Pipeline and Hazardous Materials Safety Admin., DOT Pt. 195

Major rivers Nearest town and state 195.2 Definitions. 195.3 What documents are incorporated by Maumee River ...... Defiance, OH. reference partly or wholly in this part? Maumee River ...... Toledo, OH. 195.4 Compatibility necessary for transpor- Mississippi River ...... Myrtle Grove, LA. tation of hazardous liquids or carbon di- Mississippi River ...... Woodriver, IL. Mississippi River ...... Chester, IL. oxide. Mississippi River ...... Cape Girardeau, MO. 195.5 Conversion to service subject to this Mississippi River ...... Woodriver, IL. part. Mississippi River ...... St. James, LA. 195.6 Unusually Sensitive Areas (USAs). Mississippi River ...... New Roads, LA. 195.8 Transportation of hazardous liquid or Mississippi River ...... Ball Club, MN. carbon dioxide in pipelines constructed Mississippi River ...... Mayersville, MS. Mississippi River ...... New Roads, LA. with other than steel pipe. Mississippi River ...... Quincy, IL. 195.9 Outer continental shelf pipelines. Mississippi River ...... Ft. Madison, IA. 195.10 Responsibility of operator for compli- Missouri River ...... Waverly, MO. ance with this part. Missouri River ...... St. Joseph, MO. 195.11 What is a regulated rural gathering Missouri River ...... Weldon Springs, MO. line and what requirements apply? Missouri River ...... New Frankfort, MO. 195.12 What requirements apply to low- Naches River ...... Beaumont, TX. Ohio River ...... Joppa, IL. stress pipelines in rural areas? Ohio River ...... Cincinnati, OH. 195.13 What requirements apply to pipelines Ohio River ...... Owensboro, KY. transporting hazardous liquids by grav- Pascagoula River ...... Lucedale, MS. ity? Pascagoula River ...... Wiggins, MS. 195.15 What requirements apply to report- Pearl River ...... Columbia, MS. ing-regulated-only gathering lines? Pearl River ...... Oria, TX. Platte River ...... Ogaliala, NE. Potomac River ...... Reston, VA. Subpart B—Annual, Accident, and Safety- Rappahannock River ...... Midland, VA. Related Condition Reporting Raritan River ...... South Bound Brook, NJ. Raritan River ...... Highland Park, NJ. 195.48 Scope. Red River (of the South) ...... Hanna, LA. 195.49 Annual report. Red River (of the South) ...... Bonham, TX. 195.50 Reporting accidents. Red River (of the South) ...... Dekalb, TX. 195.52 Immediate notice of certain acci- Red River (of the South) ...... Sentell Plantation, LA. Red River (of the North) ...... Wahpeton, ND. dents. Rio Grande ...... Anthony, NM. 195.54 Accident reports. Sabine River ...... Edgewood, TX. 195.55 Reporting safety-related conditions. Sabine River ...... Leesville, LA. 195.56 Filing safety-related condition re- Sabine River ...... Orange, TX. ports. Sabine River ...... Echo, TX. 195.58 Report submission requirements. Savannah River ...... Hartwell, GA. 195.59 Abandonment or deactivation of fa- Smokey Hill River ...... Abilene, KS. Susquehanna River ...... Darlington, MD. cilities. Tenessee River ...... New Johnsonville, TN. 195.60 Operator assistance in investigation. Wabash River ...... Harmony, IN. 195.61 National pipeline mapping system. Wabash River ...... Terre Haute, IN. 195.63 OMB control number assigned to in- Wabash River ...... Mt. Carmel, IL. formation collection. White River ...... Batesville, AR. 195.64 National Registry of Operators. White River ...... Grand Glaise, AR. Wisconsin River ...... Wisconsin Rapids, WI. 195.65 Safety data sheets. Yukon River ...... Fairbanks, AK. Subpart C—Design Requirements Other Navigable Waters 195.100 Scope. Arthur Kill Channel, NY 195.101 Qualifying metallic components Cook Inlet, AK other than pipe. Freeport, TX 195.102 Design temperature. Los Angeles/Long Beach Harbor, CA 195.104 Variations in pressure. Port Lavaca, TX 195.106 Internal design pressure. San Fransico/San Pablo Bay, CA 195.108 External pressure. 195.110 External loads. 195.111 Fracture propagation. PART 195—TRANSPORTATION OF 195.112 New pipe. HAZARDOUS LIQUIDS BY PIPELINE 195.114 Used pipe. 195.116 Valves. Subpart A—General 195.118 Fittings. 195.120 Passage of internal inspection de- Sec. vices. 195.0 Scope. 195.122 Fabricated branch connections. 195.1 Which pipelines are covered by this 195.124 Closures. part? 195.126 Flange connection.

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195.128 Station piping. 195.402 Procedural manual for operations, 195.130 Fabricated assemblies. maintenance, and emergencies. 195.132 Design and construction of above- 195.403 Emergency response training. ground breakout tanks. 195.404 Maps and records. 195.134 Leak detection. 195.405 Protection against ignitions and safe access/egress involving floating roofs. Subpart D—Construction 195.406 Maximum operating pressure. 195.408 Communications. 195.200 Scope. 195.410 Line markers. 195.202 Compliance with specifications or 195.412 Inspection of rights-of-way and standards. crossings under navigable waters. 195.204 Inspection—general. 195.413 Underwater inspection and reburial 195.205 Repair, alteration and reconstruc- of pipelines in the Gulf of Mexico and its tion of aboveground breakout tanks that inlets. have been in service. 195.414 Inspections of pipelines in areas af- 195.206 Material inspection. fected by extreme weather and natural 195.207 Transportation of pipe. disasters. 195.208 Welding of supports and braces. 195.415 [Reserved] 195.210 Pipeline location. 195.416 Pipeline assessments. 195.212 Bending of pipe. 195.417–195.418 [Reserved] 195.214 Welding: General. 195.420 Valve maintenance. 195.216 Welding: Miter joints. 195.422 Pipeline repairs. 195.222 Welders and welding operators: Qual- 195.424 Pipe movement. ification of welders and welding opera- 195.426 Scraper and sphere facilities. tors. 195.428 Overpressure safety devices and 195.224 Welding: Weather. overfill protection systems. 195.226 Welding: Arc burns. 195.430 Firefighting equipment. 195.228 Welds and welding inspection: 195.432 Inspection of in-service breakout Standards of acceptability. tanks. 195.230 Welds: Repair or removal of defects. 195.434 Signs. 195.234 Welds: Nondestructive testing. 195.436 Security of facilities. 195.236–195.244 [Reserved] 195.438 Smoking or open flames. 195.246 Installation of pipe in a ditch. 195.440 Public awareness. 195.248 Cover over buried pipeline. 195.442 Damage prevention program. 195.250 Clearance between pipe and under- 195.444 Leak detection. ground structures. 195.446 Control room management. 195.252 Backfilling. 195.254 Above ground components. HIGH CONSEQUENCE AREAS 195.256 Crossing of railroads and highways. 195.258 Valves: General. 195.450 Definitions. 195.260 Valves: Location. PIPELINE INTEGRITY MANAGEMENT 195.262 Pumping equipment. 195.264 Impoundment, protection against 195.452 Pipeline integrity management in entry, normal/emergency venting or high consequence areas. pressure/vacuum relief for aboveground 195.454 Integrity assessments for certain un- breakout tanks. derwater hazardous liquid pipeline facili- 195.266 Construction records. ties located in high consequence areas.

Subpart E—Pressure Testing Subpart G—Qualification of Pipeline Personnel 195.300 Scope. 195.302 General requirements. 195.501 Scope. 195.303 Risk-based alternative to pressure 195.503 Definitions. testing older hazardous liquid and carbon 195.505 Qualification program. dioxide pipelines. 195.507 Recordkeeping. 195.304 Test pressure. 195.509 General. 195.305 Testing of components. 195.306 Test medium. Subpart H—Corrosion Control 195.307 Pressure testing aboveground break- out tanks. 195.551 What do the regulations in this sub- 195.308 Testing of tie-ins. part cover? 195.310 Records. 195.553 What special definitions apply to this subpart? Subpart F—Operation and Maintenance 195.555 What are the qualifications for su- pervisors? 195.400 Scope. 195.557 Which pipelines must have coating 195.401 General requirements. for external corrosion control?

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195.559 What coating material may I use for facilities used in the transportation of external corrosion control? hazardous liquids or carbon dioxide. 195.561 When must I inspect pipe coating used for external corrosion control? [Amdt. 195–45, 56 FR 26925, June 12, 1991] 195.563 Which pipelines must have cathodic protection? § 195.1 Which pipelines are covered by 195.565 How do I install cathodic protection this Part? on breakout tanks? (a) Covered. Except for the pipelines 195.567 Which pipelines must have test leads listed in paragraph (b) of this Section, and what must I do to install and main- this Part applies to pipeline facilities tain the leads? and the transportation of hazardous 195.569 Do I have to examine exposed por- liquids or carbon dioxide associated tions of buried pipelines? with those facilities in or affecting 195.571 What criteria must I use to deter- mine the adequacy of cathodic protec- interstate or foreign commerce, includ- tion? ing pipeline facilities on the Outer 195.573 What must I do to monitor external Continental Shelf (OCS). Covered pipe- corrosion control? lines include, but are not limited to: 195.575 Which facilities must I electrically (1) Any pipeline that transports a isolate and what inspections, tests, and highly volatile liquid; safeguards are required? (2) Any pipeline segment that crosses 195.577 What must I do to alleviate inter- a waterway currently used for commer- ference currents? cial navigation; 195.579 What must I do to mitigate internal (3) Except for a gathering line not corrosion? covered by paragraph (a)(4) of this Sec- 195.581 Which pipelines must I protect against atmospheric corrosion and what tion, any pipeline located in a rural or coating material may I use? non-rural area of any diameter regard- 195.583 What must I do to monitor atmos- less of operating pressure; pheric corrosion control? (4) Any of the following onshore 195.585 What must I do to correct corroded gathering lines used for transportation pipe? of petroleum: 195.587 What methods are available to deter- (i) A pipeline located in a non-rural mine the strength of corroded pipe? area; 195.588 What standards apply to direct as- (ii) A regulated rural gathering line sessment? as provided in § 195.11; or 195.589 What corrosion control information (iii) A pipeline located in an inlet of do I have to maintain? the Gulf of Mexico as provided in 195.591 In-Line inspection of pipelines. § 195.413. APPENDIX A TO PART 195—DELINEATION BE- (5) For purposes of the reporting re- TWEEN FEDERAL AND STATE JURISDIC- quirements in subpart B of this part, TION—STATEMENT OF AGENCY POLICY AND INTERPRETATION any gathering line not already covered APPENDIX B TO PART 195—RISK-BASED ALTER- under paragraphs (a)(1), (2), (3) or (4) of NATIVE TO PRESSURE TESTING OLDER HAZ- this section. ARDOUS LIQUID AND CARBON DIOXIDE PIPE- (b) Excepted. This Part does not apply LINES to any of the following: APPENDIX C TO PART 195—GUIDANCE FOR IM- (1) Transportation of a hazardous liq- PLEMENTATION OF AN INTEGRITY MANAGE- uid transported in a gaseous state; MENT PROGRAM (2) Except for the reporting require- AUTHORITY: 30 U.S.C. 185(w)(3), 49 U.S.C. ments of subpart B of this part, see 5103, 60101 et seq., and 49 CFR 1.97. § 195.13, transportation of a hazardous SOURCE: Amdt. 195–22, 46 FR 38360, July 27, liquid through a pipeline by gravity. 1981, unless otherwise noted. (3) Transportation of a hazardous liq- uid through any of the following low- EDITORIAL NOTE: Nomenclature changes to stress pipelines: part 195 appear at 71 FR 33409, June 9, 2006. (i) A pipeline subject to safety regu- lations of the U.S. Coast Guard; or Subpart A—General (ii) A pipeline that serves refining, manufacturing, or truck, rail, or vessel § 195.0 Scope. terminal facilities, if the pipeline is This part prescribes safety standards less than one mile long (measured out- and reporting requirements for pipeline side facility grounds) and does not

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cross an offshore area or a waterway (ii) Through facilities located on the currently used for commercial naviga- grounds of a materials transportation tion; terminal if the facilities are used ex- (4) Except for the reporting require- clusively to transfer hazardous liquid ments of subpart B of this part, see or carbon dioxide between non-pipeline § 195.15, transportation of petroleum modes of transportation or between a through an onshore rural gathering non-pipeline mode and a pipeline. line that does not meet the definition These facilities do not include any de- of a ‘‘regulated rural gathering line’’ as vice and associated piping that are nec- provided in § 195.11. This exception does essary to control pressure in the pipe- not apply to gathering lines in the in- line under § 195.406(b); or lets of the Gulf of Mexico subject to (10) Transportation of carbon dioxide § 195.413. downstream from the applicable fol- (5) Transportation of hazardous liq- lowing point: uid or carbon dioxide in an offshore (i) The inlet of a compressor used in pipeline in state waters where the pipe- the injection of carbon dioxide for oil line is located upstream from the out- recovery operations, or the point where let flange of the following farthest recycled carbon dioxide enters the in- downstream facility: The facility jection system, whichever is farther where hydrocarbons or carbon dioxide upstream; or are produced or the facility where pro- (ii) The connection of the first duced hydrocarbons or carbon dioxide branch pipeline in the production field are first separated, dehydrated, or oth- where the pipeline transports carbon erwise processed; dioxide to an injection well or to a header or manifold from which a pipe- (6) Transportation of hazardous liq- line branches to an injection well. uid or carbon dioxide in a pipeline on (c) Breakout tanks. Breakout tanks the OCS where the pipeline is located subject to this Part must comply with upstream of the point at which oper- requirements that apply specifically to ating responsibility transfers from a breakout tanks and, to the extent ap- producing operator to a transporting plicable, with requirements that apply operator; to pipeline systems and pipeline facili- (7) A pipeline segment upstream ties. If a conflict exists between a re- (generally seaward) of the last valve on quirement that applies specifically to the last production facility on the OCS breakout tanks and a requirement that where a pipeline on the OCS is pro- applies to pipeline systems or pipeline ducer-operated and crosses into state facilities, the requirement that applies waters without first connecting to a specifically to breakout tanks prevails. transporting operator’s facility on the Anhydrous ammonia breakout tanks OCS. Safety equipment protecting need not comply with §§ 195.132(b), PHMSA-regulated pipeline segments is 195.205(b), 195.242(c) and (d), 195.264(b) not excluded. A producing operator of a and (e), 195.307, 195.428(c) and (d), and segment falling within this exception 195.432(b) and (c). may petition the Administrator, under § 190.9 of this chapter, for approval to EDITORIAL NOTE: For FEDERAL REGISTER ci- operate under PHMSA regulations gov- tations affecting § 195.1, see the List of CFR Sections Affected, which appears in the erning pipeline design, construction, Finding Aids section of the printed volume operation, and maintenance; and at www.govinfo.gov. (8) Transportation of hazardous liq- uid or carbon dioxide through onshore § 195.2 Definitions. production (including flow lines), refin- As used in this part— ing, or manufacturing facilities or stor- Abandoned means permanently re- age or in-plant piping systems associ- moved from service. ated with such facilities; Administrator means the Adminis- (9) Transportation of hazardous liq- trator, Pipeline and Hazardous Mate- uid or carbon dioxide: rials Safety Administration or his or (i) By vessel, aircraft, tank truck, her delegate. tank car, or other non-pipeline mode of Alarm means an audible or visible transportation; or means of indicating to the controller

