, the design pressure is limited to 75 percent of the pressure determined under paragraph#

(a)of this section if the temperature of the pipe exceeds 900°F (482°C) at any time or is held above 600°F (316°C) for more than 1 hour. § 192.107 Yield Strength#

(S)for Steel Pipe#

(a)For pipe that is manufactured in accordance with a specification listed in Section I of Appendix B of this part, the yield strength to be used in the design formula in § 192.105 is the SMYS stated in the listed specification, if that value is known.#

(b)For pipe that is manufactured in accordance with a specification not listed in Section I of Appendix B to this part or whose specification or tensile properties are unknown, the yield strength to be used in the design formula in § 192.105 is one of the following:#

(1)If the pipe is tensile tested in accordance with Section II-D of Appendix B to this part, the lower of the following:#

(i)80 percent of the average yield strength determined by the tensile tests.#

(ii)The lowest yield strength determined by the tensile tests, but not more than 52,000 p.s.i.#

(2)If the pipe is not tensile tested as provided in Subparagraph#

(b)(1)of this paragraph, 24,000 p.s.i. (165 MPa). § 192.109 Nominal Wall Thickness#

(t)for Steel Pipe#

(a)If the nominal wall thickness for steel pipe is not known, it is determined by measuring the thickness of each piece of pipe at quarter points on one end.#

(b)However, if the pipe is of uniform grade, size, and thickness and there are more than 10 lengths, only 10 percent of the individual lengths, but not less than 10 lengths, need be measured. The thickness of the lengths that are not measured must be verified by applying a gauge set to the minimum thickness found by the measurement. The nominal wall thickness to be used in the design formula in § 192.105 is the next wall thickness found in commercial specifications that is below the average of all the measurements taken. However, the nominal wall thickness used may not be more than 1.14 times the smallest measurement taken on pipe less than 20 inches (508 millimeters) in outside diameter, nor more than 1.11 times the smallest measurement taken on pipe 20 inches (508 millimeters) or more in outside diameter. § 192.111 Design Factor#

(F)for Steel Pipe#

(a)Except as otherwise provided in paragraphs (b), (c), and#

(d)of this section, the design factor to be used in the design formula in § 192.105 is determined in accordance with the following table: Class Design Location Factor#

(F)1....................... 0.72 2.......................... 0.60 3.......................... 0.50 4.......................... 0.40#

(b)A design factor of 0.60 or less must be used in the design formula in § 192.105 for steel pipe in Class 1 locations that:#

(1)Crosses the right-of-way of an unimproved public road, without a casing;#

(2)Crosses without a casing, or makes a parallel encroachment on, the right-of-way of either a hard surfaced road, a highway, a public street, or a railroad;#

(3)Is supported by a vehicular, pedestrian, railroad, or pipeline bridge; or#

(4)Is used in a fabricated assembly, (including separators, mainline valve assemblies, cross- connections, and river crossing headers) or is used within five pipe diameters in any direction from the last fitting of a fabricated assembly, other than a transition piece or an elbow used in place of a pipe bend which is not associated with a fabricated assembly.#

(c)For Class 2 locations, a design factor of 0.50, or less, must be used in the design formula in § 192.105 for uncased steel pipe that crosses the right-of-way of a hard surfaced road, a highway, a public street, or a railroad.#

(d)For Class 1 or Class 2 locations, a design factor of 0.50, or less, must be used in the design formula in § 192.105 for each compressor station, regulator station, and measuring station. § 192.112 Additional Design Requirements for Steel Pipe Using Alternative Maximum Allowable Operating Pressure For a new or existing pipeline segment to be eligible for operation at the alternative maximum allowable operating pressure#

(MAOP)calculated under § 192.620, a segment must meet the following additional design requirements. Records for alternative MAOP must be maintained, for the useful life of the pipeline, demonstrating compliance with these requirements: To address this The pipeline segment must meet these additional requirements: design issue:#

(a)General standards for the steel pipe#

(b)Fracture control#

(1)The plate, skelp, or coil used for the pipe must be micro-alloyed, fine grain, fully killed, continuously 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 Spec 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.#

(1)The toughness properties for pipe must address the potential for initiation, propagation and arrest of fractures in accordance with:#

(c)Plate/coil quality control#

(i)API Spec 5L (incorporated by reference, see §192.7); or#

(ii)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 Spec 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 behavior 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 Spec 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 average shear for any single test on each heat of steel.#

(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.#

(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.#

(d)Seam quality control#

(e)Mill hydrostatic#

(2)A mill inspection program or internal quality management program must include paragraph (c)(2)(i) of this section and either paragraph (c)(2)(ii) or#

(iii)of this section.#

(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 Spec 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.#

(1)There must be a quality assurance program for pipe seam welds to assure tensile strength provided in API Spec 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:#

(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.#

(1)All pipe to be used in a new pipeline segment installed after October 1, 2015, must be hydrostatically tested at the mill at a test pressure corresponding to a hoop stress of 95 percent SMYS for 10 seconds. test#

(f)Coating#

(g)Fittings and flanges#

(h)Compressor stations#

(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.#

(3)Pipe in operation on or after December 22, 2008, but before October 1, 1015, must have been 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 on internal test pressure and the allowance for end loading stresses imposed by the pipe mill hydrostatic testing equipment as allowed by "ANSI/API Spec 5L" (incorporated by reference, see §192.7).#

(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.#

(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.#

(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 conditioning 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 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 Sate where PHMSA has in interstate agent agreement, or an intrastate pipeline is regulated by that State. § 192.113 Longitudinal Joint Factor#

(E)for Steel Pipe#

(a)The longitudinal joint factor to be used in the design formula in § 192.105 is determined in accordance with the table 1 to this paragraph (a): Longitudinal Specification Pipe Class Joint Factor#

(E)ASTM A53/A53M Seamless 1.00 Electric resistance welded 1.00 Furnace butt welded 0.60 ASTM A106/A106M (incorporated by Seamless 1.00 reference, see § 192.7) ASTM A333/A333M (incorporated by Seamless 1.00 reference see § 192.7) Electric resistance welded 1.00 ASTM A381 (incorporated by reference see Double submerged arc welded 1.00 § 192.7) ASTM A671 (incorporated by reference see Electric fusion welded 1.00 § 192.7) ASTM A672(incorporated by reference see Electric fusion welded 1.00 § 192.7) ASTM A 691 (incorporated by reference Electric fusion welded 1.00 see § 192.7) API Spec 5L (incorporated by reference see Seamless 1.00 § 192.7) Electric resistance welded 1.00 Electric flash welded 1.00 Submerged arc welded 1.00 Furnace butt welded 0.60 Other Pipe over 4 inches (102 millimeters) 0.80 Other Pipe 4 inches (102 millimeters) or less 0.60#

(b)If the type of longitudinal joint cannot be determined, the joint factor to be used must not exceed that designated for "Other." § 192.115 Temperature Derating Factor#

(T)for Steel Pipe The temperature derating factor to be used in the design formula in § 192.105 is determined as follows: Gas Temperature in Degrees Fahrenheit#

(Celsius)Temperature Derating Factor 250⁰ F (121⁰ C) or less 1.0 300⁰ F (149⁰ C) 0.967 350⁰ F (177⁰C) 0.933 400⁰ F (204⁰C) 0.900 450⁰ F (232⁰C) 0.867 For intermediate gas temperatures, the derating factor is determined by interpolation. § 192.117 [Removed and Reserved] § 192.119 [Removed and Reserved] § 192.121 Design of Plastic Pipe#

(a)Design formula. The design formulas for plastic pipe are determined in accordance with either of the following formulas: P = Design pressure, gage, psi (kPa). S = For thermoplastic pipe, the hydrostatic design basis#

(HDB)is determined in accordance with the listed specification at a temperature equal to 73°F (23°C), 100°F (38°C), 120°F (49°C), or 140°F (60°C). In the absence of an HDB established at the specified temperature, the HDB of a higher temperature may be used in determining a design pressure rating at the specified temperature by arithmetic interpolation using the procedure in Part D.2 of PPI TR-3/2012 (incorporated by reference, see § 192.7). For reinforced thermosetting plastic pipe, 11,000 psig (75,842 kPa). t = Specified wall thickness, inches (mm). D = Specified outside diameter, inches (mm). SDR = Standard dimension ratio, the ratio of the average specified outside diameter to the minimum specified wall thickness, corresponding to a value from a common numbering system that was derived from the American National Standards Institute#

(ANSI)preferred number series 10. DF = Design Factor, a maximum of 0.32 unless otherwise specified for a particular material in this section.#

(b)General requirements for plastic pipe and components.#

(1)Except as provided in paragraphs#

(c)through#

(f)of this section, the design pressure for plastic pipe may not exceed a gauge pressure of 100 psig (689 kPa) for pipe used in:#

(i)Distribution systems; or#

(ii)Transmission lines in Class 3 and 4 locations.#

(2)Plastic pipe may not be used where operating temperatures of the pipe will be:#

(i)Below - 20 °F (- 29 °C), or below - 40 °F (- 40 °C) if all pipe and pipeline components whose operating temperature will be below - 20 °F (- 29 °C) have a temperature rating by the manufacturer consistent with that operating temperature; or#

(ii)Above the temperature at which the HDB used in the design formula under this section is determined.#

(3)Unless specified for a particular material in this section, the wall thickness of plastic pipe may not be less than 0.062 inches (1.57 millimeters).#

(4)All plastic pipe must have a listed HDB in accordance with PPI TR 4/2012 (incorporated by reference, see §192.7).#

(c)Polyethylene#

(PE)pipe requirements.#

(1)For PE pipe produced after July 14, 2004, but before January 22, 2019, a design pressure of up to 125 psig may be used, provided:#

(i)The material designation code is PE2406 or PE3408.#

(ii)The pipe has a nominal size (Iron Pipe Size#

(IPS)or Copper Tubing Size (CTS)) of 12 inches or less (above nominal pipe size of 12 inches, the design pressure is limited to 100 psig); and#

(iii)The wall thickness is not less than 0.062 inches (1.57 millimeters).#

(2)For PE pipe produced on or after January 22, 2019, a DF of 0.40 may be used in the design formula, provided:#

(i)The design pressure does not exceed 125 psig;#

(ii)The material designation code is PE2708 or PE4710;#

(iii)The pipe has a nominal size (IPS or CTS) of 24 inches or less; and#

(iv)The wall thickness for a given outside diameter is not less than that listed in Table 1 to this paragraph (c)(2)(iv): Table 1 to paragraph (c)(2)(iv): PE Pipe - Minimum Wall Thickness and SDR Values Pipe Size#

(inches)Minimum Wall Corresponding SDR Thickness (inches#

(values)½" CTS 0.090 7.0 ½" IPS 0.090 9.3 ¾" CTS 0.090 9.7 ¾" IPS 0.095 11 1" CTS 0.099 11 1" IPS 0.119 11 1 ¼" CTS 0.121 11 1 ¼" IPS 0.151 11 1 ½" IPS 0.173 11 2" 0.216 11 3" 0.259 13.5 4" 0.265 17.0 6" 0.315 21 8" 0.411 21 10" 0.512 21 12" 0.607 21 16" 0.762 21 18" 0.857 21 20" 0.952 21 22" 1.048 21 24" 1.143 21#

(d)Polyamide (PA-11) pipe requirements.#

(1)For PA-11 pipe produced after January 23, 2009, but before January 22, 2019, a DF of 0.40 may be used in the design formula, provided:#

(i)The design pressure does not exceed 200 psig;#

(ii)The material designation code is PA32312 or PA32316;#

(iii)The pipe has a nominal size (IPS or CTS) of 4 inches or less; and#

(iv)The pipe has a standard dimension ratio of SDR - 11 or less (i.e., thicker wall pipe).#

(2)For PA- 11 pipe produced on or after January 22, 2019, a DF of 0.40 may be used in the design formula, provided:#

(i)The design pressure does not exceed 250 psig;#

(ii)The material designation code is PA32316;#

(iii)The pipe has a nominal size (IPS or CTS) of 6 inches or less; and#

(iv)The minimum wall thickness for a given outside diameter is not less than that listed in Table 2 to this paragraph (d)(2)(iv): Table 2 to paragraph (d)(2)(iv): PA-11 Pipe: Minimum Wall Thickness and SDR Values Pipe Size#

(inches)Minimum Wall Thickness (inches Corresponding SDR#

(values)½" CTS 0.090 7.0 ½" IPS 0.090 9.3 ¾" CTS 0.090 9.7 ¾" IPS 0.095 11 1" CTS 0.099 11 1" IPS 0.119 11 1 ¼" CTS 0.121 11 1 ¼" IPS 0.151 11 1 ½" IPS 0.173 11 2" IPS 0.216 11 3" IPS 0.259 13.5 4" IPS 0.333 13.5 6" IPS 0.491 13.5#

(e)Polyamide (PA- 12) pipe requirements. For PA- 12 pipe produced after January 22, 2019, a DF of 0.40 may be used in the design formula, provided:#

(1)The design pressure does not exceed 250 psig;#

(2)The material designation code is PA42316;#

(3)The pipe has a nominal size (IPS or CTS) of 6 inches or less; and#

(4)The minimum wall thickness for a given outside diameter is not less than that listed in Table 3 to this Paragraph (e)(4): Table 3 to Paragraph (e)(4): PA-12 Pipe: minimum wall thickness and SDR values Pipe Size#

(inches)Minimum Wall Corresponding Thickness (inches dimension ratio#

(values)½" CTS 0.090 7.0 ½" IPS 0.090 9.3 ¾" CTS 0.090 9.7 ¾" IPS 0.095 11 1" CTS 0.099 11 1" IPS 0.119 11 1 ¼" IPS 0.151 11 1 ½" IPS 0.173 11 2" IPS 0.216 11 3" IPS 0.259 13.5 4" IPS 0.333 13.5 6" IPS 0.491 13.5#

(f)Reinforced thermosetting plastic pipe requirements.#

(1)Reinforced thermosetting plastic pipe may not be used at operating temperatures above 150 °F (66 °C).#

(2)The wall thickness for reinforced thermosetting plastic pipe may not be less than that listed in the following table: Nominal Size in Inches#

(millimeters)Minimum Wall Thickness in Inches#

(millimeters)2#

(51)0.060 (1.52) 3#

(76)0.060 (1.52) 4#

(102)0.070 (1.78) 6#

(152)0.100 (2.54) § 192.123 [ Removed and Reserved] § 192.125 Design of Copper Pipe#

(a)Copper pipe used in mains must have a minimum wall thickness of 0.065 inches (1.65 millimeters) and must be hard drawn.#

(b)Copper pipe used in service lines must have wall thickness not less than that indicated in the following table: Standard Size Inch#

(millimeter)Nominal O.D. Inch#

(millimeter)Wall Thickness, inch#

(millimeter)Nominal Tolerance ½ (13).625 (16).040 (1.06).0035 (.0889) ⅝ (16).750 (19).042 (1.07).0035 (.0889) ¾ (19).875 (22).045 (1.14).004 (.102) 1#

(24)1.125 (29).050 (1.27).004 (.102) 1 ¼#

(32)1.375 (35).055 (1.40).0045 (.1143) 1 ½#

(38)1.625 (41).060 (1.52).0045 (.1143)#

(c)Copper pipe used in mains and service line may not be used at pressures in excess of 100 p.s.i. (689 kPa) gage.#

(d)Copper pipe that does not have an internal corrosion resistant lining may not be used to carry gas that has an average hydrogen sulfide content of more than 0.3 grains/100 ft.3 (6.9/m3) under standard conditions. Standard conditions refers to 60°F and 14.7 p.s.i.a. (15.6°C and one atmosphere). § 192.127 Records: Pipe Design#

(a)For steel transmission pipelines installed after July 1, 2020], an operator must collect or make, and retain for the life of the pipeline, records documenting that the pipe is designed to withstand anticipated external pressures and loads in accordance with § 192.103 and documenting that the determination of design pressure for the pipe is made in accordance with § 192.105.#

(b)For steel transmission pipelines installed on or before July 1, 2020, if operators have records documenting pipe design and the determination of design pressure in accordance with §§ 192.103 and 192.105, operators must retain such records for the life of the pipeline.#

(c)For steel transmission pipeline segments installed on or before July 1, 2020, if an operator does not have records necessary to establish the MAOP of a pipeline segment, the operator may be subject to the requirements of § 192.624 according to the terms of that section. SUBPART D - DESIGN OF PIPELINE COMPONENTS § 192.141 Scope This subpart prescribes minimum requirements for the design and installation of pipeline components and facilities. In addition, it prescribes requirements relating to protection against accidental over pressuring. § 192.143 General Requirements#

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

(b)The design and installation of pipeline components and facilities must meet applicable requirements for corrosion control found in subpart I of this part.#

(c)Except for excess flow valves, each plastic pipeline component installed after January 22, 2019, must be able to withstand operating pressures and other anticipated loads in accordance with a listed specification. § 192.144 Qualifying Metallic Components Notwithstanding any requirement of this subpart which incorporates by reference an edition of a document listed in § 192.7 or Appendix B of this part, a metallic component manufactured in accordance with any other edition of that document is qualified for use under this part if-#