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that equipment or processes are out- Gathering line means a pipeline 219.1 side operator-defined, safety-related mm (85⁄8 in) or less nominal outside di- parameters. ameter that transports petroleum from Barrel means a unit of measurement a production facility. equal to 42 U.S. standard gallons. Gulf of Mexico and its inlets means the Breakout tank means a tank used to waters from the mean high water mark (a) relieve surges in a hazardous liquid of the coast of the Gulf of Mexico and pipeline system or (b) receive and store its inlets open to the sea (excluding hazardous liquid transported by a pipe- rivers, tidal marshes, lakes, and ca- line for reinjection and continued nals) seaward to include the territorial transportation by pipeline. sea and Outer Continental Shelf to a Carbon dioxide means a fluid con- depth of 15 feet (4.6 meters), as meas- sisting of more than 90 percent carbon ured from the mean low water. dioxide molecules compressed to a Hazard to navigation means, for the supercritical state. purposes of this part, a pipeline where Component means any part of a pipe- the top of the pipe is less than 12 line which may be subjected to pump inches (305 millimeters) below the un- pressure including, but not limited to, derwater natural bottom (as deter- pipe, valves, elbows, tees, flanges, and mined by recognized and generally ac- closures. cepted practices) in waters less than 15 Computation Pipeline Monitoring feet (4.6 meters) deep, as measured (CPM) means a software-based moni- from the mean low water. toring tool that alerts the pipeline dis- Hazardous liquid means petroleum, patcher of a possible pipeline operating petroleum products, anhydrous ammo- anomaly that may be indicative of a nia, and ethanol or other non-petro- commodity release. leum fuel, including biofuel, which is Confirmed Discovery means when it flammable, toxic, or would be harmful can be reasonably determined, based on to the environment if released in sig- information available to the operator nificant quantities. at the time a reportable event has oc- Highly volatile liquid or HVL means a curred, even if only based on a prelimi- hazardous liquid which will form a nary evaluation. vapor cloud when released to the at- Control room means an operations mosphere and which has a vapor pres- center staffed by personnel charged sure exceeding 276 kPa (40 psia) at 37.8 with the responsibility for remotely °C (100 °F). monitoring and controlling a pipeline In-Line Inspection (ILI) means the in- facility. spection of a pipeline from the interior Controller means a qualified indi- of the pipe using an in-line inspection vidual who remotely monitors and con- tool. Also called intelligent or smart pig- trols the safety-related operations of a ging. pipeline facility via a SCADA system In-Line Inspection Tool or Instru- from a control room, and who has oper- mented Internal Inspection Device means ational authority and accountability a device or vehicle that uses a non-de- for the remote operational functions of structive testing technique to inspect the pipeline facility. the pipeline from the inside. Also Corrosive product means ‘‘corrosive known as intelligent or smart pig. material’’ as defined by § 173.136 Class In-plant piping system means piping 8–Definitions of this chapter. that is located on the grounds of a Exposed underwater pipeline means an plant and used to transfer hazardous underwater pipeline where the top of liquid or carbon dioxide between plant the pipe protrudes above the under- facilities or between plant facilities water natural bottom (as determined and a pipeline or other mode of trans- by recognized and generally accepted portation, not including any device and practices) in waters less than 15 feet associated piping that are necessary to (4.6 meters) deep, as measured from control pressure in the pipeline under mean low water. § 195.406(b). Flammable product means ‘‘flammable Interstate pipeline means a pipeline or liquid’’ as defined by § 173.120 Class 3– that part of a pipeline that is used in Definitions of this chapter. the transportation of hazardous liquids

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or carbon dioxide in interstate or for- Pipe or line pipe means a tube, usu- eign commerce. ally cylindrical, through which a haz- Intrastate pipeline means a pipeline or ardous liquid or carbon dioxide flows that part of a pipeline to which this from one point to another. part applies that is not an interstate Pipeline or pipeline system means all pipeline. parts of a pipeline facility through Line section means a continuous run which a hazardous liquid or carbon di- of pipe between adjacent pressure pump oxide moves in transportation, includ- stations, between a pressure pump sta- ing, but not limited to, line pipe, tion and terminal or breakout tanks, valves, and other appurtenances con- between a pressure pump station and a nected to line pipe, pumping units, fab- block valve, or between adjacent block ricated assemblies associated with valves. pumping units, metering and delivery Low-stress pipeline means a hazardous stations and fabricated assemblies liquid pipeline that is operated in its therein, and breakout tanks. entirety at a stress level of 20 percent Pipeline facility means new and exist- or less of the specified minimum yield ing pipe, rights-of-way and any equip- strength of the line pipe. ment, facility, or building used in the Maximum operating pressure (MOP) transportation of hazardous liquids or means the maximum pressure at which carbon dioxide. a pipeline or segment of a pipeline may Production facility means piping or be normally operated under this part. equipment used in the production, ex- Nominal wall thickness means the wall traction, recovery, lifting, stabiliza- thickness listed in the pipe specifica- tion, separation or treating of petro- tions. leum or carbon dioxide, or associated Offshore means beyond the line of or- storage or measurement. (To be a pro- dinary low water along that portion of duction facility under this definition, the coast of the United States that is piping or equipment must be used in in direct contact with the open seas the process of extracting petroleum or and beyond the line marking the sea- carbon dioxide from the ground or from ward limit of inland waters. facilities where CO2 is produced, and Operator means a person who owns or preparing it for transportation by pipe- operates pipeline facilities. line. This includes piping between Outer Continental Shelf means all sub- treatment plants which extract carbon merged lands lying seaward and out- dioxide, and facilities utilized for the side the area of lands beneath navi- injection of carbon dioxide for recovery gable waters as defined in Section 2 of operations.) the Submerged Lands Act (43 U.S.C. Rural area means outside the limits 1301) and of which the subsoil and sea- of any incorporated or unincorpated bed appertain to the United States and city, town, village, or any other des- are subject to its jurisdiction and con- ignated residential or commercial area trol. such as a subdivision, a business or Person means any individual, firm, shopping center, or community devel- joint venture, partnership, corporation, opment. association, State, municipality, coop- Significant Stress Corrosion Cracking erative association, or joint stock asso- means a stress corrosion cracking ciation, and includes any trustee, re- (SCC) cluster in which the deepest ceiver, assignee, or personal represent- crack, in a series of interacting cracks, ative thereof. is greater than 10% of the wall thick- Petroleum means crude oil, conden- ness and the total interacting length of sate, natural gasoline, natural gas liq- the cracks is equal to or greater than uids, and liquefied petroleum gas. 75% of the critical length of a 50% Petroleum product means flammable, through-wall flaw that would fail at a toxic, or corrosive products obtained stress level of 110% of SMYS. from distilling and processing of crude Specified minimum yield strength oil, unfinished oils, natural gas liquids, means the minimum yield strength, ex- blend stocks and other miscellaneous pressed in p.s.i. (kPa) gage, prescribed hydrocarbon compounds. by the specification under which the

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material is purchased from the manu- available for inspection from several facturer. sources, including the following: Stress level means the level of tangen- (i) The Office of Pipeline Safety, tial or hoop stress, usually expressed as Pipeline and Hazardous Materials Safe- a percentage of specified minimum ty Administration, 1200 New Jersey Av- yield strength. enue SE., Washington, DC 20590. For Supervisory Control and Data Acquisi- more information contact 202–366–4046 tion (SCADA) system means a computer- or go to the PHMSA Web site at: http:// based system or systems used by a con- www.phmsa.dot.gov/pipeline/regs. troller in a control room that collects (ii) The National Archives and and displays information about a pipe- Records Administration (NARA). For line facility and may have the ability to send commands back to the pipeline information on the availability of this facility. material at NARA, call 202–741–6030 or Surge pressure means pressure pro- go to the NARA Web site at: http:// duced by a change in velocity of the www.archives.gov/federallregister/ moving stream that results from shut- codeloflfederallregulations/ ting down a pump station or pumping ibrllocations.html. unit, closure of a valve, or any other (iii) Copies of standards incorporated blockage of the moving stream. by reference in this part can also be Toxic product means ‘‘poisonous ma- purchased from the respective stand- terial’’ as defined by § 173.132 Class 6, ards-developing organization at the ad- Division 6.1–Definitions of this chapter. dresses provided in the centralized IBR Unusually Sensitive Area (USA) means section below. a drinking water or ecological resource (b) American Petroleum Institute area that is unusually sensitive to en- (API), 1220 L Street NW., Washington, vironmental damage from a hazardous DC 20005, and phone: 202–682–8000, Web liquid pipeline release, as identified site: http://api.org/. under § 195.6. (1) API Publication 2026, ‘‘Safe Ac- Welder means a person who performs cess/Egress Involving Floating Roofs of manual or semi-automatic welding. Welding operator means a person who Storage Tanks in Petroleum Service,’’ operates machine or automatic welding 2nd edition, April 1998 (reaffirmed June equipment. 2006) (API Pub 2026), IBR approved for § 195.405(b). [Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 (2) API Recommended Practice 5L1, FR 32721, July 29, 1982] ‘‘Recommended Practice for Railroad EDITORIAL NOTE: For FEDERAL REGISTER ci- Transportation of Line Pipe,’’ 7th edi- tations affecting § 195.2, see the List of CFR tion, September 2009, (API RP 5L1), Sections Affected, which appears in the Finding Aids section of the printed volume IBR approved for § 195.207(a). and at www.govinfo.gov. (3) API Recommended Practice 5LT, ‘‘Recommended Practice for Truck § 195.3 What documents are incor- Transportation of Line Pipe,’’ First porated by reference partly or edition, March 12, 2012, (API RP 5LT), wholly in this part? IBR approved for § 195.207(c). (a) This part prescribes standards, or (4) API Recommended Practice 5LW, portions thereof, incorporated by ref- ‘‘Recommended Practice Transpor- erence into this part with the approval tation of Line Pipe on Barges and Ma- of the Director of the Federal Register rine Vessels,’’ 3rd edition, September in 5 U.S.C. 552(a) and 1 CFR part 51. 2009, (API RP 5LW), IBR approved for The materials listed in this section § 195.207(b). have the full force of law. To enforce any edition other than that specified in (5) ANSI/API Recommended Practice this section, PHMSA must publish a 651, ‘‘Cathodic Protection of Above- notice of change in the FEDERAL REG- ground Petroleum Storage Tanks,’’ 3rd ISTER. edition, January 2007, (ANSI/API RP (1) Availability of standards incor- 651), IBR approved for §§ 195.565 and porated by reference. All of the mate- 195.573(d). rials incorporated by reference are

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(6) ANSI/API Recommended Practice (16) API Standard 510, ‘‘Pressure Ves- 652, ‘‘Linings of Aboveground Petro- sel Inspection Code: In-Service Inspec- leum Storage Tank Bottoms,’’ 3rd edi- tion, Rating, Repair, and Alteration,’’ tion, October 2005, (API RP 652), IBR 9th edition, June 2006, (API Std 510), approved for § 195.579(d). IBR approved for §§ 195.205(b); 195.432(c). (7) API Recommended Practice 1130, (17) API Standard 620, ‘‘Design and ‘‘Computational Pipeline Monitoring Construction of Large, Welded, Low- for Liquids: Pipeline Segment,’’ 3rd Pressure Storage Tanks,’’ 11th edition edition, September 2007, (API RP 1130), February 2008 (including addendum 1 IBR approved for §§ 195.134 and 195.444. (March 2009), addendum 2 (August 2010), (8) API Recommended Practice 1162, and addendum 3 (March 2012)), (API Std ‘‘Public Awareness Programs for Pipe- 620), IBR approved for §§ 195.132(b); line Operators,’’ 1st edition, December 195.205(b); 195.264(b) and (e); 195.307(b); 2003, (API RP 1162), IBR approved for 195.565, 195.579(d). § 195.440(a), (b), and (c). (18) API Standard 650, ‘‘Welded Steel (9) API Recommended Practice 1165, Tanks for Oil Storage,’’ 11th edition, ‘‘Recommended Practice for Pipeline June 2007, effective February 1, 2012, SCADA Displays,’’ First edition, Janu- (including addendum 1 (November 2008), ary 2007, (API RP 1165), IBR approved addendum 2 (November 2009), addendum for § 195.446(c). 3 (August 2011), and errata (October (10) API Recommended Practice 1168, 2011)), (API Std 650), IBR approved for ‘‘Pipeline Control Room Management,’’ §§ 195.132(b); 195.205(b); 195.264(b), (e); First edition, September 2008, (API RP 195.307(c) and (d); 195.565; 195.579(d). 1168), IBR approved for § 195.446(c) and (19) API Standard 653, ‘‘Tank Inspec- (f). tion, Repair, Alteration, and Recon- (11) API Recommended Practice 2003, struction,’’ 3rd edition, December 2001, ‘‘Protection against Ignitions Arising (including addendum 1 (September out of Static, Lightning, and Stray 2003), addendum 2 (November 2005), ad- Currents,’’ 7th edition, January 2008, dendum 3 (February 2008), and errata (API RP 2003), IBR approved for (April 2008)), (API Std 653), IBR ap- § 195.405(a). proved for §§ 195.205(b), 195.307(d), and (12) API Recommended Practice 2350, 195.432(b). ‘‘Overfill Protection for Storage Tanks (20) API Standard 1104, ‘‘Welding of in Petroleum Facilities,’’ 3rd edition, Pipelines and Related Facilities,’’ 20th January 2005, (API RP 2350), IBR ap- edition, October 2005, (including errata/ proved for § 195.428(c). addendum (July 2007) and errata 2 (13) API Specification 5L, ‘‘Speci- (2008), (API Std 1104)), IBR approved for fication for Line Pipe,’’ 45th edition, ef- §§ 195.214(a), 195.222(a) and (b), 195.228(b). fective July 1, 2013, (ANSI/API Spec (21) ANSI/API Standard 2000, ‘‘Vent- 5L), IBR approved for § 195.106(b) and ing Atmospheric and Low-pressure (e). Storage Tanks,’’ 6th edition, November (14) ANSI/API Specification 6D, 2009, (ANSI/API Std 2000), IBR approved ‘‘Specification for Pipeline Valves,’’ for § 195.264(e). 23rd edition, effective October 1, 2008, (22) API Standard 2510, ‘‘Design and (including Errata 1 (June 2008), Errata Construction of LPG Installations,’’ 2 (November 2008), Errata 3 (February 8th edition, 2001, (API Std 2510), IBR 2009), Errata 4 (April 2010), Errata 5 approved for §§ 195.132(b), 195.205(b), (November 2010), and Errata 6 (August 195.264 (b), (e); 195.307 (e), 195.428 (c); 2011); Addendum 1 (October 2009), Ad- and 195.432 (c). dendum 2 (August 2011), and Addendum (23) API Standard 1163, ‘‘In-Line In- 3 (October 2012)); (ANSI/API Spec 6D), spection Systems Qualification’’ Sec- IBR approved for § 195.116(d). ond edition, April 2013, (API Std 1163), (15) API Specification 12F, ‘‘Speci- IBR approved for § 195.591. fication for Shop Welded Tanks for (c) ASME International (ASME), Two Storage of Production Liquids,’’ 12th Park Avenue, New York, NY 10016, 800– edition, October 2008, effective April 1, 843–2763 (U.S/Canada), Web site: http:// 2009, (API Spec 12F), IBR approved for www.asme.org/. §§ 195.132(b); 195.205(b); 195.264(b) and (e); (1) ASME/ANSI B16.9–2007, ‘‘Factory- 195.307(a); 195.565; 195.579(d). Made Wrought Buttwelding Fittings,’’