(a)It can be shown through visual inspection of the cleaned component that no defect exists which might impair the strength or tightness of the component; and#

(b)The edition of the document under which the component was manufactured has equal or more stringent requirements for the following as an edition of that document currently or previously listed in § 192.7 or Appendix B of this part:#

(1)Pressure testing;#

(2)Materials; and#

(3)Pressure and temperature ratings. § 192.145 Valves#

(a)Except for cast iron and plastic valves, each valve must meet the minimum requirements of API Spec 6D (incorporated by reference, see § 192.7), or to a national or international standard that provides an equivalent performance level. A valve may not be used under operating conditions that exceed the applicable pressure-temperature ratings contained in those requirements.#

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

(1)The valve must have a maximum service pressure rating for temperatures that equal or exceed the maximum service temperature; and#

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

(i)With the valve in the fully open position, the shell must be tested with no leakage to a pressure at least 1.5 times the maximum service rating.#

(ii)After the shell test, the seat must be tested to a pressure not less than 1.5 times the maximum service pressure rating. Except for swing check valves, test pressure during the seat test must be applied successively on each side of the closed valve with the opposite side open. No visible leakage is permitted.#

(iii)After the last pressure test is completed, the valve must be operated through its full travel to demonstrate freedom from interference.#

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

(d)No valve having shell (Body, bonnet, cover, and/or end flange) components made of ductile iron may be used at pressures exceeding 80 percent of the pressure ratings for comparable steel valves at their listed temperature. However, a valve having shell components made of ductile iron may be used at pressures up to 80 percent of the pressure ratings for comparable steel valves at their listed temperature, if:#

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

(2)Welding is not used on any ductile iron component in the fabrication of the valve shells or their assembly.#

(e)No valve having shell (body, bonnet, cover, and/or end flange) components made of cast iron, malleable iron, or ductile iron may be used in the gas pipe components of compressor stations.#

(f)Except for excess flow valves, plastic valves installed after January 22, 2019, must meet the minimum requirements of a listed specification. A valve may not be used under operating conditions that exceed the applicable pressure and temperature ratings contained in the listed specification. § 192.147 Flanges and Flange Accessories#

(a)Each flange or flange accessory (other than cast iron) must meet the minimum requirements of ASME/ANSI B16.5 (incorporated by reference, see § 192.7), ANSI/MSS SP-44 (incorporated by reference, see § 192.7), or the equivalent.#

(b)Each flange assembly must be able to withstand the maximum pressure at which the pipeline is to be operated and to maintain its physical and chemical properties at any temperature to which it is anticipated that it might be subjected in service.#

(c)Each flange on a flanged joint in cast iron pipe must conform in dimensions, drilling, face and gasket design to ASME/ANSI B16.1 (incorporated by reference, see § 192.7) and be cast integrally with the pipe, valve, or fitting. § 192.149 Standard Fittings#

(a)The minimum metal thickness of threaded fittings may not be less than specified for the pressures and temperatures in the applicable standards referenced in this part, or their equivalent.#

(b)Each steel, butt-welding fitting must have pressure and temperature ratings based on stresses for pipe of the same or equivalent material. The actual bursting strength of the fitting must at least equal the computed bursting strength of pipe of the designated material and wall thickness, as determined by a prototype that was tested to at least the pressure required for the pipeline to which it is being added.#

(c)Plastic fittings installed after January 22, 2019, must meet a listed specification. § 192.150 Passage of Internal Inspection Devices#

(a)Except as provided in paragraphs#

(b)and#

(c)of this section, each new transmission line and each replacement of line pipe, valve, fitting, or other line component in a transmission line must be designed and constructed to accommodate the passage of instrumented internal inspection devices in accordance with NACE SP0102, section 7 (incorporated by reference, see § 192.7).#

(b)This section does not apply to:#

(1)Manifolds;#

(2)Station piping such as at compressor stations, meter stations, or regulator stations;#

(3)Piping associated with storage facilities, other than a continuous run of transmission line between a compressor station and storage facilities;#

(4)Cross-overs;#

(5)Sizes of pipe for which an instrumented internal inspection device is not commercially available;#

(6)Transmission lines, operated in conjunction with a distribution system which are installed in Class 4 locations;#

(7)Gathering lines; and#

(8)Other piping that, under § 190.9 of this chapter, the Administrator finds in a particular case would be impracticable to design and construct to accommodate the passage of instrumented internal inspection devices.#

(c)An operator encountering emergencies, construction time constraints or other unforeseen construction problems need not construct a new or replacement segment of a transmission line to meet subparagraph#

(a)of this paragraph, if the operator determines and documents why impracticability prohibits compliance with subparagraph#

(a)of this paragraph. Within 30 days after discovering the emergency or construction problem the operator must petition, under § 190.9 of this chapter, for approval that design and construction to accommodate passage of instrumented internal inspection devices would be impracticable. If the petition is denied, within 1 year after the date of the notice of denial, the operator must modify that segment to allow passage of instrumented internal inspection devices. § 192.151 Tapping#

(a)Each mechanical fitting used to make a hot tap must be designed for at least the operating pressure of the pipeline.#

(b)Where a ductile iron pipe is tapped, the extent of full-thread engagement and the need for the use of outside-sealing service connections, tapping saddles, or other fixtures must be determined by service conditions.#

(c)Where a threaded tap is made in cast iron or ductile iron pipe, the diameter of the tapped hole may not be more than 25 percent of the nominal diameter of the pipe unless the pipe is reinforced, except that:#

(1)Existing taps may be used for replacement service, if they are free of cracks and have good threads; and#

(2)A 1 1/4 inch (32 millimeters) tap may be made in a 4 inch (102 millimeters) cast iron or ductile iron pipe, without reinforcement. However, in areas where climate, soil, and service conditions may create unusual external stresses on cast iron pipe, unreinforced taps may be used only on 6 inch (152 millimeters) or larger pipe. § 192.153 Components Fabricated by Welding#

(a)Except for branch connections and assemblies of standard pipe and fittings joined by circumferential welds, the design pressure of each component fabricated by welding, whose strength cannot be determined, must be established in accordance with paragraph UG-101 of the ASME Boiler and Pressure Vessel Code#

(BPVC)(Section VIII, Division 1) (incorporated by reference, see § 192.7).#

(b)Each prefabricated unit that uses plate and longitudinal seams must be designed, constructed, and tested in accordance with section 1 of the ASME BPVC (Rules for Construction of Pressure Vessels as defined in either Section VIII, Division 1 or Section VIII, Division 2; incorporated by reference, see §192.7), except for the following:#

(1)Regularly manufactured butt-welding fittings.#

(2)Pipe that has been produced and tested under a specification listed in Appendix B to this part.#

(3)Partial assemblies such as split rings or collars.#

(4)Prefabricated units that the manufacturer certifies have been tested to at least twice the maximum pressure to which they will be subjected under the anticipated operating conditions.#

(c)Orange-peel bull plugs and orange-peel swages may not be used on pipelines that are to operate at a hoop stress of 20 percent or more of the SMYS of the pipe.#

(d)Except for flat closures designed in accordance with the ASME BPVC, (Section VIII, Division 1 or Division 2), (both incorporated by reference, see § 192.7) flat closures and fish tails may not be used on pipe that either operates at 100 p.s.i. (689 kilopascals) or more, or that is more than 3 inches (76 millimeters) nominal diameter.#

(e)The test requirements for a prefabricate unit or pressure vessel, defined for this paragraph as components with a design pressure established in accordance with paragraph#

(a)or paragraph#

(b)of this section are as follows.#

(1)A prefabricated unit or pressure vessel installed after July 14, 2004 is not subject to the strength testing requirements at §192.505(b) provided the component has been tested in accordance with paragraph#

(a)or paragraph#

(b)of this section and with a test factor of at least 1.3 times MAOP.#

(2)A prefabricated unit or pressure vessel must be tested for a duration specified as follows.#

(i)A prefabricated unit or pressure vessel installed after July 14, 2004, but before October 1, 2021 is exempt from §§ 192.505(c) and#

(d)and 192.507(c) provided it has been tested for a duration consistent with the ASME BPVC requirements referenced in paragraph#

(a)or#

(b)of this section.#

(ii)A prefabricated unit or pressure vessel installed on or after October 1, 2021 must be tested for the duration specified in either § 192.505(c) or (d), § 192.507(c), or § 192.509(a), whichever is applicable for the pipeline in which the component is being installed.#

(3)For any prefabricated unit or pressure vessel permanently or temporarily installed on a pipeline facility, an operator must either:#

(i)Test the prefabricated unit or pressure vessel in accordance with this section and Subpart J of this part after it has been placed on its support structure at its final installation location. The test may be performed before or after it has been tied-in to the pipeline. Test records that meet § 192.517(a) must be kept for the operational life of the prefabricated unit or pressure vessel; or#