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December 7, 2007, (ASME/ANSI B16.9), (2) ASTM A106/A106M–10, ‘‘Standard IBR approved for § 195.118(a). Specification for Seamless Carbon (2) ASME/ANSI B31G–1991 (Re- Steel Pipe for High-Temperature Serv- affirmed 2004), ‘‘Manual for Deter- ice,’’ approved April 1, 2010, (ASTM mining the Remaining Strength of Cor- A106/A106M), IBR approved for roded Pipelines,’’ 2004, (ASME/ANSI § 195.106(e). B31G), IBR approved for §§ 195.452(h); (3) ASTM A333/A333M–11, ‘‘Standard 195.587; and 195.588(c). Specification for Seamless and Welded (3) ASME/ANSI B31.4–2006, ‘‘Pipeline Steel Pipe for Low-Temperature Serv- Transportation Systems for Liquid Hy- ice,’’ approved April 1, 2011, (ASTM drocarbons and Other Liquids’’ October A333/A333M), IBR approved for 20, 2006, (ASME/ANSI B31.4), IBR ap- § 195.106(e). proved for §§ 195.110(a); 195.452(h). (4) ASTM A381–96 (Reapproved 2005), (4) ASME/ANSI B31.8–2007, ‘‘Gas ‘‘Standard Specification for Metal-Arc Transmission and Distribution Piping Welded Steel Pipe for Use with High- Systems,’’ November 30, 2007, (ASME/ Pressure Transmission Systems,’’ ap- ANSI B31.8), IBR approved for §§ 195.5(a) proved October 1, 2005, (ASTM A381), and 195.406(a). IBR approved for § 195.106(e). (5) ASME Boiler & Pressure Vessel (5) ASTM A671/A671M–10, ‘‘Standard Code, Section VIII, Division 1, ‘‘Rules Specification for Electric-Fusion-Weld- for Construction of Pressure Vessels,’’ ed Steel Pipe for Atmospheric and 2007 edition, July 1, 2007, (ASME BPVC, Lower Temperatures,’’ approved April Section VIII, Division 1), IBR approved 1, 2010, (ASTM A671/A671M), IBR ap- for §§ 195.124 and 195.307(e). proved for § 195.106(e). (6) ASME Boiler & Pressure Vessel (6) ASTM A672/A672M–09, ‘‘Standard Code, Section VIII, Division 2, ‘‘Alter- Specification for Electric-Fusion-Weld- nate Rules, Rules for Construction of ed Steel Pipe for High-Pressure Service Pressure Vessels,’’ 2007 edition, July 1, at Moderate Temperatures,’’ approved 2007, (ASME BPVC, Section VIII, Divi- October 1, 2009, (ASTM A672/A672M), sion 2), IBR approved for § 195.307(e). IBR approved for § 195.106(e). (7) ASME Boiler & Pressure Vessel (7) ASTM A691/A691M–09, ‘‘Standard Code, Section IX: ‘‘Qualification Specification for Carbon and Alloy Standard for Welding and Brazing Pro- Steel Pipe, Electric-Fusion-Welded for cedures, Welders, Brazers, and Welding High-Pressure Service at High Tem- and Brazing Operators,’’ 2007 edition, peratures,’’ approved October 1, 2009, July 1, 2007, (ASME BPVC, Section IX), (ASTM A691), IBR approved for IBR approved for § 195.222(a). § 195.106(e). (d) American Society for Non- (f) Manufacturers Standardization destructive Testing, P.O. Box 28518, Society of the Valve and Fittings In- 1711 Arlingate Lane, Columbus, OH dustry, Inc. (MSS), 127 Park St. NE., 43228. https://asnt.org. Vienna, VA 22180, phone: 703–281–6613, (1) ANSI/ASNT ILI–PQ–2005(2010), Web site: http://www.mss-hq.org/. ‘‘In-line Inspection Personnel Quali- (1) MSS SP–75–2008 Standard Prac- fication and Certification’’ reapproved tice, ‘‘Specification for High-Test, October 11, 2010, (ANSI/ASNT ILI–PQ), Wrought, Butt-Welding Fittings,’’ 2008 IBR approved for § 195.591. edition, (MSS SP 75), IBR approved for (2) [Reserved] § 195.118(a). (e) American Society for Testing and (2) [Reserved] Materials (ASTM), 100 Barr Harbor (g) NACE International (NACE), 1440 Drive, P.O. Box C700, West South Creek Drive, Houston, TX 77084, Conshohocken, PA 119428, phone: 610– phone: 281–228–6223 or 800–797–6223, Web 832–9585, Web site: http://www.astm.org/. site: http://www.nace.org/Publications/. (1) ASTM A53/A53M–10, ‘‘Standard (1) NACE SP0169–2007, Standard Prac- Specification for Pipe, Steel, Black and tice, ‘‘Control of External Corrosion on Hot-Dipped, Zinc-Coated, Welded and Underground or Submerged Metallic Seamless,’’ approved October 1, 2010, Piping Systems’’ reaffirmed March 15, (ASTM A53/A53M), IBR approved for 2007, (NACE SP0169), IBR approved for § 195.106(e). §§ 195.571 and 195.573(a).

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(2) ANSI/NACE SP0502–2010, Standard § 195.5 Conversion to service subject Practice, ‘‘Pipeline External Corrosion to this part. Direct Assessment Methodology,’’ June (a) A steel pipeline previously used in 24, 2010, (NACE SP0502), IBR approved service not subject to this part quali- for § 195.588(b). fies for use under this part if the oper- (3) NACE SP0102–2010, ‘‘Standard ator prepares and follows a written Practice, Inline Inspection of Pipe- procedure to accomplish the following: lines’’ revised March 13, 2010, (NACE (1) The design, construction, oper- SP0102), IBR approved for §§ 195.120 and ation, and maintenance history of the 195.591. pipeline must be reviewed and, where (4) NACE SP0204–2008, ‘‘Standard sufficient historical records are not Practice, Stress Corrosion Cracking available, appropriate tests must be (SSC) Direct Assessment Methodology’’ performed to determine if the pipeline reaffirmed September 18, 2008, (NACE is in satisfactory condition for safe op- SP0204), IBR approved for § 195.588(c). eration. If one or more of the variables (h) National Fire Protection Associa- necessary to verify the design pressure tion (NFPA), 1 Batterymarch Park, under § 195.106 or to perform the testing Quincy, MA 02169, phone: 617–984–7275, under paragraph (a)(4) of this section is Web site: http://www.nfpa.org/. unknown, the design pressure may be (1) NFPA–30 (2012), ‘‘Flammable and verified and the maximum operating Combustible Liquids Code,’’ including pressure determined by— Errata 30–12–1 (9/27/11), and Errata 30– (i) Testing the pipeline in accordance 12–2 (11/14/11), 2012 edition, copyright with ASME/ANSI B31.8 (incorporated by reference, § 195.3), Appendix N, to 2011, (NFPA–30), IBR approved for see produce a stress equal to the yield § 195.264(b). strength; and (2) [Reserved] (ii) Applying, to not more than 80 (i) Pipeline Research Council Inter- percent of the first pressure that pro- national, Inc. (PRCI), c/o Technical duces a yielding, the design factor F in Toolboxes, 3801 Kirby Drive, Suite 520, § 195.106(a) and the appropriate factors P.O. Box 980550, Houston, TX 77098, in § 195.106(e). phone: 713–630–0505, toll free: 866–866– (2) The pipeline right-of-way, all 6766, Web site: http://www.ttoolboxes.com/ aboveground segments of the pipeline, . and appropriately selected under- (1) AGA Pipeline Research Com- ground segments must be visually in- mittee, Project PR–3–805 ‘‘A Modified spected for physical defects and oper- Criterion for Evaluating the Remain- ating conditions which reasonably ing Strength of Corroded Pipe,’’ De- could be expected to impair the cember 22, 1989, (PR–3–805 (RSTRING)). strength or tightness of the pipeline. IBR approved for §§ 195.452(h); 195.587; (3) All known unsafe defects and con- and 195.588(c). ditions must be corrected in accord- (2) [Reserved] ance with this part. (4) The pipeline must be tested in ac- [Amdt. 195–99, 80 FR 184, Jan. 5, 2015, as cordance with subpart E of this part to amended by Amdt. 195–101, 82 FR 7998, Jan. 23, 2017; Amdt. 195–102, 84 FR 52294, Oct. 1, substantiate the maximum operating 2019] pressure permitted by § 195.406. (b) A pipeline that qualifies for use § 195.4 Compatibility necessary for under this section need not comply transportation of hazardous liquids with the corrosion control require- or carbon dioxide. ments of subpart H of this part until 12 No person may transport any haz- months after it is placed into service, ardous liquid or carbon dioxide unless notwithstanding any previous dead- the hazardous liquid or carbon dioxide lines for compliance. is chemically compatible with both the (c) Each operator must keep for the pipeline, including all components, and life of the pipeline a record of the in- vestigations, tests, repairs, replace- any other commodity that it may come ments, and alterations made under the into contact with while in the pipeline. requirements of paragraph (a) of this [Amdt. 195–45, 56 FR 26925, June 12, 1991] section.

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(d) An operator converting a pipeline most viable, highest quality, or in the from service not previously covered by best condition, as identified by an ele- this part must notify PHMSA 60 days ment occurrence ranking (EORANK) of before the conversion occurs as re- A (excellent quality) or B (good qual- quired by § 195.64. ity). [Amdt. 195–22, 46 FR 38360, July 27, 1981, as (c) As used in this part— amended by Amdt. 195–52, 59 FR 33396, June Adequate Alternative Drinking Water 28, 1994; Amdt. 195–173, 66 FR 67004, Dec. 27, Source means a source of water that 2001; Amdt. 195–99, 80 FR 184, Jan. 5, 2015; currently exists, can be used almost Amdt. 195–101, 82 FR 7999, Jan. 23, 2017] immediately with a minimal amount of § 195.6 Unusually Sensitive Areas effort and cost, involves no decline in (USAs). water quality, and will meet the con- sumptive, hygiene, and fire fighting re- As used in this part, a USA means a quirements of the existing population drinking water or ecological resource area that is unusually sensitive to en- of impacted customers for at least one vironmental damage from a hazardous month for a surface water source of liquid pipeline release. water and at least six months for a (a) An USA drinking water resource groundwater source. is: Aquatic or Aquatic Dependent Species (1) The water intake for a Commu- or Community means a species or com- nity Water System (CWS) or a Non- munity that primarily occurs in aquat- transient Non-community Water Sys- ic, marine, or wetland habitats, as well tem (NTNCWS) that obtains its water as species that may use terrestrial supply primarily from a surface water habitats during all or some portion of source and does not have an adequate their life cycle, but that are still close- alternative drinking water source; ly associated with or dependent upon (2) The Source Water Protection Area aquatic, marine, or wetland habitats (SWPA) for a CWS or a NTNCWS that for some critical component or portion obtains its water supply from a Class I of their life-history (i.e., reproduction, or Class IIA aquifer and does not have rearing and development, feeding, etc). an adequate alternative drinking water Class I Aquifer means an aquifer that source. Where a state has not yet iden- is surficial or shallow, permeable, and tified the SWPA, the Wellhead Protec- is highly vulnerable to contamination. tion Area (WHPA) will be used until Class I aquifers include: the state has identified the SWPA; or (1) Unconsolidated Aquifers (Class Ia) (3) The sole source aquifer recharge that consist of surficial, unconsoli- area where the sole source aquifer is a dated, and permeable alluvial, terrace, karst aquifer in nature. outwash, beach, dune and other similar (b) An USA ecological resource is: deposits. These aquifers generally con- (1) An area containing a critically imperiled species or ecological commu- tain layers of sand and gravel that, nity; commonly, are interbedded to some de- (2) A multi-species assemblage area; gree with silt and clay. Not all Class Ia (3) A migratory waterbird concentra- aquifers are important water-bearing tion area; units, but they are likely to be both (4) An area containing an imperiled permeable and vulnerable. The only species, threatened or endangered spe- natural protection of these aquifers is cies, depleted marine mammal species, the thickness of the unsaturated zone or an imperiled ecological community and the presence of fine-grained mate- where the species or community is rial; aquatic, aquatic dependent, or terres- (2) Soluble and Fractured Bedrock trial with a limited range; or Aquifers (Class Ib). Lithologies in this (5) An area containing an imperiled class include limestone, dolomite, and, species, threatened or endangered spe- locally, evaporitic units that contain cies, depleted marine mammal species, documented karst features or solution or imperiled ecological community channels, regardless of size. Generally where the species or community occur- these aquifers have a wide range of per- rence is considered to be one of the meability. Also included in this class

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are sedimentary strata, and meta- maining individuals (less than 1,000) or morphic and igneous (intrusive and ex- acres (less than 2,000). These species trusive) rocks that are significantly and ecological communities are ex- faulted, fractured, or jointed. In all tremely vulnerable to extinction due to cases groundwater movement is largely some natural or man-made factor. controlled by secondary openings. Well Depleted marine mammal species means yields range widely, but the important a species that has been identified and is feature is the potential for rapid protected under the Marine Mammal vertical and lateral ground water Protection Act of 1972, as amended movement along preferred pathways, (MMPA) (16 U.S.C. 1361 et seq.). The which result in a high degree of vulner- term ‘‘depleted’’ refers to marine mam- ability; mal species that are listed as threat- (3) Semiconsolidated Aquifers (Class ened or endangered, or are below their Ic) that generally contain poorly to optimum sustainable populations (16 moderately indurated sand and gravel U.S.C. 1362). The term ‘‘marine mam- that is interbedded with clay and silt. mal’’ means ‘‘any mammal which is This group is intermediate to the un- morphologically adapted to the marine consolidated and consolidated end environment (including sea otters and members. These systems are common members of the orders Sirenia, in the Tertiary age rocks that are ex- Pinnipedia, and Cetacea), or primarily posed throughout the Gulf and Atlantic inhabits the marine environment (such coastal states. Semiconsolidated condi- as the polar bear)’’ (16 U.S.C. 1362). The tions also arise from the presence of order Sirenia includes manatees, the intercalated clay and caliche within order Pinnipedia includes seals, sea primarily unconsolidated to poorly lions, and walruses, and the order Ceta- consolidated units, such as occurs in cea includes dolphins, porpoises, and parts of the High Plains Aquifer; or whales. (4) Covered Aquifers (Class Id) that Ecological community means an inter- are any Class I aquifer overlain by less acting assemblage of plants and ani- than 50 feet of low permeability, un- mals that recur under similar environ- consolidated material, such as glacial mental conditions across the land- till, lacustrian, and loess deposits. scape. Class IIa aquifer means a Higher Yield Bedrock Aquifer that is consolidated Element occurrence rank (EORANK) and is moderately vulnerable to con- means the condition or viability of a tamination. These aquifers generally species or ecological community occur- consist of fairly permeable sandstone rence, based on a population’s size, or conglomerate that contain lesser condition, and landscape context. amounts of interbedded fine grained EORANKs are assigned by the Natural clastics (shale, siltstone, mudstone) Heritage Programs. An EORANK of A and occasionally carbonate units. In means an excellent quality and an general, well yields must exceed 50 gal- EORANK of B means good quality. lons per minute to be included in this Imperiled species or ecological commu- class. Local fracturing may contribute nity (habitat) means a rare species or to the dominant primary porosity and ecological community, based on The permeability of these systems. Nature Conservancy’s Global Conserva- Community Water System (CWS) means tion Status Rank. There are generally a public water system that serves at 6 to 20 occurrences, or few remaining least 15 service connections used by individuals (1,000 to 3,000) or acres year-round residents of the area or reg- (2,000 to 10,000). These species and eco- ularly serves at least 25 year-round logical communities are vulnerable to residents. extinction due to some natural or man- Critically imperiled species or ecological made factor. community (habitat) means an animal or Karst aquifer means an aquifer that is plant species or an ecological commu- composed of limestone or dolomite nity of extreme rarity, based on The where the porosity is derived from con- Nature Conservancy’s Global Conserva- nected solution cavities. Karst aquifers tion Status Rank. There are generally are often cavernous with high rates of 5 or fewer occurrences, or very few re- flow.

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Migratory waterbird concentration area one composed of limestone where the means a designated Ramsar site or a porosity is derived from connected so- Western Hemisphere Shorebird Reserve lution cavities. They are often cav- Network site. ernous, with high rates of flow. Multi-species assemblage area means Source Water Protection Area (SWPA) an area where three or more different means the area delineated by the state critically imperiled or imperiled spe- for a public water supply system (PWS) cies or ecological communities, threat- or including numerous PWSs, whether ened or endangered species, depleted the source is ground water or surface marine mammals, or migratory water or both, as part of the state waterbird concentrations co-occur. source water assessment program Non-transient Non-community Water (SWAP) approved by EPA under sec- System (NTNCWS) means a public water tion 1453 of the Safe Drinking Water system that regularly serves at least 25 Act. of the same persons over six months Species means species, subspecies, per year. Examples of these systems in- population stocks, or distinct clude schools, factories, and hospitals vertebrate populations. that have their own water supplies. Terrestrial ecological community with a Public Water System (PWS) means a limited range means a non-aquatic or system that provides the public water non-aquatic dependent ecological com- for human consumption through pipes munity that covers less than five (5) or other constructed conveyances, if acres. such system has at least 15 service con- nections or regularly serves an average Terrestrial species with a limited range of at least 25 individuals daily at least means a non-aquatic or non-aquatic de- 60 days out of the year. These systems pendent animal or plant species that include the sources of the water sup- has a range of no more than five (5) plies—i.e., surface or ground. PWS can acres. be community, non-transient non-com- Threatened and endangered species munity, or transient non-community (T&E) means an animal or plant spe- systems. cies that has been listed and is pro- Ramsar site means a site that has tected under the Endangered Species been designated under The Convention Act of 1973, as amended (ESA73) (16 on Wetlands of International Impor- U.S.C. 1531 et seq.). ‘‘Endangered spe- tance Especially as Waterfowl Habitat cies’’ is defined as ‘‘any species which program. Ramsar sites are globally is in danger of extinction throughout critical wetland areas that support mi- all or a significant portion of its gratory waterfowl. These include wet- range’’ (16 U.S.C. 1532). ‘‘Threatened land areas that regularly support 20,000 species’’ is defined as ‘‘any species waterfowl; wetland areas that regu- which is likely to become an endan- larly support substantial numbers of gered species within the foreseeable fu- individuals from particular groups of ture throughout all or a significant waterfowl, indicative of wetland val- portion of its range’’ (16 U.S.C. 1532). ues, productivity, or diversity; and Transient Non-community Water System wetland areas that regularly support (TNCWS) means a public water system 1% of the individuals in a population of that does not regularly serve at least one species or subspecies of waterfowl. 25 of the same persons over six months Sole source aquifer (SSA) means an per year. This type of water system area designated by the U.S. Environ- serves a transient population found at mental Protection Agency under the rest stops, campgrounds, restaurants, Sole Source Aquifer program as the and parks with their own source of ‘‘sole or principal’’ source of drinking water. water for an area. Such designations Wellhead Protection Area (WHPA) are made if the aquifer’s ground water means the surface and subsurface area supplies 50% or more of the drinking surrounding a well or well field that water for an area, and if that aquifer supplies a public water system through were to become contaminated, it would which contaminants are likely to pass pose a public health hazard. A sole and eventually reach the water well or source aquifer that is karst in nature is well field.

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Western Hemisphere Shorebird Reserve ating responsibility transfers to a pro- Network (WHSRN) site means an area ducing operator. For those instances in that contains migratory shorebird con- which the transfer points are not iden- centrations and has been designated as tifiable by a durable marking, each op- a hemispheric reserve, international erator will have until September 15, reserve, regional reserve, or endan- 1998 to identify the transfer points. If it gered species reserve. Hemispheric re- is not practicable to durably mark a serves host at least 500,000 shorebirds transfer point and the transfer point is annually or 30% of a species flyway located above water, the operator must population. International reserves host depict the transfer point on a sche- 100,000 shorebirds annually or 15% of a matic maintained near the transfer species flyway population. Regional re- point. If a transfer point is located serves host 20,000 shorebirds annually subsea, the operator must identify the or 5% of a species flyway population. transfer point on a schematic which Endangered species reserves are crit- must be maintained at the nearest up- ical to the survival of endangered spe- stream facility and provided to PHMSA cies and no minimum number of birds upon request. For those cases in which is required. adjoining operators have not agreed on [Amdt. 195–71, 65 FR 80544, Dec. 21, 2000] a transfer point by September 15, 1998 the Regional Director and the MMS § 195.8 Transportation of hazardous Regional Supervisor will make a joint liquid or carbon dioxide in pipe- lines constructed with other than determination of the transfer point. steel pipe. [Amdt. 195–59, 62 FR 61695, Nov. 19, 1997, as No person may transport any haz- amended at 70 FR 11140, Mar. 8, 2005] ardous liquid or carbon dioxide through a pipe that is constructed after October § 195.10 Responsibility of operator for 1, 1970, for hazardous liquids or after compliance with this part. July 12, 1991 for carbon dioxide of ma- An operator may make arrangements terial other than steel unless the per- with another person for the perform- son has notified the Administrator in ance of any action required by this writing at least 90 days before the part. However, the operator is not transportation is to begin. The notice thereby relieved from the responsi- must state whether carbon dioxide or a bility for compliance with any require- hazardous liquid is to be transported ment of this part. and the chemical name, common name, properties and characteristics of the § 195.11 What is a regulated rural hazardous liquid to be transported and gathering line and what require- the material used in construction of ments apply? the pipeline. If the Administrator de- Each operator of a regulated rural termines that the transportation of the gathering line, as defined in paragraph hazardous liquid or carbon dioxide in (a) of this section, must comply with the manner proposed would be unduly hazardous, he will, within 90 days after the safety requirements described in receipt of the notice, order the person paragraph (b) of this section. that gave the notice, in writing, not to (a) Definition. As used in this section, transport the hazardous liquid or car- a regulated rural gathering line means bon dioxide in the proposed manner an onshore gathering line in a rural until further notice. area that meets all of the following cri- teria— [Amdt. 195–45, 56 FR 26925, June 12, 1991, as (1) Has a nominal diameter from 65⁄8 amended by Amdt. 195–50, 59 FR 17281, Apr. 5 12, 1994] inches (168 mm) to 8 ⁄8 inches (219.1 mm); § 195.9 Outer continental shelf pipe- (2) Is located in or within one-quarter lines. mile (.40 km) of an unusually sensitive Operators of transportation pipelines area as defined in § 195.6; and on the Outer Continental Shelf must (3) Operates at a maximum pressure identify on all their respective pipe- established under § 195.406 cor- lines the specific points at which oper- responding to—

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(i) A stress level greater than 20-per- isting on July 3, 2008 before July 3, cent of the specified minimum yield 2011. strength of the line pipe; or (10) For steel pipelines, establish and (ii) If the stress level is unknown or follow a comprehensive and effective the pipeline is not constructed with program to continuously identify oper- steel pipe, a pressure of more than 125 ating conditions that could contribute psi (861 kPa) gage. to internal corrosion. The program (b) Safety requirements. Each operator must include measures to prevent and must prepare, follow, and maintain mitigate internal corrosion, such as written procedures to carry out the re- cleaning the pipeline and using inhibi- quirements of this section. Except for tors. This program must be established the requirements in paragraphs (b)(2), before transportation begins or if the (b)(3), (b)(9) and (b)(10) of this section, pipeline exists on July 3, 2008, before the safety requirements apply to all July 3, 2009. materials of construction. (11) To comply with the Operator (1) Identify all segments of pipeline Qualification program requirements in meeting the criteria in paragraph (a) of subpart G of this part, have a written this section before April 3, 2009. description of the processes used to (2) For steel pipelines constructed, carry out the requirements in § 195.505 replaced, relocated, or otherwise to determine the qualification of per- changed after July 3, 2009, design, in- stall, construct, initially inspect, and sons performing operations and main- initially test the pipeline in compli- tenance tasks. These processes must be ance with this part, unless the pipeline established before transportation be- is converted under § 195.5. gins or if the pipeline exists on July 3, (3) For non-steel pipelines con- 2008, before July 3, 2009. structed after July 3, 2009, notify the (c) New unusually sensitive areas. If, Administrator according to § 195.8. after July 3, 2008, a new unusually sen- (4) Beginning no later than January sitive area is identified and a segment 3, 2009, comply with the reporting re- of pipeline becomes regulated as a re- quirements in subpart B of this part. sult, except for the requirements of (5) Establish the maximum operating paragraphs (b)(9) and (b)(10) of this sec- pressure of the pipeline according to tion, the operator must implement the § 195.406 before transportation begins, requirements in paragraphs (b)(2) or if the pipeline exists on July 3, 2008, through (b)(11) of this section for the before July 3, 2009. affected segment within 6 months of (6) Install line markers according to identification. For steel pipelines, com- § 195.410 before transportation begins, ply with the deadlines in paragraph or if the pipeline exists on July 3, 2008, (b)(9) and (b)(10). before July 3, 2009. Continue to main- (d) Record Retention. An operator tain line markers in compliance with must maintain records demonstrating § 195.410. compliance with each requirement ac- (7) Establish a continuing public edu- cording to the following schedule. cation program in compliance with (1) An operator must maintain the § 195.440 before transportation begins, segment identification records required or if the pipeline exists on July 3, 2008, in paragraph (b)(1) of this section and before January 3, 2010. Continue to the records required to comply with carry out such program in compliance (b)(10) of this section, for the life of the with § 195.440. pipe. (8) Establish a damage prevention (2) An operator must maintain the program in compliance with § 195.442 records necessary to demonstrate com- before transportation begins, or if the pliance with each requirement in para- pipeline exists on July 3, 2008, before graphs (b)(2) through (b)(9), and (b)(11) July 3, 2009. Continue to carry out such of this section according to the record program in compliance with § 195.442. retention requirements of the ref- (9) For steel pipelines, comply with erenced section or subpart. subpart H of this part, except corrosion control is not required for pipelines ex- [73 FR 31644, June 3, 2008]

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§ 195.12 What requirements apply to sitive area (USA) as defined in § 195.6; low-stress pipelines in rural areas? and (a) General. This Section sets forth (ii) Operates at a maximum pressure the requirements for each category of established under § 195.406 cor- low-stress pipeline in a rural area set responding to a stress level equal to or forth in paragraph (b) of this Section. less than 20-percent of the specified This Section does not apply to a rural minimum yield strength of the line low-stress pipeline regulated under this pipe; or Part as a low-stress pipeline that (iii) If the stress level is unknown or crosses a waterway currently used for the pipeline is not constructed with commercial navigation; these pipelines steel pipe, a pressure equal to or less are regulated pursuant to § 195.1(a)(2). than 125 psi (861 kPa) gage. (b) Categories. An operator of a rural (c) Applicable requirements and dead- low-stress pipeline must meet the ap- lines for compliance. An operator must plicable requirements and compliance comply with the following compliance deadlines for the category of pipeline dates depending on the category of set forth in paragraph (c) of this Sec- pipeline determined by the criteria in tion. For purposes of this Section, a paragraph (b): rural low-stress pipeline is a Category (1) An operator of a Category 1 pipe- 1, 2, or 3 pipeline based on the following line must: criteria: (i) Identify all segments of pipeline (1) A Category 1 rural low-stress pipe- meeting the criteria in paragraph (b)(1) line: of this Section before April 3, 2009. (i) Has a nominal diameter of 85⁄8 (ii) Beginning no later than January inches (219.1 mm) or more; 3, 2009, comply with the reporting re- (ii) Is located in or within one-half quirements of Subpart B for the identi- mile (.80 km) of an unusually sensitive fied segments. area (USA) as defined in § 195.6; and (iii) IM requirements— (iii) Operates at a maximum pressure (A) Establish a written program that established under § 195.406 cor- complies with § 195.452 before July 3, responding to: 2009, to assure the integrity of the pipe- (A) A stress level equal to or less line segments. Continue to carry out than 20-percent of the specified min- such program in compliance with imum yield strength of the line pipe; or § 195.452. (B) If the stress level is unknown or (B) An operator may conduct a deter- the pipeline is not constructed with mination per § 195.452(a) in lieu of the steel pipe, a pressure equal to or less one-half mile buffer. than 125 psi (861 kPa) gauge. (C) Complete the baseline assessment (2) A Category 2 rural pipeline: (i) Has a nominal diameter of less of all segments in accordance with § 195.452(c) before July 3, 2015, and com- than 85⁄8 inches (219.1mm); (ii) Is located in or within one-half plete at least 50-percent of the assess- mile (.80 km) of an unusually sensitive ments, beginning with the highest risk area (USA) as defined in § 195.6; and pipe, before January 3, 2012. (iii) Operates at a maximum pressure (iv) Comply with all other safety re- established under § 195.406 cor- quirements of this Part, except Sub- responding to: part H, before July 3, 2009. Comply with (A) A stress level equal to or less the requirements of Subpart H before than 20-percent of the specified min- July 3, 2011. imum yield strength of the line pipe; or (2) An operator of a Category 2 pipe- (B) If the stress level is unknown or line must: the pipeline is not constructed with (i) Identify all segments of pipeline steel pipe, a pressure equal to or less meeting the criteria in paragraph (b)(2) than 125 psi (861 kPa) gage. of this Section before July 1, 2012. (3) A Category 3 rural low-stress pipe- (ii) Beginning no later than January line: 3, 2009, comply with the reporting re- (i) Has a nominal diameter of any quirements of Subpart B for the identi- size and is not located in or within one- fied segments. half mile (.80 km) of an unusually sen- (iii) IM—