(ii)For a prefabricated unit or pressure vessel that is pressure tested prior to installation or where a manufacturer's pressure test is used in accordance with paragraph#

(e)of this section, inspect the prefabricated unit or pressure vessel after it has been placed on its support structure at its final installation location and confirm that the prefabricated unit or pressure vessel was not damaged during any prior operation, transportation, or installation into the pipeline. The inspection procedure and documented inspection must include visual inspection for vessel damage, including, at a minimum, inlets, outlets, and lifting locations. Injurious defects that are an integrity threat may include dents, gouges, bending, corrosion, and cracking. This inspection must be performed prior to operation but may be performed either before or after it has been tied-in to the pipeline. If injurious defects that are an integrity threat are found, the prefabricated unit or pressure vessel must be either non-destructively tested, re-pressure tested, or remediated in accordance with applicable part 192 requirements for a fabricated unit or with the applicable ASME BPVC requirements referenced in paragraphs#

(a)or#

(b)of this section. Test, inspection, and repair records for the fabricated unit or pressure vessel must be kept for the operational life of the component. Test records must meet the requirements in §192.517(a).#

(4)An initial pressure test from the prefabricated unit or pressure vessel manufacturer may be used to meet the requirements of this section with the following conditions:#

(i)The prefabricated unit or pressure vessel is newly-manufactured and installed on or after October 1, 2021, except as provided in paragraph (e)(4)(ii) of this section.#

(ii)An initial pressure test from the fabricated unit or pressure vessel manufacturer or other prior test of a new or existing prefabricated unit or pressure vessel may be used for a component that is temporarily installed in a pipeline facility in order to complete a testing, integrity assessment, repair, odorization, or emergency response-related task, including noise or pollution abatement. The temporary component must be promptly removed after that task is completed. If operational and environmental constraints require leaving a temporary prefabricated unit or pressure vessel under this paragraph in place for longer than 30 days, the operator must notify PHMSA and State or local pipeline safety authorities, as applicable, in accordance with §192.18.#

(iii)The manufacturer's pressure test must meet the minimum requirements of this part; and#

(iv)The operator inspects and remediates the prefabricated unit or pressure vessel after installation in accordance with paragraph (e)(3)(ii) of this section.#

(5)An existing prefabricated unit or pressure vessel that is temporarily removed from a pipeline facility to complete a testing, integrity assessment, repair, odorization, or emergency response-related task, including noise or pollution abatement, and then re-installed at the same location must be inspected in accordance with paragraph (e)(3)(ii) of this section; however, a new pressure test is not required provided no damage or threats to the operational integrity of the prefabricated unit or pressure vessel were identified during the inspection and the MAOP of the pipeline is not increased.#

(6)Except as provided in paragraphs (e)(4)(ii) and#

(5)of this section, on or after October 1, 2021, an existing prefabricated unit or pressure vessel relocated and operated at a different location must meet the requirements of this part and the following:#

(i)The prefabricated unit or pressure vessel must be designed and constructed in accordance with the requirements of this part at the time the vessel is returned to operational service at the new location; and#

(ii)The prefabricated unit or pressure vessel must be pressure tested by the operator in accordance with the testing and inspection requirements of this part applicable to newly installed prefabricated units and pressure vessels. § 192.155 Welded Branch Connections Each welded branch connection made to pipe in the form of a single connection, or in a header or manifold as a series of connections, must be designed to ensure that the strength of the pipeline system is not reduced, taking into account the stresses in the remaining pipe wall due to the opening in the pipe or header, the shear stresses produced by the pressure acting on the area of the branch opening and any external loadings due to thermal movement, weight, and vibration. § 192.157 Extruded Outlets Each extruded outlet must be suitable for anticipated service conditions and must be at least equal to the design strength of the pipe and other fittings in the pipeline to which it is attached. § 192.159 Flexibility Each pipeline must be designed with enough flexibility to prevent thermal expansion or contraction from causing excessive stresses in the pipe or components, excessive bending or unusual loads at joints, or undesirable forces or moments at points of connection to equipment, or at anchorage or guide points. § 192.161 Supports and Anchors#

(a)Each pipeline and its associated equipment must have enough anchors or supports to:#

(1)Prevent undue strain on connected equipment;#

(2)Resist longitudinal forces caused by a bend or offset in the pipe; and#

(3)Prevent or damp out excessive vibration.#

(b)Each exposed pipeline must have enough supports or anchors to protect the exposed pipe joints from the maximum end force caused by internal pressure and any additional forces caused by temperature expansion or contraction or by the weight of the pipe and its contents.#

(c)Each support or anchor on an exposed pipeline must be made of durable, noncombustible material and must be designed and installed as follows:#

(1)Free expansion and contraction of the pipeline between supports or anchors may not be restricted;#

(2)Provision must be made for the service conditions involved; and#

(3)Movement of the pipeline may not cause disengagement of the support equipment.#

(d)Each support on an exposed pipeline operated at a stress level of 50 percent or more of SMYS must comply with the following:#

(1)A structural support may not be welded directly to the pipe;#

(2)The support must be provided by a member that completely encircles the pipe; and#

(3)If an encircling member is welded to a pipe, the weld must be continuous and cover the entire circumference.#

(e)Each underground pipeline that is connected to a relatively unyielding line or other fixed object must have enough flexibility to provide for possible movement, or it must have an anchor that will limit the movement of the pipeline.#

(f)Each underground pipeline that is being connected to new branches must have a firm foundation for both the header and the branch to prevent detrimental lateral and vertical movement. § 192.163 Compressor Stations: Design and Construction#

(a)Location of compressor building. Each main compressor building of a compressor station must be located on property under the control of the operator. It must be far enough away from adjacent property, not under control of the operator, to minimize the possibility of fire being communicated to the compressor building from structures on adjacent property. There must be enough open space around the main compressor building to allow the free movement of fire-fighting equipment.#

(b)Building construction. Each building on a compressor station site must be made of noncombustible materials if it contains either:#

(1)Pipe more than 2 inches (51 millimeters) in diameter that is carrying gas under pressure; or#

(2)Gas handling equipment other than gas utilization equipment used for domestic purposes.#

(c)Exits. Each operating floor of a main compressor building must have at least two separated and unobstructed exits located so as to provide a convenient possibility of escape and an unobstructed passage to a place of safety. Each door latch on an exit must be of a type which can be readily opened from the inside without a key. Each swinging door located in an exterior wall must be mounted to swing outward.#

(d)Fenced areas. Each fence around a compressor station must have at least two gates located so as to provide a convenient opportunity for escape to a place of safety or have other facilities affording a similarly convenient exit from the area. Each gate located within 200 feet (61 meters) of any compressor plant building must open outward and, when occupied, must be openable from the inside without a key.#

(e)Electrical facilities. Electrical equipment and wiring installed in compressor stations must conform to the NFPA-70 (incorporated by reference, see § 192.7), so far as that code is applicable. § 192.165 Compressor Stations: Liquid Removal#

(a)Where entrained vapors in gas may liquefy under the anticipated pressure and temperature conditions, the compressor must be protected against the introduction of those liquids in quantities that could cause damage.#

(b)Each liquid separator used to remove entrained liquids at a compressor station must:#

(1)Have a manually operable means of removing these liquids;#

(2)Where slugs of liquid could be carried into the compressors, have either automatic liquid removal facilities, an automatic compressor shut-down device, or a high liquid level alarm; and#

(3)Be manufactured in accordance with Section VIII ASME Boiler and Pressure Vessel Code#

(BPVC)(incorporated by reference, see § 192.7) and the additional requirements of § 192.153(e), except that liquid separators constructed of pipe and fittings without internal welding must be fabricated with a design factor of 0.4 or less. § 192.167 Compressor Station: Emergency ShutDown#

(a)Except for unattended field compressor stations of 1,000 horsepower (746 kilowatts) or less, each compressor station must have an emergency shutdown system that meets the following:#

(1)It must be able to block gas out of the station and blow down the station piping.#

(2)It must discharge gas from the blowdown piping at a location where the gas will not create a hazard.#

(3)It must provide means for the shutdown of gas compressing equipment, gas fires, and electrical facilities in the vicinity of gas headers and in the compressor building except, that:#

(i)Electrical circuits that supply emergency lighting required to assist station personnel in evacuating the compressor building and the area in the vicinity of the gas headers must remain energized; and#

(ii)Electrical circuits needed to protect equipment from damage may remain energized.#

(4)It must be operable from at least two locations, each of which is:#

(i)Outside the gas area of the station;#

(ii)Near the exit gates, if the station is fenced, or near emergency exits, if not fenced; and#