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(A) Establish a written IM program the estimated amount of production that complies with § 195.452 before Oc- from affected wells per year, whether tober 1, 2012 to assure the integrity of wells will be shut in or alternate trans- the pipeline segments. Continue to portation used, and if alternate trans- carry out such program in compliance portation will be used, the estimated with § 195.452. cost to do so. (B) An operator may conduct a deter- (3) When an operator notifies PHMSA mination per § 195.452(a) in lieu of the in accordance with paragraph (d)(1) of one-half mile buffer. this Section, PHMSA will stay compli- (C) Complete the baseline assessment ance with §§ 195.452(d) and 195.452(j)(3) of all segments in accordance with until it has completed an analysis of § 195.452(c) before October 1, 2016 and the notification. PHMSA will consult complete at least 50-percent of the as- the Department of Energy, as appro- sessments, beginning with the highest priate, to help analyze the potential risk pipe, before April 1, 2014. energy impact of loss of the pipeline. (iv) Comply with all other safety re- Based on the analysis, PHMSA may quirements of this Part, except Sub- grant the operator a special permit to part H, before October 1, 2012. Comply allow continued operation of the pipe- with Subpart H of this Part before Oc- line subject to alternative safety re- tober 1, 2014. quirements. (3) An operator of a Category 3 pipe- (e) Changes in unusually sensitive line must: areas. (1) If, after June 3, 2008, for Cat- (i) Identify all segments of pipeline egory 1 rural low-stress pipelines or Oc- meeting the criteria in paragraph (b)(3) tober 1, 2011 for Category 2 rural low- of this Section before July 1, 2012. stress pipelines, an operator identifies (ii) Beginning no later than January a new USA that causes a segment of 3, 2009, comply with the reporting re- pipeline to meet the criteria in para- quirements of Subpart B for the identi- graph (b) of this Section as a Category fied segments. 1 or Category 2 rural low-stress pipe- (A)(iii) Comply with all safety re- line, the operator must: quirements of this Part, except the re- (i) Comply with the IM program re- quirements in § 195.452, Subpart B, and quirement in paragraph (c)(1)(iii)(A) or the requirements in Subpart H, before (c)(2)(iii)(A) of this Section, as appro- October 1, 2012. Comply with Subpart H priate, within 12 months following the of this Part before October 1, 2014. date the area is identified regardless of (d) Economic compliance burden. (1) An the prior categorization of the pipeline; operator may notify PHMSA in accord- and ance with § 195.452(m) of a situation (ii) Complete the baseline assessment meeting the following criteria: required by paragraph (c)(1)(iii)(C) or (i) The pipeline is a Category 1 rural (c)(2)(iii)(C) of this Section, as appro- low-stress pipeline; priate, according to the schedule in (ii) The pipeline carries crude oil § 195.452(d)(3). from a production facility; (2) If a change to the boundaries of a (iii) The pipeline, when in operation, USA causes a Category 1 or Category 2 operates at a flow rate less than or pipeline segment to no longer be within equal to 14,000 barrels per day; and one-half mile of a USA, an operator (iv) The operator determines it would must continue to comply with para- abandon or shut-down the pipeline as a graph (c)(1)(iii) or paragraph (c)(2)(iii) result of the economic burden to com- of this section, as applicable, with re- ply with the assessment requirements spect to that segment unless the oper- in § 195.452(d) or 195.452(j). ator determines that a release from the (2) A notification submitted under pipeline could not affect the USA. this provision must include, at min- (f) Record Retention. An operator imum, the following information about must maintain records demonstrating the pipeline: its operating, mainte- compliance with each requirement ap- nance and leak history; the estimated plicable to the category of pipeline ac- cost to comply with the integrity as- cording to the following schedule. sessment requirements (with a brief de- (1) An operator must maintain the scription of the basis for the estimate); segment identification records required

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in paragraph (c)(1)(i), (c)(2)(i) or (b) Implementation period—(1) Annual (c)(3)(i) of this Section for the life of reporting. Operators must comply with the pipe. the annual reporting requirements in (2) Except for the segment identifica- subpart B of this part by March 31, tion records, an operator must main- 2021. tain the records necessary to dem- (2) Accident and safety-related condi- onstrate compliance with each applica- tion reporting. Operators must comply ble requirement set forth in paragraph with the accident and safety-related (c) of this section according to the condition reporting requirements in record retention requirements of the subpart B of this part by January 1, referenced section or subpart. 2021. [76 FR 25587, May 5, 2011, as amended at 76 (c) Exceptions. (1) This section does FR 43605, July 21, 2011] not apply to those gathering lines that are otherwise excepted under § 195.13 What requirements apply to § 195.1(b)(3), (7), (8), (9), or (10). pipelines transporting hazardous (2) The reporting requirements in liquids by gravity? §§ 195.52, 195.61, and 195.65 do not apply (a) Scope. Pipelines transporting haz- to the transportation of a hazardous ardous liquids by gravity must comply liquid in a gathering line that is speci- with the reporting requirements of sub- fied in paragraph (a) of this section. part B of this part. (3) The drug and alcohol testing re- (b) Implementation period—(1) Annual quirements in part 199 of this sub- reporting. Comply with the annual re- chapter do not apply to the transpor- porting requirements in subpart B of tation of a hazardous liquid in a gath- this part by March 31, 2021. ering line that is specified in paragraph (2) Accident and safety-related report- (a) of this section. ing. Comply with the accident and safe- ty-related condition reporting require- [Amdt. 195–102, 84 FR 52294, Oct. 1, 2019] ments in subpart B of this part by Jan- uary 1, 2021. Subpart B—Annual, Accident, and (c) Exceptions. (1) This section does Safety-Related Condition Re- not apply to the transportation of a porting hazardous liquid in a gravity line that meets the definition of a low-stress § 195.48 Scope. pipeline, travels no farther than 1 mile from a facility boundary, and does not This Subpart prescribes requirements cross any waterways used for commer- for periodic reporting and for reporting cial navigation. of accidents and safety-related condi- (2) The reporting requirements in tions. This Subpart applies to all pipe- §§ 195.52, 195.61, and 195.65 do not apply lines subject to this Part. An operator to the transportation of a hazardous of a Category 3 rural low-stress pipe- liquid in a gravity line. line meeting the criteria in § 195.12 is (3) The drug and alcohol testing re- not required to complete those parts of quirements in part 199 of this sub- the hazardous liquid annual report chapter do not apply to the transpor- form PHMSA F 7000–1.1 associated with tation of a hazardous liquid in a grav- IM or high consequence areas. ity line. [76 FR 25588, May 5, 2011] [Amdt. 195–102, 84 FR 52294, Oct. 1, 2019] § 195.49 Annual report. § 195.15 What requirements apply to Each operator must annually com- reporting-regulated-only gathering plete and submit DOT Form PHMSA F lines? 7000–1.1 for each type of hazardous liq- (a) Scope. Gathering lines that do not uid pipeline facility operated at the otherwise meet the definition of a reg- end of the previous year. An operator ulated rural gathering line in § 195.11 must submit the annual report by June and any gathering line not already cov- 15 each year, except that for the 2010 ered under § 195.1(a)(1), (2), (3) or (4) reporting year the report must be sub- must comply with the reporting re- mitted by August 15, 2011. A separate quirements of subpart B of this part. report is required for crude oil, HVL

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(including anhydrous ammonia), petro- (1) Caused a death or a personal in- leum products, carbon dioxide pipe- jury requiring hospitalization; lines, and fuel grade ethanol pipelines. (2) Resulted in either a fire or explo- For each state a pipeline traverses, an sion not intentionally set by the oper- operator must separately complete ator; those sections on the form requiring (3) Caused estimated property dam- information to be reported for each age, including cost of cleanup and re- state. covery, value of lost product, and dam- age to the property of the operator or [75 FR 72907, Nov. 26, 2010] others, or both, exceeding $50,000; § 195.50 Reporting accidents. (4) Resulted in pollution of any stream, river, lake, reservoir, or other An accident report is required for similar body of water that violated ap- each failure in a pipeline system sub- plicable water quality standards, ject to this part in which there is a re- caused a discoloration of the surface of lease of the hazardous liquid or carbon the water or adjoining shoreline, or de- dioxide transported resulting in any of posited a sludge or emulsion beneath the following: the surface of the water or upon adjoin- (a) Explosion or fire not inten- ing shorelines; or tionally set by the operator. (5) In the judgment of the operator (b) Release of 5 gallons (19 liters) or was significant even though it did not more of hazardous liquid or carbon di- meet the criteria of any other para- oxide, except that no report is required graph of this section. for a release of less than 5 barrels (0.8 (b) Information required. Each notice cubic meters) resulting from a pipeline required by paragraph (a) of this sec- maintenance activity if the release is: tion must be made to the National Re- (1) Not otherwise reportable under sponse Center either by telephone to this section; 800–424–8802 (in Washington, DC, 202– (2) Not one described in § 195.52(a)(4); 267–2675) or electronically at http:// (3) Confined to company property or www.nrc.uscg.mil and must include the pipeline right-of-way; and following information: (4) Cleaned up promptly; (1) Name, address and identification (c) Death of any person; number of the operator. (d) Personal injury necessitating hos- (2) Name and telephone number of pitalization; the reporter. (e) Estimated property damage, in- (3) The location of the failure. cluding cost of clean-up and recovery, (4) The time of the failure. value of lost product, and damage to (5) The fatalities and personal inju- the property of the operator or others, ries, if any. or both, exceeding $50,000. (6) Initial estimate of amount of product released in accordance with [Amdt. 195–22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195–39, 53 FR 24950, July 1, paragraph (c) of this section. 1988; Amdt. 195–45, 56 FR 26925, June 12, 1991; (7) All other significant facts known Amdt. 195–52, 59 FR 33396, June 28, 1994; by the operator that are relevant to Amdt. 195–63, 63 FR 37506, July 13, 1998; the cause of the failure or extent of the Amdt. 195–75, 67 FR 836, Jan. 8, 2002] damages. (c) Calculation. A pipeline operator § 195.52 Immediate notice of certain must have a written procedure to cal- accidents. culate and provide a reasonable initial (a) Notice requirements. At the earliest estimate of the amount of released practicable moment following dis- product. covery, of a release of the hazardous (d) New information. Within 48 hours liquid or carbon dioxide transported re- after the confirmed discovery of an ac- sulting in an event described in § 195.50, cident, to the extent practicable, an but no later than one hour after con- operator must revise or confirm its ini- firmed discovery, the operator of the tial telephonic notice required in para- system must give notice, in accordance graph (b) of this section with a revised with paragraph (b) of this section of estimate of the amount of product re- any failure that: leased, location of the failure, time of

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the failure, a revised estimate of the remedial action of the operator), for number of fatalities and injuries, and purposes other than abandonment, a 20 all other significant facts that are percent or more reduction in operating known by the operator that are rel- pressure or shutdown of operation of a evant to the cause of the accident or pipeline. extent of the damages. If there are no (b) A report is not required for any changes or revisions to the initial re- safety-related condition that— port, the operator must confirm the es- (1) Exists on a pipeline that is more timates in its initial report. than 220 yards (200 meters) from any building intended for human occupancy [75 FR 72907, Nov. 26, 2010, as amended by Amdt. 195–101, 82 FR 7999, Jan. 23, 2017] or outdoor place of assembly, except that reports are required for conditions § 195.54 Accident reports. within the right-of-way of an active (a) Each operator that experiences an railroad, paved road, street, or high- accident that is required to be reported way, or that occur offshore or at on- under § 195.50 must, as soon as prac- shore locations where a loss of haz- ticable, but not later than 30 days after ardous liquid could reasonably be ex- discovery of the accident, file an acci- pected to pollute any stream, river, dent report on DOT Form 7000–1. lake, reservoir, or other body of water; (b) Whenever an operator receives (2) Is an accident that is required to any changes in the information re- be reported under § 195.50 or results in ported or additions to the original re- such an accident before the deadline port on DOT Form 7000–1, it shall file a for filing the safety-related condition supplemental report within 30 days. report; or (3) Is corrected by repair or replace- [Amdt. 195–39, 53 FR 24950, July 1, 1988, as ment in accordance with applicable amended by Amdt. 195–95, 75 FR 72907, Nov. safety standards before the deadline for 26, 2010] filing the safety-related condition re- § 195.55 Reporting safety-related con- port, except that reports are required ditions. for all conditions under paragraph (a) Except as provided in paragraph (a)(1) of this section other than local- (b) of this section, each operator shall ized corrosion pitting on an effectively report in accordance with § 195.56 the coated and cathodically protected pipe- existence of any of the following safe- line. ty-related conditions involving pipe- [Amdt. 195–39, 53 FR 24950, July 1, 1988; 53 FR lines in service: 29800, Aug. 8, 1988, as amended by Amdt. 195– (1) General corrosion that has re- 63, 63 FR 37506, July 13, 1998] duced the wall thickness to less than that required for the maximum oper- § 195.56 Filing safety-related condition ating pressure, and localized corrosion reports. pitting to a degree where leakage (a) Each report of a safety-related might result. condition under § 195.55(a) must be filed (2) Unintended movement or abnor- (received by OPS) within five working mal loading of a pipeline by environ- days (not including Saturday, Sunday, mental causes, such as an earthquake, or Federal Holidays) after the day a landslide, or flood, that impairs its representative of the operator first de- serviceability. termines that the condition exists, but (3) Any material defect or physical not later than 10 working days after damage that impairs the serviceability the day a representative of the oper- of a pipeline. ator discovers the condition. Separate (4) Any malfunction or operating conditions may be described in a single error that causes the pressure of a report if they are closely related. Re- pipeline to rise above 110 percent of its ports may be transmitted by electronic maximum operating pressure. mail to (5) A leak in a pipeline that con- [email protected], stitutes an emergency. or by facsimile at (202) 366–7128. (6) Any safety-related condition that (b) The report must be headed ‘‘Safe- could lead to an imminent hazard and ty-Related Condition Report’’ and pro- causes (either directly or indirectly by vide the following information:

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(1) Name and principal address of op- (d) Alternate Reporting Method. If elec- erator. tronic reporting imposes an undue bur- (2) Date of report. den and hardship, the operator may (3) Name, job title, and business tele- submit a written request for an alter- phone number of person submitting the native reporting method to the Infor- report. mation Resources Manager, Office of (4) Name, job title, and business tele- Pipeline Safety, Pipeline and Haz- phone number of person who deter- ardous Materials Safety Administra- mined that the condition exists. tion, PHP–20, 1200 New Jersey Avenue, (5) Date condition was discovered and SE., Washington DC 20590. The request date condition was first determined to must describe the undue burden and exist. hardship. PHMSA will review the re- (6) Location of condition, with ref- quest and may authorize, in writing, an erence to the State (and town, city, or alternative reporting method. An au- county) or offshore site, and as appro- thorization will state the period for priate nearest street address, offshore which it is valid, which may be indefi- platform, survey station number, mile- nite. An operator must contact post, landmark, or name of pipeline. PHMSA at 202–366–8075, or electroni- (7) Description of the condition, in- cally to cluding circumstances leading to its ‘‘[email protected]’’ discovery, any significant effects of the to make arrangements for submitting a condition on safety, and the name of report that is due after a request for al- the commodity transported or stored. ternative reporting is submitted but (8) The corrective action taken (in- before an authorization or denial is re- cluding reduction of pressure or shut- ceived. down) before the report is submitted (e) National Pipeline Mapping System and the planned follow-up or future (NPMS). An operator must provide corrective action, including the antici- NPMS data to the address identified in pated schedule for starting and con- the NPMS Operator Standards Manual cluding such action. available at www.npms.phmsa.dot.gov or [Amdt. 195–39, 53 FR 24950, July 1, 1988; 53 FR by contacting the PHMSA Geographic 29800, Aug. 8, 1988, as amended by Amdt. 195– Information Systems Manager at (202) 42, 54 FR 32344, Aug. 7, 1989; Amdt. 195–44, 54 366–4595. FR 40878, Oct. 4, 1989; Amdt. 195–50, 59 FR 17281, Apr. 12, 1994; Amdt. 195–61, 63 FR 7723, [Amdt. 195–95, 75 FR 72907, Nov. 26, 2010, as Feb. 17, 1998; Amdt. 195–100, 80 FR 12780, Mar. amended by ; Amdt. 195–100, 80 FR 12780, Mar. 11, 2015] 11, 2015]

§ 195.58 Report submission require- § 195.59 Abandonment or deactivation ments. of facilities. (a) General. Except as provided in For each abandoned offshore pipeline paragraphs (b) and (e) of this section, facility or each abandoned onshore an operator must submit each report pipeline facility that crosses over, required by this part electronically to under or through a commercially navi- PHMSA at http://opsweb.phmsa.dot.gov gable waterway, the last operator of unless an alternative reporting method that facility must file a report upon is authorized in accordance with para- abandonment of that facility. graph (d) of this section. (a) The preferred method to submit (b) Exceptions: An operator is not re- data on pipeline facilities abandoned quired to submit a safety-related con- after October 10, 2000 is to the National dition report (§ 195.56) electronically. Pipeline Mapping System (NPMS) in (c) Safety-related conditions. An oper- accordance with the NPMS ‘‘Standards ator must submit concurrently to the for Pipeline and Liquefied Natural Gas applicable State agency a safety-re- Operator Submissions.’’ To obtain a lated condition report required by copy of the NPMS Standards, please § 195.55 for an intrastate pipeline or refer to the NPMS homepage at http:// when the State agency acts as an agent www.npms.phmsa.dot.gov or contact the of the Secretary with respect to inter- NPMS National Repository at 703–317– state pipelines. 3073. A digital data format is preferred,

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but hard copy submissions are accept- (1) Geospatial data, attributes, able if they comply with the NPMS metadata and transmittal letter appro- Standards. In addition to the NPMS-re- priate for use in the National Pipeline quired attributes, operators must sub- Mapping System. Acceptable formats mit the date of abandonment, diame- and additional information are speci- ter, method of abandonment, and cer- fied in the NPMS Operator Standards tification that, to the best of the oper- manual available at ator’s knowledge, all of the reasonably www.npms.phmsa.dot.gov or by con- available information requested was tacting the PHMSA Geographic Infor- provided and, to the best of the opera- mation Systems Manager at (202) 366– tor’s knowledge, the abandonment was 4595. completed in accordance with applica- (2) The name of and address for the ble laws. Refer to the NPMS Standards operator. for details in preparing your data for (3) The name and contact informa- submission. The NPMS Standards also tion of a pipeline company employee, include details of how to submit data. to be displayed on a public Web site, Alternatively, operators may submit who will serve as a contact for ques- reports by mail, fax or e-mail to the Of- tions from the general public about the fice of Pipeline Safety, Pipeline and operator’s NPMS data. Hazardous Materials Safety Adminis- (b) This information must be sub- tration, U.S. Department of Transpor- mitted each year, on or before June 15, tation, Information Resources Man- representing assets as of December 31 ager, PHP–10, 1200 New Jersey Avenue, of the previous year. If no changes have SE., Washington, DC 20590-0001; fax occurred since the previous year’s sub- (202) 366–4566; e-mail, mission, the operator must refer to the ‘‘InformationResourcesManager@phmsa. information provided in the NPMS Op- dot.gov. The information in the report erator Standards manual available at must contain all reasonably available www.npms.phmsa.dot.gov or contact the information related to the facility, in- PHMSA Geographic Information Sys- cluding information in the possession tems Manager at (202) 366–4595. of a third party. The report must con- tain the location, size, date, method of [Amdt. 195–100, 80 FR 12780, Mar. 11, 2015] abandonment, and a certification that the facility has been abandoned in ac- § 195.63 OMB control number assigned to information collection. cordance with all applicable laws. (b) [Reserved] The control numbers assigned by the Office of Management and Budget to [Amdt. 195–69, 65 FR 54444, Sept. 8, 2000, as the hazardous liquid pipeline informa- amended at 70 FR 11140, Mar. 8, 2005; Amdt. tion collection pursuant to the Paper- 195–86, 72 FR 4657, Feb. 1, 2007; 73 FR 16570, Mar. 28, 2008; 74 FR 2894, Jan. 16, 2009] work Reduction Act are 2137–0047, 2137– 0601, 2137–0604, 2137–0605, 2137–0618, and § 195.60 Operator assistance in inves- 2137–0622. tigation. [Amdt. 195–95, 75 FR 72907, Nov. 26, 2010] If the Department of Transportation investigates an accident, the operator § 195.64 National Registry of Opera- involved shall make available to the tors. representative of the Department all (a) OPID Request. Effective January records and information that in any 1, 2012, each operator of a hazardous way pertain to the accident, and shall liquid or carbon dioxide pipeline or afford all reasonable assistance in the pipeline facility must obtain from investigation of the accident. PHMSA an Operator Identification Number (OPID). An OPID is assigned to § 195.61 National Pipeline Mapping an operator for the pipeline or pipeline System. system for which the operator has pri- (a) Each operator of a hazardous liq- mary responsibility. To obtain an uid pipeline facility must provide the OPID or a change to an OPID, an oper- following geospatial data to PHMSA ator must complete an OPID Assign- for that facility: ment Request DOT Form PHMSA F

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1000.1 through the National Registry of (v) The acquisition or divestiture of Operators in accordance with § 195.58. an existing pipeline facility subject to (b) OPID validation. An operator who this part. has already been assigned one or more (d) Reporting. An operator must use OPID by January 1, 2011 must validate the OPID issued by PHMSA for all re- the information associated with each porting requirements covered under such OPID through the National Reg- this subchapter and for submissions to istry of Operators at https://por- the National Pipeline Mapping System. tal.phmsa.dot.gov, and correct that in- [Amdt. 195–95, 75 FR 72907, Nov. 26, 2010, as formation as necessary, no later than amended by Amdt. 195–100, 80 FR 12780, Mar. June 30, 2012. 11, 2015; Amdt. 195–101, 82 FR 7999, Jan. 23, (c) Changes. Each operator must no- 2017; Amdt. 195–103, 85 FR 8127, Feb. 12, 2020] tify PHMSA electronically through the National Registry of Operators at § 195.65 Safety data sheets. https://portal.phmsa.dot.gov, of certain (a) Each owner or operator of a haz- events. ardous liquid pipeline facility, fol- (1) An operator must notify PHMSA lowing an accident involving a pipeline of any of the following events not later facility that results in a hazardous liq- than 60 days before the event occurs: uid spill, must provide safety data (i) Construction or any planned reha- sheets on any spilled hazardous liquid bilitation, replacement, modification, to the designated Federal On-Scene Co- upgrade, uprate, or update of a facility, ordinator and appropriate State and other than a section of line pipe, that local emergency responders within 6 costs $10 million or more. If 60 day no- hours of a telephonic or electronic no- tice is not feasible because of an emer- tice of the accident to the National Re- gency, an operator must notify PHMSA sponse Center. as soon as practicable; (b) Definitions. In this section: (ii) Construction of 10 or more miles (1) Federal On-Scene Coordinator. The of a new or replacement hazardous liq- term ‘‘Federal On-Scene Coordinator’’ uid or carbon dioxide pipeline; has the meaning given such term in (iii) Reversal of product flow direc- section 311(a) of the Federal Water Pol- tion when the reversal is expected to lution Control Act (33 U.S.C. 1321(a)). last more than 30 days. This notifica- (2) National Response Center. The term tion is not required for pipeline sys- ‘‘National Response Center’’ means the tems already designed for bi-direc- center described under 40 CFR tional flow; or 300.125(a). (iv) A pipeline converted for service (3) Safety data sheet. The term ‘‘safety under § 195.5, or a change in commodity data sheet’’ means a safety data sheet as reported on the annual report as re- required under 29 CFR 1910.1200. quired by § 195.49. [Amdt. 195–102, 84 FR 52294, Oct. 1, 2019] (2) An operator must notify PHMSA of any following event not later than 60 Subpart C—Design Requirements days after the event occurs: (i) A change in the primary entity re- § 195.100 Scope. sponsible (i.e., with an assigned OPID) This subpart prescribes minimum de- for managing or administering a safety sign requirements for new pipeline sys- program required by this part covering tems constructed with steel pipe and pipeline facilities operated under mul- for relocating, replacing, or otherwise tiple OPIDs. changing existing systems constructed (ii) A change in the name of the oper- with steel pipe. However, it does not ator; apply to the movement of line pipe (iii) A change in the entity (e.g., covered by § 195.424. company, municipality) responsible for operating an existing pipeline, pipeline § 195.101 Qualifying metallic compo- segment, or pipeline facility; nents other than pipe. (iv) The acquisition or divestiture of Notwithstanding any requirement of 50 or more miles of pipeline or pipeline the subpart which incorporates by ref- system subject to this part; or erence an edition of a document listed

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in § 195.3, a metallic component other D = Nominal outside diameter of the pipe in than pipe manufactured in accordance inches (millimeters). with any other edition of that docu- E = Seam joint factor determined in accord- ment is qualified for use if— ance with paragraph (e) of this section. F = A design factor of 0.72, except that a de- (a) It can be shown through visual in- sign factor of 0.60 is used for pipe, includ- spection of the cleaned component that ing risers, on a platform located offshore no defect exists which might impair or on a platform in inland navigable the strength or tightness of the compo- waters, and 0.54 is used for pipe that has nent: and been subjected to cold expansion to meet (b) The edition of the document the specified minimum yield strength under which the component was manu- and is subsequently heated, other than factured has equal or more stringent by welding or stress relieving as a part of welding, to a temperature higher than requirements for the following as an 900 °F (482 °C) for any period of time or edition of that document currently or over 600 °F (316 °C) for more than 1 hour. previously listed in § 195.3: (1) Pressure testing; (b) The yield strength to be used in (2) Materials; and determining the internal design pres- (3) Pressure and temperature ratings. sure under paragraph (a) of this section is the specified minimum yield [Amdt. 195–28, 48 FR 30639, July 5, 1983] strength. If the specified minimum § 195.102 Design temperature. yield strength is not known, the yield strength to be used in the design for- (a) Material for components of the mula is one of the following: system must be chosen for the tem- (1)(i) The yield strength determined perature environment in which the by performing all of the tensile tests of components will be used so that the ANSI/API Spec 5L (incorporated by ref- pipeline will maintain its structural erence, see § 195.3) on randomly selected integrity. specimens with the following number (b) Components of carbon dioxide of tests: pipelines that are subject to low tem- peratures during normal operation be- Pipe size No. of tests cause of rapid pressure reduction or Less than 65⁄8 in (168 mm) nomi- One test for each 200 during the initial fill of the line must nal outside diameter. lengths. be made of materials that are suitable 65⁄8 in through 123⁄4 in (168 mm One test for each 100 for those low temperatures. through 324 mm) nominal out- lengths. side diameter. [Amdt. 195–45, 56 FR 26925, June 12, 1991] Larger than 123⁄4 in (324 mm) One test for each 50 nominal outside diameter. lengths. § 195.104 Variations in pressure. (ii) If the average yield-tensile ratio If, within a pipeline system, two or exceeds 0.85, the yield strength shall be more components are to be connected taken as 24,000 p.s.i. (165,474 kPa). If the at a place where one will operate at a average yield-tensile ratio is 0.85 or higher pressure than another, the sys- less, the yield strength of the pipe is tem must be designed so that any com- taken as the lower of the following: ponent operating at the lower pressure (A) Eighty percent of the average will not be overstressed. yield strength determined by the ten- § 195.106 Internal design pressure. sile tests. (B) The lowest yield strength deter- (a) Internal design pressure for the mined by the tensile tests. pipe in a pipeline is determined in ac- (2) If the pipe is not tensile tested as cordance with the following formula: provided in paragraph (b) of this sec- P = (2 ) × × St/D E F tion, the yield strength shall be taken P = Internal design pressure in p.s.i. (kPa) as 24,000 p.s.i. (165,474 kPa). gage. (c) If the nominal wall thickness to S = Yield strength in pounds per square inch be used in determining internal design (kPa) determined in accordance with pressure under paragraph (a) of this paragraph (b) of this section. t = Nominal wall thickness of the pipe in section is not known, it is determined inches (millimeters). If this is unknown, by measuring the thickness of each it is determined in accordance with para- piece of pipe at quarter points on one graph (c) of this section. end. However, if the pipe is of uniform

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grade, size, and thickness, only 10 indi- (d) The minimum wall thickness of vidual lengths or 5 percent of all the pipe may not be less than 87.5 per- lengths, whichever is greater, need be cent of the value used for nominal wall measured. The thickness of the lengths thickness in determining the internal that are not measured must be verified design pressure under paragraph (a) of by applying a gage set to the minimum this section. In addition, the antici- thickness found by the measurement. pated external loads and external pres- The nominal wall thickness to be used sures that are concurrent with internal is the next wall thickness found in pressure must be considered in accord- commercial specifications that is ance with §§ 195.108 and 195.110 and, below the average of all the measure- after determining the internal design ments taken. However, the nominal pressure, the nominal wall thickness wall thickness may not be more than must be increased as necessary to com- 1.14 times the smallest measurement pensate for these concurrent loads and taken on pipe that is less than 20 pressures. inches (508 mm) nominal outside di- (e)(1) The seam joint factor used in ameter, nor more than 1.11 times the paragraph (a) of this section is deter- smallest measurement taken on pipe mined in accordance with the following that is 20 inches (508 mm) or more in standards incorporated by reference nominal outside diameter. (see § 195.3):

Seam joint Specification Pipe class factor

ASTM A53/A53M ...... Seamless ...... 1.00 Electric resistance welded ...... 1.00 Furnace lap welded ...... 0.80 Furnace butt welded ...... 0.60 ASTM A106/A106M ...... Seamless ...... 1.00 ASTM A333/A333M ...... Seamless ...... 1.00 Welded ...... 1.00 ASTM A381 ...... Double submerged arc welded ...... 1.00 ASTM A671/A671M ...... Electric-fusion-welded ...... 1.00 ASTM A672/A672M ...... Electric-fusion-welded ...... 1.00 ASTM A691/A691M ...... Electric-fusion-welded ...... 1.00 ANSI/API Spec 5L ...... Seamless ...... 1.00 Electric resistance welded ...... 1.00 Electric flash welded ...... 1.00 Submerged arc welded ...... 1.00 Furnace lap welded ...... 0.80 Furnace butt welded ...... 0.60

(2) The seam joint factor for pipe that sion, and contraction must be provided is not covered by this paragraph must for in designing a pipeline system. In be approved by the Administrator. providing for expansion and flexibility, [Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 section 419 of ASME/ANSI B31.4 must FR 32721, July 29, 1982, as amended by Amdt. be followed. 195–30, 49 FR 7569, Mar. 1, 1984; Amdt. 195–37, (b) The pipe and other components 51 FR 15335, Apr. 23, 1986; Amdt. 195–40, 54 FR must be supported in such a way that 5628, Feb. 6, 1989; 58 FR 14524, Mar. 18, 1993; Amdt. 195–50, 59 FR 17281, Apr. 12, 1994; Amdt. the support does not cause excess local- 195–52, 59 FR 33396, 33397, June 28, 1994; Amdt. ized stresses. In designing attachments 195–63, 63 FR 37506, July 13, 1998; Amdt. 195– to pipe, the added stress to the wall of 99, 80 FR 185, Jan. 5, 2015] the pipe must be computed and com- pensated for. § 195.108 External pressure. Any external pressure that will be [Amdt. 195–22, 46 FR 38360, July 27, 1981, as exerted on the pipe must be provided amended at 58 FR 14524, Mar. 18, 1993] for in designing a pipeline system.