(iii)Not more than 500 feet (153 meters) from the limits of the station.#

(b)If a compressor station supplies gas directly to a distribution system with no other adequate source of gas available, the emergency shutdown system must be designed so that it will not function at the wrong time and cause the unintended outage on the distribution system. § 192.169 Compressor Stations: Pressure Limiting Devices#

(a)Each compressor station must have pressure relief or other suitable protective devices of sufficient capacity and sensitivity to ensure that the maximum allowable operating pressure of the station piping and equipment is not exceeded by more than 10 percent.#

(b)Each vent line that exhausts gas from the pressure relief valves of a compressor station must extend to a location where the gas may be discharged without hazard. § 192.171 Compressor Stations: Additional Safety Equipment#

(a)Each compressor station must have adequate fire protection facilities. If fire pumps are a part of these facilities, their operation may not be affected by the emergency shutdown system.#

(b)Each compressor station prime mover, other than an electrical induction or synchronous motor, must have an automatic device to shut down the unit before the speed of either the prime mover or the driven unit exceeds a maximum safe speed.#

(c)Each compressor unit in a compressor station must have a shutdown or alarm device that operates in the event of inadequate cooling or lubrication of the unit.#

(d)Each compressor station gas engine that operates with pressure gas injection must be equipped so that the stoppage of the engine automatically shuts off the fuel and vents the engine distribution manifold.#

(e)Each muffler for a gas engine in a compressor station must have vent slots or holes in baffles of each compartment to prevent gas from being trapped in the muffler. § 192.173 Compressor Stations: Ventilation Each compressor station building must be ventilated to ensure that employees are not endangered by the accumulation of gas in rooms, sumps, attics, pits, or other enclosed places. § 192.175 Pipe-Type and Bottle-Type Holders#

(a)Each pipe-type and bottle-type holder must be designed so as to prevent the accumulation of liquids in the holder, in connecting pipe, or in auxiliary equipment, that might cause corrosion or interfere with the safe operation of the holder.#

(b)Each pipe-type or bottle-type holder must have minimum clearance from other holders in accordance with the following formula: C = (3D x P x F)/1000) in inches; (C = (3D x P x F)/6,895) in millimeters In which: C = Minimum clearance between pipe containers or bottles in inches (millimeters). D = Outside diameter of pipe containers or bottles in inches#

(millimeters)P = Maximum allowable operating pressure, psi#

(kPa)gauge. F = Design factor as set forth in § 192.111 of this part. § 192.177 Additional Provisions for Bottle-Type Holders#

(a)Each bottle-type holder must be:#

(1)Located on a site entirely surrounded by fencing that prevents access by unauthorized persons and with minimum clearance from the fence as follows: Maximum Allowable Operating Pressure Minimum Clearance Feet#

(meters)Less than 1,000 p.s.i. (7 MPa) gage 25 (7.6) 1,000 p.s.i. (7 MPa) or more 100#

(31)#

(2)Designed using the design factors set forth in § 192.111; and#

(3)Buried with a minimum cover in accordance with § 192.327.#

(b)Each bottle-type holder manufactured from steel that is not weldable under field conditions must comply with the following:#

(1)A bottle-type holder made from alloy steel must meet the chemical and tensile requirements for the various grades of steel in ASTM A372/A372M (incorporated by reference, see § 192.7).#

(2)The actual yield-tensile ratio of the steel may not exceed 0.85.#

(3)Welding may not be performed on the holder after it has been heat treated or stress relieved, except that copper wires may be attached to the small diameter portion of the bottle end closure for cathodic protection if a localized thermite welding process is used.#

(4)The holder must be given a mill hydrostatic test at a pressure that produces a hoop stress at least equal to 85 percent of the SMYS.#

(5)The holder, connection pipe, and components must be leak tested after installation as required by Subpart J of this part. § 192.179 Transmission Line Valves#

(a)Each transmission line must have sectionalizing block valves spaced as follows, unless in a particular case the Administrator finds that alternative spacing would provide an equivalent level of safety:#

(1)Each point on the pipeline in a Class 4 location must be within 2 1/2 miles (4 kilometers) of a valve.#

(2)Each point on the pipeline in a Class 3 location must be within 4 miles (6.4 kilometers) of a valve.#

(3)Each point on the pipeline in a Class 2 location must be within 7 1/2 miles (12 kilometers) of a valve.#

(4)Each point on the pipeline in a Class 1 location must be within 10 miles (16 kilometers) of a valve.#

(b)Each sectionalizing block valve on a transmission line must comply with the following:#

(1)The valve and the operating device to open or close the valve must be readily accessible and protected from tampering and damage.#

(2)The valve must be supported to prevent settling of the valve or movement of the pipe to which it is attached.#

(c)Each section of transmission line between main line valves must have a blowdown valve with enough capacity to allow the transmission line to be blown down as rapidly as practicable. Each blowdown discharge must be located so the gas can be blown to the atmosphere without hazard and, if the transmission line is adjacent to an overhead electric line, so that the gas is directed away from the electrical conductors.#

(d)Offshore segments of transmission lines must be equipped with valves or other components to shut off the flow of gas to an offshore platform in an emergency.#

(e)For onshore transmission pipeline segments with diameters greater than or equal to 6 inches that are constructed after April 10, 2023, the operator must install rupture-mitigation valves#

(RMV)or an alternative equivalent technology whenever a valve must be installed to meet the appropriate valve spacing requirements of this section. An operator seeking to use alternative equivalent technology must notify PHMSA in accordance with the procedures set forth in paragraph#

(g)of this section. All RMVs and alternative equivalent technologies installed pursuant to this paragraph#

(e)must meet the requirements of § 192.636. The installation requirements in this paragraph#

(e)do not apply to pipe segments with a potential impact radius (PIR), as defined in § 192.903, that is less than or equal to 150 feet in either Class 1 or Class 2 locations. An operator may request an extension of the installation compliance deadline requirements of this paragraph#

(e)if it can demonstrate to PHMSA, in accordance with the notification procedures in § 192.18, that those installation compliance deadlines would be economically, technically, or operationally infeasible for a particular new pipeline.#

(f)For entirely replaced onshore transmission pipeline segments, as defined in § 192.3, with diameters greater than or equal to 6 inches and that are installed after April 10, 2023, the operator must install RMVs or an alternative equivalent technology whenever a valve must be installed to meet the appropriate valve spacing requirements of this section. An operator seeking to use alternative equivalent technology must notify PHMSA in accordance with the procedures set forth in paragraph#

(g)of this section. All RMVs and alternative equivalent technologies installed pursuant to this paragraph#

(f)must meet the requirements of § 192.636. The requirements of this paragraph#

(f)apply when the applicable pipeline replacement project involves a valve, either through addition, replacement, or removal. The installation requirements in this paragraph#

(f)do not apply to pipe segments with a PIR, as defined in § 192.903, that is less than or equal to 150 feet in either Class 1 or Class 2 locations. An operator may request an extension of the installation compliance deadline requirements of this paragraph#

(f)if it can demonstrate to PHMSA, in accordance with the notification procedures in § 192.18, that those installation compliance deadlines would be economically, technically, or operationally infeasible for a particular pipeline replacement project.#

(g)If an operator elects to use alternative equivalent technology in accordance with paragraph#

(e)or#

(f)of this section, the operator must notify PHMSA in accordance with the procedures in § 192.18. The operator must include a technical and safety evaluation in its notice to PHMSA. Valves that are installed as alternative equivalent technology must comply with §§ 192.634 and 192.636. An operator requesting use of manual valves as an alternative equivalent technology must also include within the notification submitted to PHMSA a demonstration that installation of an RMV as otherwise required would be economically, technically, or operationally infeasible. An operator may use a manual compressor station valve at a continuously manned station as an alternative equivalent technology, and use of such valve would not require a notification to PHMSA in accordance with § 192.18, but it must comply with § 192.636.#

(h)The valve spacing requirements of paragraph#

(a)of this section do not apply to pipe replacements on a pipeline if the distance between each point on the pipeline and the nearest valve does not exceed:#

(1)Four#

(4)miles in Class 4 locations, with a total spacing between valves no greater than 8 miles;#

(2)Seven-and-a-half (7 1/2) miles in Class 3 locations, with a total spacing between valves no greater than 15 miles; or#

(3)Ten#

(10)miles in Class 1 or 2 locations, with a total spacing between valves no greater than 20 miles. § 192.181 Distribution Line Valves#

(a)Each high-pressure distribution system must have valves spaced so as to reduce the time to shut down a section of main in an emergency. The valve spacing is determined by the operating pressure, the size of the mains, and the local physical conditions.#

(b)Each regulator station controlling the flow or pressure of gas in a distribution system must have a valve installed on the inlet piping at a distance from the regulator station sufficient to permit the operation of the valve during an emergency that might preclude access to the station.#

(c)Each valve on a main installed for operating or emergency purposes must comply with the following:#

(1)The valve must be placed in a readily accessible location so as to facilitate its operation in an emergency.#

(2)The operating stem or mechanism must be readily accessible.#

(3)If the valve is installed in a buried box or enclosure, the box or enclosure must be installed so as to avoid transmitting external loads to the main. § 192.183 Vaults: Structural Design Requirements#

(a)Each underground vault or pit for valves, pressure relieving, pressure limiting, or pressure regulating stations, must be able to meet the loads which may be imposed upon it, and to protect installed equipment.#

(b)There must be enough working space so that all of the equipment required in the vault or pit can be properly installed, operated, and maintained.#

(c)Each pipe entering, or within, a regulator vault or pit must be steel for sizes 10 inches (254 millimeters), and less, except that control and gauge piping may be copper. Where pipe extends through the vault or pit structure, provision must be made to prevent the passage of gasses or liquids through the opening and to avert strains in the pipe. § 192.185 Vaults: Accessibility Each vault must be located in an accessible location and, so far as practical, away from:#

(a)Street intersections or points where traffic is heavy or dense;#

(b)Points of minimum elevation, catch basins, or places where the access cover will be in the course of surface waters; and#

(c)Water, electric, steam, or other facilities. § 192.187 Vaults: Sealing, Venting, and Ventilation Each underground vault or closed top pit containing either a pressure regulating or reducing station, or a pressure limiting or relieving station, must be sealed, vented, or ventilated, as follows:#

(a)When the internal volume exceeds 200 cubic feet (5.7 cubic meters):#

(1)The vault or pit must be ventilated with two ducts, each having at least the ventilating effect of a pipe 4 inches (102 millimeters ) in diameter;#

(2)The ventilation must be enough to minimize the formation of combustible atmosphere in the vault or pit; and#

(3)The ducts must be high enough above grade to disperse any gas-air mixtures that might be discharged.#

(b)When the internal volume is more than 75 cubic feet (2.1 cubic meters) but less than 200 cubic feet (5.7 cubic meters):#

(1)If the vault or pit is sealed, each opening must have a tight fitting cover without open holes through which an explosive mixture might be ignited, and there must be a means for testing the internal atmosphere before removing the cover;#

(2)If the vault or pit is vented, there must be a means of preventing external sources of ignition from reaching the vault atmosphere; or#

(3)If the vault or pit is ventilated, paragraph#

(a)or#

(c)of this section applies.#

(c)If a vault or pit covered by paragraph#

(b)of this section is ventilated by openings in the covers or gratings and the ratio of the internal volume, in cubic feet, to the effective ventilating area of the cover or grating, in square feet, is less than 20 to 1, no additional ventilation is required. § 192.189 Vaults: Drainage and Waterproofing#

(a)Each vault must be designed so as to minimize the entrance of water.#

(b)A vault containing gas piping may not be connected by means of a drain connection to any other underground structure.#

(c)Electrical equipment in vaults must conform to the applicable requirements of Class 1, Group D, of the National Electrical Code, NFPA-70 (incorporated by reference see § 192.7). § 192.191 [Removed and Reserved] § 192.193 Valve Installation in Plastic Pipe Each valve installed in plastic pipe must be designed so as to protect the plastic material against excessive torsional or shearing loads when the valve or shutoff is operated, and from any other secondary stresses that might be exerted through the valve or its enclosure. § 192.195 Protection Against Accidental Overpressuring#

(a)General requirements. Except as provided in § 192.197, each pipeline that is connected to a gas source so that the maximum allowable operating pressure could be exceeded as the result of pressure control failure or of some other type of failure, must have pressure relieving or pressure limiting devices that meet the requirements of §§ 192.199 and 192.201.#

(b)Additional requirements for distribution systems. Each distribution system that is supplied from a source of gas that is at a higher pressure than the maximum allowable operating pressure for the system must:#

(1)Have pressure regulation devices capable of meeting the pressure, load, and other service conditions that will be experienced in normal operation of the system, and that could be activated in the event of failure of some portion of the system; and#

(2)Be designed so as to prevent accidental overpressuring. § 192.197 Control of Pressure of Gas Delivered from High-Pressure Distribution Systems#

(a)Each operator shall establish a maximum actual operating pressure for each distribution system as required by § 192.622.#

(b)If the maximum actual operating pressure of the distribution system is 60 p.s.i. (414 kPa) gage, or less, and a service regulator having the following characteristics is used, no other pressure limiting device is required:#

(1)A regulator capable of reducing line pressure to pressures required to safely operate the customers' gas utilization equipment.#

(2)A regulator with an internal relief valve vented to the outside atmosphere or an overpressure control device. A single port valve with the orifice size commensurate with the inlet pressure to assure adequate volume and pressure to the customer and also assures the overpressure control device prevents the build-up of pressure that would cause the unsafe operation of the customers' gas utilization equipment.#

(3)A valve seat made of resilient material designed to withstand abrasion of the gas, impurities in gas, cutting of the valve, and to resist permanent deformation when pressed against the valve port.#

(4)Pipe connections to the regulator not exceeding 2 inches (51 millimeters) in diameter.#

(5)A regulator that, under normal operating conditions, will regulate the downstream pressure within the necessary limits of accuracy and prevents the build-up of pressure under no flow conditions that would cause the unsafe operation of the customers' gas utilization equipment.#

(6)A self-contained regulator with no external static or control lines.#

(c)If the maximum actual operating pressure of the distribution system is 60 p.s.i. (414 kPa) gage, or less, and a regulator that does not have all the characteristics listed in paragraph#

(b)of this section is used, or if the gas contains materials that seriously affects the operation of the regulator, there must be suitable protective devices installed to prevent over-pressuring the customers' gas utilization equipment if the regulator fails.#

(d)If the maximum actual operating pressure of the distribution system exceeds 60 p.s.i. (414 kPa) gage, one of the following methods must be used to regulate and limit to a safe value, the pressure delivered to the customers' gas utilization equipment:#

(1)A service regulator having the characteristics listed in paragraph#

(b)this part, and another regulator located upstream from the service regulator. The upstream regulator may not be set to maintain a pressure higher than 60 p.s.i. (414 kPa) gage. If the upstream regulator does not have an internal relief valve of sufficient capacity to limit the pressure to the service regulator to 60 p.s.i.(414 kPa) gage, a device must be installed between the upstream regulator and service regulator to limit the pressure to the service regulator to 60 p.s.i.(414 kPa) gage or less in case the upstream regulator fails to function properly. This device may be either a regulator, relief valve, or an automatic shutoff that shuts if the pressure on the inlet of the service regulator exceeds 60 p.s.i. (414 kPa) gage, and remains closed until manually reset.#

(2)A service regulator and a monitoring regulator set to limit, to a safe value, the pressure delivered to the customer. Both regulators must be constructed to withstand the maximum inlet pressure.#

(3)A service regulator and an automatic shutoff device that closes upon an unsafe rise in pressure downstream from the regulator and remains closed until manually reset.#

(e)If the maximum actual operating pressure does not exceed 125 p.s.i. (862 kPa) gage, a service regulator having the characteristics listed in paragraph#

(b)of this section and a manufacturer's inlet working pressure rating of 125 p.s.i. (862 kPa) gage or higher, may be used. If the internal relief valve capacity will prevent the downstream pressure from exceeding a safe value, or an overpressure control device is installed, no additional pressure limiting device is required. § 192.199 Requirements for Design of Pressure Relief and Limiting Devices Except for rupture discs, each pressure relief or pressure limiting device must:#

(a)Be constructed of materials such that the operation of the device will not be impaired by corrosion;#

(b)Have valves and valve seats that are designed not to stick in a position that will make the device inoperative;#

(c)Be designed and installed so that it can be readily operated to determine if the valve is free, can be tested to determine the pressure at which it will operate, and can be tested for leakage when in the closed position;#

(d)Have support made of noncombustible material;#

(e)Have discharge stacks, vents, or outlet ports designed to prevent accumulation of water, ice, or snow, located where gas can be discharged into the atmosphere without undue hazard;#

(f)Be designed and installed so that the size of the openings, pipe, and fittings located between the system to be protected and the pressure relieving device, and the size of the vent line, are adequate to prevent hammering of the valve and to prevent impairment of relief capacity;#

(g)Where installed at a district regulator station to protect a pipeline system from overpressuring, be designed and installed to prevent any single incident such as an explosion in a vault or damage by a vehicle from affecting the operation of both the overpressure protective device and the district regulator; and#