§ 195.110 External loads. (a) Anticipated external loads (e.g.), earthquakes, vibration, thermal expan-

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§ 195.111 Fracture propagation. (3) Corroded areas where the remain- ing wall thickness is less than the min- A carbon dioxide pipeline system must be designed to mitigate the ef- imum thickness required by the toler- fects of fracture propagation. ances in the specification to which the pipe was manufactured. [Amdt. 195–45, 56 FR 26926, June 12, 1991] However, pipe that does not meet the § 195.112 New pipe. requirements of paragraph (b)(3) of this section may be used if the operating Any new pipe installed in a pipeline pressure is reduced to be commensu- system must comply with the fol- rate with the remaining wall thick- lowing: ness. (a) The pipe must be made of steel of the carbon, low alloy-high strength, or [Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 alloy type that is able to withstand the FR 32721, July 29, 1982] internal pressures and external loads and pressures anticipated for the pipe- § 195.116 Valves. line system. Each valve installed in a pipeline (b) The pipe must be made in accord- system must comply with the fol- ance with a written pipe specification lowing: that sets forth the chemical require- (a) The valve must be of a sound en- ments for the pipe steel and mechan- gineering design. ical tests for the pipe to provide pipe (b) Materials subject to the internal suitable for the use intended. pressure of the pipeline system, includ- (c) Each length of pipe with a nomi- ing welded and flanged ends, must be 1 nal outside diameter of 4 ⁄2 in (114.3 compatible with the pipe or fittings to mm) or more must be marked on the which the valve is attached. pipe or pipe coating with the specifica- (c) Each part of the valve that will be tion to which it was made, the speci- fied minimum yield strength or grade, in contact with the carbon dioxide or and the pipe size. The marking must be hazardous liquid stream must be made applied in a manner that does not dam- of materials that are compatible with age the pipe or pipe coating and must carbon dioxide or each hazardous liquid remain visible until the pipe is in- that it is anticipated will flow through stalled. the pipeline system. (d) Each valve must be both [Amdt. 195–22, 46 FR 38360, July 27, 1981, as hydrostatically shell tested and amended by Amdt. 195–52, 59 FR 33396, June 28, 1994; Amdt. 195–63, 63 FR 37506, July 13, hydrostatically seat tested without 1998] leakage to at least the requirements set forth in Section 11 of ANSI/API § 195.114 Used pipe. Spec 6D (incorporated by reference, see Any used pipe installed in a pipeline § 195.3). system must comply with § 195.112 (a) (e) Each valve other than a check and (b) and the following: valve must be equipped with a means (a) The pipe must be of a known spec- for clearly indicating the position of ification and the seam joint factor the valve (open, closed, etc.). must be determined in accordance with (f) Each valve must be marked on the § 195.106(e). If the specified minimum body or the nameplate, with at least yield strength or the wall thickness is the following: not known, it is determined in accord- (1) Manufacturer’s name or trade- ance with § 195.106 (b) or (c) as appro- mark. priate. (2) Class designation or the maximum (b) There may not be any: working pressure to which the valve (1) Buckles; may be subjected. (2) Cracks, grooves, gouges, dents, or (3) Body material designation (the other surface defects that exceed the end connection material, if more than maximum depth of such a defect per- one type is used). mitted by the specification to which the pipe was manufactured; or

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(4) Nominal valve size. of this section should not be applied to [Amdt. 195–22, 46 FR 38360, July 27, 1981, as a pipeline for reasons of imprac- amended by Amdt. 195–45, 56 FR 26926, June ticability. 12, 1991; Amdt. 195–86, 71 FR 33410, June 9, (d) Emergencies. An operator need not 2006; Amdt. 195–94, 75 FR 48606, Aug. 11, 2010; comply with paragraph (a) of this sec- Amdt. 195–99, 80 FR 186, Jan. 5, 2015] tion in constructing a new or replace- ment segment of a pipeline in an emer- § 195.118 Fittings. gency. Within 30 days after discovering (a) Butt-welding type fittings must the emergency, the operator must file meet the marking, end preparation, a petition under § 190.9 for a finding and the bursting strength requirements that requiring the design and construc- of ASME/ANSI B16.9 or MSS SP–75 (in- tion of the new or replacement pipeline corporated by reference, see § 195.3). segment to accommodate passage of in- (b) There may not be any buckles, dents, cracks, gouges, or other defects strumented internal inspection devices in the fitting that might reduce the would be impracticable as a result of strength of the fitting. the emergency. If PHMSA denies the (c) The fitting must be suitable for petition, within 1 year after the date of the intended service and be at least as the notice of the denial, the operator strong as the pipe and other fittings in must modify the new or replacement the pipeline system to which it is at- pipeline segment to allow passage of tached. instrumented internal inspection de- vices. [Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982, as amended at 58 FR [Amdt. 195–102, 84 FR 52294, Oct. 1, 2019] 14524, Mar. 18, 1993; Amdt. 195–99, 80 FR 186, Jan. 5, 2015] § 195.122 Fabricated branch connec- tions. § 195.120 Passage of internal inspec- tion devices. Each pipeline system must be de- (a) General. Except as provided in signed so that the addition of any fab- paragraphs (b) and (c) of this section, ricated branch connections will not re- each new pipeline and each main line duce the strength of the pipeline sys- section of a pipeline where the line tem. pipe, valve, fitting or other line compo- nent is replaced must be designed and § 195.124 Closures. constructed to accommodate the pas- Each closure to be installed in a pipe- sage of instrumented internal inspec- line system must comply with the 2007 tion devices in accordance with NACE ASME Boiler and Pressure Vessel Code SP0102 (incorporated by reference, see (BPVC) (Section VIII, Division 1) (in- § 195.3). corporated by reference, see § 195.3) and (b) Exceptions. This section does not must have pressure and temperature apply to: ratings at least equal to those of the (1) Manifolds; pipe to which the closure is attached. (2) Station piping such as at pump stations, meter stations, or pressure [Amdt. 195–99, 80 FR 186, Jan. 5, 2015] reducing stations; (3) Piping associated with tank farms § 195.126 Flange connection. and other storage facilities; Each component of a flange connec- (4) Cross-overs; tion must be compatible with each (5) Pipe for which an instrumented other component and the connection as internal inspection device is not com- a unit must be suitable for the service mercially available; and in which it is to be used. (6) Offshore pipelines, other than lines 10 inches (254 millimeters) or § 195.128 Station piping. greater in nominal diameter, that transport liquids to onshore facilities. Any pipe to be installed in a station (c) Impracticability. An operator may that is subject to system pressure must file a petition under § 190.9 for a finding meet the applicable requirements of that the requirements in paragraph (a) this subpart.

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§ 195.130 Fabricated assemblies. § 195.134 Leak detection. Each fabricated assembly to be in- (a) Scope. This section applies to each stalled in a pipeline system must meet hazardous liquid pipeline transporting the applicable requirements of this liquid in single phase (without gas in subpart. the liquid). (b) General. (1) For each pipeline con- § 195.132 Design and construction of structed prior to October 1, 2019. Each aboveground breakout tanks. pipeline must have a system for detect- (a) Each aboveground breakout tank ing leaks that complies with the re- must be designed and constructed to quirements in § 195.444 by October 1, withstand the internal pressure pro- 2024. duced by the hazardous liquid to be (2) For each pipeline constructed on stored therein and any anticipated ex- or after October 1, 2019. Each pipeline ternal loads. must have a system for detecting leaks (b) For aboveground breakout tanks that complies with the requirements in first placed in service after October 2, § 195.444 by October 1, 2020. 2000, compliance with paragraph (a) of (c) CPM leak detection systems. A new this section requires one of the fol- computational pipeline monitoring lowing: (CPM) leak detection system or re- (1) Shop-fabricated, vertical, cylin- placed component of an existing CPM drical, closed top, welded steel tanks system must be designed in accordance with nominal capacities of 90 to 750 with the requirements in section 4.2 of barrels (14.3 to 119.2 m 3) and with inter- API RP 1130 (incorporated by reference, nal vapor space pressures that are ap- see § 195.3) and any other applicable de- proximately atmospheric must be de- sign criteria in that standard. signed and constructed in accordance (d) Exception. The requirements of with API Spec 12F (incorporated by ref- paragraph (b) of this section do not erence, see § 195.3) . apply to offshore gathering or regu- (2) Welded, low-pressure (i.e., internal lated rural gathering lines. vapor space pressure not greater than 15 psig (103.4 kPa)), carbon steel tanks [Amdt. 195–102, 84 FR 52295, Oct. 1, 2019] that have wall shapes that can be gen- erated by a single vertical axis of revo- Subpart D—Construction lution must be designed and con- structed in accordance with API Std § 195.200 Scope. 620 (incorporated by reference, see This subpart prescribes minimum re- § 195.3). quirements for constructing new pipe- (3) Vertical, cylindrical, welded steel line systems with steel pipe, and for re- tanks with internal pressures at the locating, replacing, or otherwise tank top approximating atmospheric changing existing pipeline systems pressures (i.e., internal vapor space that are constructed with steel pipe. pressures not greater than 2.5 psig (17.2 However, this subpart does not apply kPa), or not greater than the pressure to the movement of pipe covered by developed by the weight of the tank § 195.424. roof) must be designed and constructed in accordance with API Std 650 (incor- § 195.202 Compliance with specifica- porated by reference, see § 195.3). tions or standards. (4) High pressure steel tanks (i.e., in- Each pipeline system must be con- ternal gas or vapor space pressures structed in accordance with com- greater than 15 psig (103.4 kPa)) with a prehensive written specifications or nominal capacity of 2000 gallons (7571 standards that are consistent with the liters) or more of liquefied petroleum requirements of this part. gas (LPG) must be designed and con- structed in accordance with API Std § 195.204 Inspection—general. 2510 (incorporated by reference, see Inspection must be provided to en- § 195.3). sure that the installation of pipe or [Amdt. 195–66, 64 FR 15935, Apr. 2, 1999, as pipeline systems is in accordance with amended by Amdt. 195–99, 80 FR 186, Jan. 5, the requirements of this subpart. Any 2015; 80 FR 46848, Aug. 6, 2015] operator personnel used to perform the

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inspection must be trained and quali- of installation to ensure that it is not fied in the phase of construction to be damaged in a manner that could impair inspected. An operator must not use its strength or reduce its service- operator personnel to perform a re- ability. quired inspection if the operator per- sonnel performed the construction task § 195.207 Transportation of pipe. requiring inspection. Nothing in this (a) Railroad. In a pipeline operated at section prohibits the operator from in- a hoop stress of 20 percent or more of specting construction tasks with oper- SMYS, an operator may not use pipe ator personnel who are involved in having an outer diameter to wall other construction tasks. thickness ratio of 70 to 1, or more, that [Amdt. 195–100, 80 FR 12780, Mar. 11, 2015] is transported by railroad unless the transportation is performed in accord- § 195.205 Repair, alteration and recon- ance with API RP 5L1 (incorporated by struction of aboveground breakout reference, see § 195.3). tanks that have been in service. (b) Ship or barge. In a pipeline oper- (a) Aboveground breakout tanks that ated at a hoop stress of 20 percent or have been repaired, altered, or recon- more of SMYS, an operator may not structed and returned to service must use pipe having an outer diameter to be capable of withstanding the internal wall thickness ratio of 70 to 1, or more, pressure produced by the hazardous liq- that is transported by ship or barge on uid to be stored therein and any antici- both inland and marine waterways, un- pated external loads. less the transportation is performed in (b) After October 2, 2000, compliance accordance with API RP 5LW (incor- with paragraph (a) of this section re- porated by reference, see § 195.3). quires the following: (c) Truck. In a pipeline to be operated (1) For tanks designed for approxi- at a hoop stress of 20 percent or more mate atmospheric pressure, con- of SMYS, an operator may not use pipe structed of carbon and low alloy steel, having an outer diameter to wall welded or riveted, and non-refrig- thickness ratio of 70 to 1, or more, that erated; and for tanks built to API Std is transported by truck unless the 650 (incorporated by reference, see transportation is performed in accord- § 195.3) or its predecessor Standard 12C; ance with API RP 5LT (incorporated by repair, alteration; and reconstruction reference, see § 195.3). must be in accordance with API Std 653 [Amdt. 195–94, 75 FR 48606, Aug. 11, 2010, as (except section 6.4.3) (incorporated by amended by Amdt. 195–99, 80 FR 186, Jan. 5, reference, see § 195.3). 2015] (2) For tanks built to API Spec 12F (incorporated by reference, see § 195.3) § 195.208 Welding of supports and or API Std 620 (incorporated by ref- braces. erence, see § 195.3), repair, alteration, Supports or braces may not be weld- and reconstruction must be in accord- ed directly to pipe that will be oper- ance with the design, welding, exam- ated at a pressure of more than 100 ination, and material requirements of p.s.i. (689 kPa) gage. those respective standards. [Amdt. 195–22, 46 FR 38360, July 27, 1981, as (3) For high-pressure tanks built to amended by Amdt. 195–63, 63 FR 37506, July API Std 2510 (incorporated by ref- 13, 1998] erence, see § 195.3), repairs, alterations, and reconstruction must be in accord- § 195.210 Pipeline location. ance with API Std 510 (incorporated by (a) Pipeline right-of-way must be se- reference, see § 195.3). lected to avoid, as far as practicable, [Amdt. 195–66, 64 FR 15935, Apr. 2, 1999, as areas containing private dwellings, in- amended by Amdt. 195–99, 80 FR 186, Jan. 5, dustrial buildings, and places of public 2015; 80 FR 46848, Aug. 6, 2015] assembly. (b) No pipeline may be located within § 195.206 Material inspection. 50 feet (15 meters) of any private dwell- No pipe or other component may be ing, or any industrial building or place installed in a pipeline system unless it of public assembly in which persons has been visually inspected at the site work, congregate, or assemble, unless