(h)Except for a valve that will isolate the system under protection from its source of pressure, be designed to prevent unauthorized operation of any stop valve that will make the pressure relief valve or pressure limiting device inoperative.#

(i)Each regulator station must be provided with reasonable protection from physical damage due to vehicles or other causes by being placed in a suitable location or by installation of barricades. § 192.201 Required Capacity of Pressure Relieving and Limiting Stations#

(a)Each pressure relief station or pressure limiting station or group of those stations installed to protect a pipeline must have enough capacity, and must be set to operate, to insure the following:#

(1)In a low-pressure distribution system, the pressure may not cause the unsafe operation of any connected and properly adjusted gas utilization equipment.#

(2)In pipelines other than a low-pressure distribution system:#

(i)If the maximum allowable operating pressure is 60 p.s.i. (414 kPa) or more, the pressure may not exceed the maximum allowable operating pressure plus 10 percent, or the pressure that produces a hoop stress of 75 percent of SMYS, whichever is lower;#

(ii)If the maximum allowable operating pressure is 12 p.s.i. (83 kPa) gage or more, but less than 60 p.s.i. (414 kPa) gage, the pressure may not exceed the maximum allowable operating pressure plus 6 p.s.i.#

(41kPa)gage; or#

(iii)If the maximum allowable operating pressure is less than 12 p.s.i. (83 kPa) gage, the pressure may not exceed the maximum allowable operating pressure plus 50 percent.#

(b)When more than one pressure regulating or compressor station feeds into a pipeline, relief valves or other protective devices must be installed at each station to ensure that the complete failure of the largest capacity regulator or compressor, or any single run of lesser capacity regulators or compressors in that station, will not impose pressures on any part of the pipeline or distribution system in excess of those for which it was designed, or against which it was protected, whichever is lower.#

(c)Relief valves or other pressure limiting devices must be installed at or near each regulator station in a low-pressure distribution system, with a capacity to limit the maximum pressure in the main to a pressure that will not exceed the safe operating pressure for any connected and properly adjusted gas utilization equipment. § 192.203 Instrument, Control, and Sampling Pipe and Components#

(a)Applicability. This section applies to the design of instrument, control and sampling pipe and components. It does not apply to permanently closed systems, such as fluid-filled temperature responsive devices.#

(b)Materials and design. All materials employed for pipe and components must be designed to meet the particular conditions of service and the following:#

(1)Each takeoff connection and attaching boss, fitting, or adapter must be made of suitable material, be able to withstand the maximum service pressure and temperature of the pipe or equipment to which it is attached, and be designed to satisfactorily withstand all stresses without failure by fatigue.#

(2)Except for takeoff lines that can be isolated from sources of pressure by other valving, a shutoff valve must be installed in each take offline as near as practicable to the point of take-off. Blowdown valves must be installed where necessary.#

(3)Brass or copper material may not be used for metal temperatures greater than 400°F (204°C).#

(4)Pipe or components that may contain liquids must be protected by heating or other means from damage due to freezing.#

(5)Pipe or components in which liquids may accumulate must have drains or drips.#

(6)Pipe or components subject to clogging from solids or deposits must have suitable connections for cleaning.#

(7)The arrangement of pipe, components, and supports must provide safety under anticipated operating stresses.#

(8)Each joint between sections of pipe, and between pipe and valves or fittings, must be made in a manner suitable for the anticipated pressure and temperature condition. Slip type expansion joints may not be used. Expansion must be allowed for by providing flexibility within the system itself.#

(9)Each control line must be protected from anticipated causes of damage and must be designed and installed to prevent damage to any one control line from making both the regulator and the over-pressure protective device inoperative. § 192.204 Risers Installed After January 22, 2019#

(a)Riser designs must be tested to ensure safe performance under anticipated external and internal loads acting on the assembly.#

(b)Factory assembled anodeless risers must be designed and tested in accordance with ASTM F1973-13 (incorporated by reference, see §192.7).#

(c)All risers used to connect regulator stations to plastic mains must be rigid and designed to provide adequate support and resist lateral movement. Anodeless risers used in accordance with this paragraph must have a rigid riser casing. § 192.205 Records: Pipeline Components#

(a)For steel transmission pipelines installed after July 1, 2020, an operator must collect or make, and retain for the life of the pipeline, records documenting the manufacturing standard and pressure rating to which each valve was manufactured and tested in accordance with this subpart. Flanges, fittings, branch connections, extruded outlets, anchor forgings, and other components with material yield strength grades of 42,000 psi#

(X42)or greater and with nominal diameters of greater than 2 inches must have records documenting the manufacturing specification in effect at the time of manufacture, including yield strength, ultimate tensile strength, and chemical composition of materials.#

(b)For steel transmission pipelines installed on or before July 1, 2020, if operators have records documenting the manufacturing standard and pressure rating for valves, flanges, fittings, branch connections, extruded outlets, anchor forgings, and other components with material yield strength grades of 42,000 psi#

(X42)or greater and with nominal diameters of greater than 2 inches, operators must retain such records for the life of the pipeline.#

(c)For steel transmission pipeline segments installed on or before July 1, 2020, if an operator does not have records necessary to establish the MAOP of a pipeline segment, the operator may be subject to the requirements of § 192.624 according to the terms of that section. SUBPART E - WELDING OF STEEL IN PIPELINES § 192.221 Scope#

(a)This subpart prescribes minimum requirements for welding steel materials in pipelines.#

(b)This subpart does not apply to welding that occurs during the manufacture of steel pipe or steel pipeline components. § 192.225 Welding - Procedures#

(a)Welding must be performed by a qualified welder or welding operator in accordance with welding procedures qualified under section 5 (except for Note 2 in section 5.4.2.2), section 12, Appendix A or Appendix B of API Std 1104 (incorporated by reference, see § 192.7), or Section IX of the ASME Boiler and Pressure Vessel Code (ASME BPVC) (incorporated by reference, see § 192.7) to produce welds meeting the requirements of this subpart. The quality of the test welds used to qualify welding procedures must be determined by destructive testing in accordance with the applicable welding standard(s).#

(b)Each welding procedure must be recorded in detail, including the results of the qualifying tests. This record must be retained and followed whenever the procedure is used. § 192.227 Qualification of Welders and Welding Operators#

(a)Except as provided in paragraph#

(b)of this section, each welder or welding operator must be qualified in accordance with section 6, section 12, Appendix A or Appendix B of API Std 1104 (incorporated by reference, see § 192.7), or section IX of the ASME Boiler and Pressure Vessel Code#

(BPVC)(incorporated by reference, see § 192.7). However, a welder or welding operator qualified under an earlier edition than listed in § 192.7 may weld but may not requalify under that earlier edition.#

(b)A welder may qualify to perform welding on pipe to be operated at a pressure that produces a hoop stress of less than 20 percent of SMYS by performing an acceptable test weld, for the process to be used, under the test set forth in Section I of Appendix C of this part. Each welder who is to make a welded service line connection to a main must first perform an acceptable test weld under section II of Appendix C of this part as a requirement of the qualifying test.#

(c)For steel transmission pipe installed after July 1, 2021, records demonstrating each individual welder qualification at the time of construction in accordance with this section must be retained for a minimum of 5 years following construction. § 192.229 Limitations on Welders and Welding Operators#

(a)No welder or welding operator whose qualification is based on nondestructive testing may weld compressor station pipe and components.#

(b)A welder or welding operator may not weld with a particular welding process unless, within the preceding 6 calendar months, the welder or welding operator was engaged in welding with that process. Alternatively, welders or welding operators may demonstrate they have engaged in a specific welding process if they have performed a weld with that process if they have performed a weld with that process that was tested and found acceptable under section 6, 9, 12, or Appendix A of API Std 1104 (incorporated by reference, see §192.7) within the preceding 7½ months.#

(c)A welder or welding operator qualified under § 192.227(a):#

(1)May not weld on pipe to be operated at a pressure that produces a hoop stress of 20 percent or more of SMYS unless within the preceding 6 calendar months the welder or welding operator has had one weld tested and found acceptable under either section 6, section 9, section 12 or Appendix A of API Std 1104 (incorporated by reference, see § 192.7). Alternatively, welders or welding operators may maintain an ongoing qualification status by performing welds tested and found acceptable under the above acceptance criteria at least twice each calendar year, but at intervals not exceeding 7 ½ months. A welder or welding operator qualified under an earlier edition of a standard listed in § 192.7 of this part may weld but may not re-qualify under that earlier edition; and#

(2)May not weld on pipe to be operated at a pressure that produces a hoop stress of less than 20 percent of SMYS unless the welder or welding operator is tested in accordance with paragraph#

(c)(1)of this section or requalifies under paragraph#

(d)(1)or#

(d)(2)of this section.#

(d)A welder or welding operator qualified under § 192.227(b) may not weld unless:#

(1)Within the preceding 15 calendar months, but at least once each calendar year, the welder or welding operator has re-qualified under § 192.227(b); or#

(2)Within the preceding 7 1/2 calendar months, but at least twice each calendar year, the welder or welding operator has had - i. A production weld cut out, tested, and found acceptable in accordance with the qualifying test; or ii. For a welder who works only on service lines 2 inches (51 millimeters) or smaller in diameter, the welder has had two sample welds tested and found acceptable in accordance with the test in section III of Appendix C of this part. § 192.231 Protection from Weather The welding operation must be protected from weather conditions that would impair the quality of the completed weld. § 192.233 Miter Joints#

(a)A miter joint on steel pipe to be operated at a pressure that produces a hoop stress of 30 percent or more of SMYS may not deflect the pipe more than 3°.#

(b)A miter joint on steel pipe to be operated at a pressure that produces a hoop stress of less than 30 percent, but more than 10 percent, of SMYS may not deflect the pipe more than 12 1/2° and must be a distance equal to one pipe diameter or more away from any other miter joint, as measured from the crotch of each joint.#

(c)A miter joint on steel pipe to be operated at a pressure that produces a hoop stress of 10 percent or less of SMYS may not deflect the pipe more than 90°. § 192.235 Preparation for Welding Before beginning any welding, the welding surfaces must be clean and free of any material that may be detrimental to the weld, and the pipe or component must be aligned to provide the most favorable condition for depositing the root bead. This alignment must be preserved while the root bead is being deposited. § 192.241 Inspection and Test of Welds#

(a)Visual inspection of welding must be conducted by an individual qualified by appropriate training and experience to ensure that:#

(1)The welding is performed in accordance with the welding procedure, and#

(2)The weld is acceptable under paragraph#

(c)of this section.#

(b)The welds on a pipeline to be operated at a pressure that produces a hoop stress of 20 percent or more of SMYS must be nondestructively tested in accordance with § 192.243, except that welds that are visually inspected and approved by a qualified welding inspector need not be nondestructively tested if:#

(1)The pipe has a nominal diameter of less than 6 inches (152 millimeters); or#

(2)The pipeline is to be operated at a pressure that produces a hoop stress of less than 40 percent of SMYS and the welds are so limited in number that nondestructive testing is impractical.#

(c)The acceptability of a weld that is nondestructively tested or visually inspected is determined according to the standards in Section 9 or Appendix A of API Std 1104 (incorporated by reference, see § 192.7). Appendix A of API Std 1104 may not be used to accept cracks.#

(d)Each operator must designate in writing a welding inspector to perform visual inspections of welds under this paragraph. § 192.243 Nondestructive Testing#

(a)Nondestructive testing of welds must be performed by any process, other than trepanning, that will clearly indicate defects that may affect the integrity of the weld.#

(b)Nondestructive testing of welds must be performed:#

(1)In accordance with written procedures; and#

(2)By persons who have been trained and qualified in accordance with the requirements of API Standard 1104. These persons must also be qualified on the equipment employed in the nondestructive testing.#

(c)Procedures must be established for the proper interpretation of each nondestructive test of a weld to ensure the acceptability of the weld under § 192.241(c).#

(d)When nondestructive testing is required under § 192.241(b), the following percentages of each day's field butt welds, selected at random by the operator, must be nondestructively tested over their entire circumference:#

(1)In Class 1 locations, at least 10 percent.#

(2)In Class 2 locations, at least 15 percent.#

(3)In Class 3 and 4 locations at crossings of major or navigable rivers and within railroad or public highway rights-of-way, including tunnels, bridges, and overhead road crossings, 100 percent unless impracticable, in which case at least 90 percent. Nondestructive testing must be impracticable for each girth weld not tested.#

(4)At pipeline tie-ins, including tie-ins of replacement sections, 100 percent.#

(e)Except for a welder or welding operator whose work is isolated from the principal welding activity, a sample of each welder's or welding work for each day must be nondestructively tested, when nondestructive testing is required under § 192.241(b).#

(f)When nondestructive testing is required under § 192.241(b) each operator must retain, for the life of the pipeline, a record showing by milepost, engineering station, or by geographic feature, the number of girth welds made, the number nondestructively tested, the number rejected, and the disposition of the rejects. § 192.245 Repair or Removal of Defects#

(a)Each weld that is unacceptable under § 192.241(c) must be removed or repaired. A weld must be removed if it has a crack that is more than 8 percent of the weld length.#

(b)Each weld that is repaired must have the defect removed down to sound metal and the segment to be repaired must be preheated if conditions exist which would adversely affect the quality of the weld repair. After repair, the segment of the weld that was repaired must be inspected to ensure its acceptability.#

(c)Repair of a crack, or of any defect in a previously repaired area must be in accordance with the written weld repair procedures that have been qualified under § 192.225. Repair procedures must provide that the minimum mechanical properties specified for the welding procedures used to make the original weld are met upon completion of the final weld repair. SUBPART F - JOINING OF MATERIALS OTHER THAN BY WELDING § 192.271 Scope#

(a)This subpart prescribes minimum requirements for joining materials in pipelines, other than by welding.#

(b)This subpart does not apply to joining during the manufacture of pipe or pipeline components.#

(c)Where pipe is to be joined or connections made by threaded couplings all threads will meet the standards of API Standard 5B. All joints will be made up power-tight using a suitable thread sealant. § 192.273 General#

(a)The pipeline must be designed and installed so that each joint will sustain the longitudinal pullout or thrust forces caused by contraction or expansion of the piping or by anticipated external or internal loading.#

(b)Each joint must be made in accordance with written procedures that have been proven by test or experience to produce strong gas-tight joints.#

(c)Each joint must be inspected to insure compliance with this subpart. § 192.275 Cast Iron Pipe#

(a)Each caulked bell and spigot joint in cast iron pipe must be sealed with mechanical leak clamps.#

(b)Each mechanical joint in cast iron pipe must have a gasket made of a resilient material as the sealing medium. Each gasket must be suitably confined and retained under compression by a separate gland or follower ring.#

(c)Cast iron pipe may not be joined by threaded joints.#

(d)Cast iron pipe may not be joined by brazing. § 192.277 Ductile Iron Pipe#

(a)Ductile iron pipe may not be joined by threaded joints.#

(b)Ductile iron pipe may not be joined by brazing. § 192.279 Copper Pipe Copper pipe may not be threaded, except that copper pipe that is used for joining screw fittings or valves which may be threaded if the wall thickness is equivalent to the comparable size of Schedule 40 or heavier wall pipe listed in ASME B36.10M (incorporated by reference, see § 192.7). § 192.281 Plastic Pipe#

(a)General. A plastic pipe joint that is joined by solvent cement, adhesive, or heat fusion may not be disturbed until it has properly set. Plastic pipe may not be joined by a threaded joint or miter joint.#

(b)Solvent cement joints. Each solvent cement joint on plastic pipe must comply with the following:#

(1)The mating surfaces of the joint must be clean, dry, and free of material which might be detrimental to the joint.#

(2)The solvent cement must conform to ASTM D2564-12, for PVC (incorporated by reference, see § 192.7).#

(3)The joint may not be heated or cooled to accelerate the setting of the cement.#

(4)Plastic pipe manufactured from different materials shall not be joined by solvent cement joints.#

(c)Heat-fusion joints. Each heat-fusion joint on a PE pipe or component, except for electrofusion joints, must comply with ASTM F2620-12 (incorporated by reference in §192.7), or an alternative written procedure that has been demonstrated to provide an equivalent or superior level of safety and has been proven by tests or experience to produce strong gastight joints, and the following:#

(1)A butt heat-fusion joint must be joined by a device that holds the heater element square to the ends of the pipe or component, compresses the heated ends together, and holds the pipe in proper alignment in accordance with the appropriate procedure qualified under § 192.283.#

(2)A socket heat-fusion joint must be joined by a device that heats the mating surfaces of the pipe or component, uniformly and simultaneously, to establish the same temperature. The device used must be the same device specified in the operator's joining procedure for socket fusion.#

(3)An electrofusion joint must be made using the equipment and techniques prescribed by the fitting manufacturer, or using equipment and techniques shown, by testing joints to the requirements of § 192.283(a)(1)(iii), to be equivalent to or better than the requirements of the fitting manufacturer.#

(4)Heat may not be applied with a torch or other open flame.#

(d)Adhesive joints. Each adhesive joint on thermosetting plastic pipe must comply with the following:#

(1)The plastic fittings and adhesives must conform to the specifications listed in ASTM D2517 (incorporated by reference, see §192.7).#

(2)The materials and adhesive must be compatible with each other.#