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it is provided with at least 12 inches must be retained and followed when- (305 millimeters) of cover in addition to ever the procedure is used. that prescribed in § 195.248. [Amdt. 195–38, 51 FR 20297, June 4, 1986, as [Amdt. 195–22, 46 FR 39360, July 27, 1981, as amended at Amdt. 195–81, 69 FR 32897, June amended by Amdt. 195–63, 63 FR 37506, July 14, 2004; Amdt. 195–99, 80 FR 186, Jan. 5, 2015; 13, 1998] Amdt. 195–100, 80 FR 12780, Mar. 11, 2015; Amdt. 195–101, 82 FR 7999, Jan. 23, 2017] § 195.212 Bending of pipe. § 195.216 Welding: Miter joints. (a) Pipe must not have a wrinkle bend. A miter joint is not permitted (not (b) Each field bend must comply with including deflections up to 3 degrees the following: that are caused by misalignment). (1) A bend must not impair the serv- iceability of the pipe. § 195.222 Welders and welding opera- tors: Qualification of welders and (2) Each bend must have a smooth welding operators. contour and be free from buckling, cracks, or any other mechanical dam- (a) Each welder or welding operator age. must be qualified in accordance with (3) On pipe containing a longitudinal section 6, section 12, Appendix A or Ap- weld, the longitudinal weld must be as pendix B of API Std 1104 (incorporated near as practicable to the neutral axis by reference, see § 195.3), or section IX of the bend unless— of the ASME Boiler and Pressure Ves- (i) The bend is made with an internal sel Code (ASME BPVC), (incorporated bending mandrel; or by reference, see § 195.3) except that a welder or welding operator qualified (ii) The pipe is 123⁄4 in (324 mm) or less nominal outside diameter or has a under an earlier edition than listed in diameter to wall thickness ratio less § 195.3, may weld but may not requalify than 70. under that earlier edition. (c) Each circumferential weld which (b) No welder or welding operator is located where the stress during bend- may weld with a welding process un- ing causes a permanent deformation in less, within the preceding 6 calendar the pipe must be nondestructively test- months, the welder or welding operator ed either before or after the bending has— process. (1) Engaged in welding with that process; and [Amdt. 195–22, 46 FR 38360, July 27, 1981, as (2) Had one weld tested and found ac- amended by Amdt. 195–52, 59 FR 33396, June ceptable under section 9 or Appendix A 28, 1994; Amdt. 195–63, 63 FR 37506, July 13, 1998] of API Std 1104 (incorporated by ref- erence, see § 195.3). § 195.214 Welding procedures. [Amdt. 195–81, 69 FR 54593, Sept. 9, 2004, as (a) Welding must be performed by a amended by Amdt. 195–86, 71 FR 33409, June qualified welder or welding operator in 9, 2006; Amdt. 195–99, 80 FR 186, Jan. 5, 2015; accordance with welding procedures Amdt. 195–100, 80 FR 12780, Mar. 11, 2015; qualified under section 5, section 12, Amdt. 195–101, 82 FR 7999, Jan. 23, 2017] Appendix A or Appendix B of API Std § 195.224 Welding: Weather. 1104 (incorporated by reference, see § 195.3), or Section IX of the ASME Welding must be protected from Boiler and Pressure Vessel Code (ASME weather conditions that would impair BPVC) (incorporated by reference, see the quality of the completed weld. § 195.3). The quality of the test welds used to qualify the welding procedures § 195.226 Welding: Arc burns. must be determined by destructive (a) Each arc burn must be repaired. testing. (b) An arc burn may be repaired by (b) Each welding procedure must be completely removing the notch by recorded in detail, including the results grinding, if the grinding does not re- of the qualifying tests. This record duce the remaining wall thickness to

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less than the minimum thickness re- § 195.234 Welds: Nondestructive test- quired by the tolerances in the speci- ing. fication to which the pipe is manufac- (a) A weld may be nondestructively tured. If a notch is not repairable by tested by any process that will clearly grinding, a cylinder of the pipe con- indicate any defects that may affect taining the entire notch must be re- the integrity of the weld. moved. (b) Any nondestructive testing of (c) A ground may not be welded to welds must be performed— the pipe or fitting that is being welded. (1) In accordance with a written set § 195.228 Welds and welding inspec- of procedures for nondestructive test- tion: Standards of acceptability. ing; and (2) With personnel that have been (a) Each weld and welding must be trained in the established procedures inspected to insure compliance with and in the use of the equipment em- the requirements of this subpart. Vis- ployed in the testing. ual inspection must be supplemented (c) Procedures for the proper inter- by nondestructive testing. pretation of each weld inspection must (b) The acceptability of a weld is de- be established to ensure the accept- termined according to the standards in ability of the weld under § 195.228. section 9 or Appendix A of API Std 1104 (d) During construction, at least 10 (incorporated by reference, see § 195.3). percent of the girth welds made by Appendix A of API Std 1104 may not be each welder and welding operator dur- used to accept cracks. ing each welding day must be non- [Amdt. 195–22, 46 FR 38360, July 27, 1981, as destructively tested over the entire cir- amended by Amdt. 195–52, 59 FR 33397, June cumference of the weld. 28, 1994; Amdt. 195–81, 69 FR 32898, June 14, (e) All girth welds installed each day 2004; Amdt. 195–99, 80 FR 186, Jan. 5, 2015; in the following locations must be non- Amdt. 195–100, 80 FR 12780, Mar. 11, 2015] destructively tested over their entire circumference, except that when non- § 195.230 Welds: Repair or removal of defects. destructive testing is impracticable for a girth weld, it need not be tested if (a) Each weld that is unacceptable the number of girth welds for which under § 195.228 must be removed or re- testing is impracticable does not ex- paired. Except for welds on an offshore ceed 10 percent of the girth welds in- pipeline being installed from a pipelay stalled that day: vessel, a weld must be removed if it has (1) At any onshore location where a a crack that is more than 8 percent of loss of hazardous liquid could reason- the weld length. ably be expected to pollute any stream, (b) Each weld that is repaired must river, lake, reservoir, or other body of have the defect removed down to sound water, and any offshore area; metal and the segment to be repaired (2) Within railroad or public road must be preheated if conditions exist rights-of-way; which would adversely affect the qual- (3) At overhead road crossings and ity of the weld repair. After repair, the within tunnels; segment of the weld that was repaired (4) Within the limits of any incor- must be inspected to ensure its accept- porated subdivision of a State govern- ability. ment; and (c) Repair of a crack, or of any defect (5) Within populated areas, including, in a previously repaired area must be but not limited to, residential subdivi- in accordance with written weld repair sions, shopping centers, schools, des- procedures that have been qualified ignated commercial areas, industrial under § 195.214. Repair procedures must facilities, public institutions, and provide that the minimum mechanical places of public assembly. properties specified for the welding (f) When installing used pipe, 100 per- procedure used to make the original cent of the old girth welds must be weld are met upon completion of the nondestructively tested. final weld repair. (g) At pipeline tie-ins, including tie- [Amdt. 195–29, 48 FR 48674, Oct. 20, 1983] ins of replacement sections, 100 percent

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of the girth welds must be nondestruc- natural bottom (as determined by rec- tively tested. ognized and generally accepted prac- tices) unless the pipe is supported by [Amdt. 195–22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195–35, 50 FR 37192, Sept. stanchions held in place by anchors or 21, 1985; Amdt. 195–52, 59 FR 33397, June 28, heavy concrete coating or protected by 1994; Amdt. 195–100, 80 FR 12780, Mar. 11, 2015] an equivalent means. [Amdt. 195–22, 46 FR 38360, July 27, 1981, as §§ 195.236–195.244 [Reserved] amended by Amdt. 195–52, 59 FR 33397, June 28, 1994; 59 FR 36256, July 15, 1994; Amdt. 195– § 195.246 Installation of pipe in a 85, 69 FR 48407, Aug. 10, 2004] ditch. (a) All pipe installed in a ditch must § 195.248 Cover over buried pipeline. be installed in a manner that mini- (a) Unless specifically exempted in mizes the introduction of secondary this subpart, all pipe must be buried so stresses and the possibility of damage that it is below the level of cultivation. to the pipe. Except as provided in paragraph (b) of (b) Except for pipe in the Gulf of this section, the pipe must be installed Mexico and its inlets in waters less so that the cover between the top of than 15 feet deep, all offshore pipe in the pipe and the ground level, road bed, water at least 12 feet deep (3.7 meters) river bottom, or underwater natural but not more than 200 feet deep (61 me- bottom (as determined by recognized ters) deep as measured from the mean and generally accepted practices), as low water must be installed so that the applicable, complies with the following top of the pipe is below the underwater table:

Cover inches (millimeters) Location For normal For rock excavation excavation 1

Industrial, commercial, and residential areas ...... 36 (914) 30 (762) Crossing of inland bodies of water with a width of at least 100 feet (30.5 meters) from high water mark to high water mark ...... 48 (1219) 18 (457) Drainage ditches at public roads and railroads ...... 36 (914) 36 (914) Deepwater port safety zones ...... 48 (1219) 24 (610) Gulf of Mexico and its inlets in waters less than 15 feet (4.6 meters) deep as measured from mean low water ...... 36 (914) 18 (457) Other offshore areas under water less than 12 ft (3.7 meters) deep as measured from mean low water ...... 36 (914) 18 (457) Any other area ...... 30 (762) 18 (457) 1 Rock excavation is any excavation that requires blasting or removal by equivalent means.

(b) Except for the Gulf of Mexico and § 195.250 Clearance between pipe and its inlets in waters less than 15 feet (4.6 underground structures. meters) deep, less cover than the min- Any pipe installed underground must imum required by paragraph (a) of this have at least 12 inches (305 millime- section and § 195.210 may be used if— ters) of clearance between the outside (1) It is impracticable to comply with of the pipe and the extremity of any the minimum cover requirements; and other underground structure, except (2) Additional protection is provided that for drainage tile the minimum that is equivalent to the minimum re- clearance may be less than 12 inches quired cover. (305 millimeters) but not less than 2 [Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 inches (51 millimeters). However, FR 32721, July 29, 1982, as amended by Amdt. where 12 inches (305 millimeters) of 195–52, 59 FR 33397, June 28, 1994; 59 FR 36256, clearance is impracticable, the clear- July 15, 1994; Amdt. 195–63, 63 FR 37506, July ance may be reduced if adequate provi- 13, 1998; Amdt. 195–95, 69 FR 48407, Aug. 10, sions are made for corrosion control. 2004; Amdt. 195–101, 82 FR 7999, Jan. 23, 2017] [Amdt. 195–22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195–63, 63 FR 37506, July 13, 1998]

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§ 195.252 Backfilling. ner that permits isolation of the tank area from other facilities. When a ditch for a pipeline is (c) On each mainline at locations backfilled, it must be backfilled in a along the pipeline system that will manner that: minimize damage or pollution from ac- (a) Provides firm support under the cidental hazardous liquid discharge, as pipe; and appropriate for the terrain in open (b) Prevents damage to the pipe and country, for offshore areas, or for popu- pipe coating from equipment or from lated areas. the backfill material. (d) On each lateral takeoff from a [Amdt. 195–78, 68 FR 53528, Sept. 11, 2003] trunk line in a manner that permits shutting off the lateral without inter- § 195.254 Above ground components. rupting the flow in the trunk line. (a) Any component may be installed (e) On each side of a water crossing above ground in the following situa- that is more than 100 feet (30 meters) tions, if the other applicable require- wide from high-water mark to high- ments of this part are complied with: water mark unless the Administrator (1) Overhead crossings of highways, finds in a particular case that valves railroads, or a body of water. are not justified. (2) Spans over ditches and gullies. (f) On each side of a reservoir holding water for human consumption. (3) Scraper traps or block valves. (4) Areas under the direct control of [Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 the operator. FR 32721, July 29, 1982; Amdt. 195–50, 59 FR (5) In any area inaccessible to the 17281, Apr. 12, 1994; Amdt. 195–63, 63 FR 37506, public. July 13, 1998] (b) Each component covered by this § 195.262 Pumping equipment. section must be protected from the forces exerted by the anticipated loads. (a) Adequate ventilation must be pro- vided in pump station buildings to pre- § 195.256 Crossing of railroads and vent the accumulation of hazardous va- highways. pors. Warning devices must be installed to warn of the presence of hazardous The pipe at each railroad or highway vapors in the pumping station building. crossing must be installed so as to ade- (b) The following must be provided in quately withstand the dynamic forces each pump station: exerted by anticipated traffic loads. (1) Safety devices that prevent over- § 195.258 Valves: General. pressuring of pumping equipment, in- cluding the auxiliary pumping equip- (a) Each valve must be installed in a ment within the pumping station. location that is accessible to author- (2) A device for the emergency shut- ized employees and that is protected down of each pumping station. from damage or tampering. (3) If power is necessary to actuate (b) Each submerged valve located off- the safety devices, an auxiliary power shore or in inland navigable waters supply. must be marked, or located by conven- (c) Each safety device must be tested tional survey techniques, to facilitate under conditions approximating actual quick location when operation of the operations and found to function prop- valve is required. erly before the pumping station may be used. § 195.260 Valves: Location. (d) Except for offshore pipelines, A valve must be installed at each of pumping equipment must be installed the following locations: on property that is under the control of (a) On the suction end and the dis- the operator and at least 15.2 m (50 ft) charge end of a pump station in a man- from the boundary of the pump station. ner that permits isolation of the pump (e) Adequate fire protection must be station equipment in the event of an installed at each pump station. If the emergency. fire protection system installed re- (b) On each line entering or leaving a quires the use of pumps, motive power breakout storage tank area in a man- must be provided for those pumps that

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is separate from the power that oper- (2) Normal/emergency relief venting ates the station. installed on atmospheric pressure tanks (such as those built to API Std [Amdt. 195–22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195–52, 59 FR 33397, June 650 or its predecessor Standard 12C) 28, 1994] must be in accordance with API Std 2000 (incorporated by reference, see § 195.264 Impoundment, protection § 195.3). against entry, normal/emergency (3) Pressure-relieving and emergency venting or pressure/vacuum relief vacuum-relieving devices installed on for aboveground breakout tanks. low-pressure tanks built to API Std 620 (a) A means must be provided for must be in accordance with Section 9 containing hazardous liquids in the of API Std 620 (incorporated by ref- event of spillage or failure of an above- erence, see § 195.3) and its references to ground breakout tank. the normal and emergency venting re- (b) After October 2, 2000, compliance quirements in API Std 2000 (incor- with paragraph (a) of this section re- porated by reference, see § 195.3). quires the following for the above- (4) Pressure and vacuum-relieving de- ground breakout tanks specified: vices installed on high-pressure tanks (1) For tanks built to API Spec 12F, built to API Std 2510 must be in ac- API Std 620, and others (such as API cordance with sections 7 or 11 of API Std 650 (or its predecessor Standard Std 2510 (incorporated by reference, see 12C)), the installation of impoundment § 195.3). must be in accordance with the fol- lowing sections of NFPA–30 (incor- [Amdt. 195–66, 64 FR 15935, Apr. 2, 1999, as porated by reference, see § 195.3); amended by Amdt. 195–86, 71 FR 33410, June 9, 2006; Amd .t195–94, 75 FR 48606, Aug. 11, (i) Impoundment around a breakout 2010; Amdt. 195–99, 80 FR 186, Jan. 5, 2015; 80 tank must be installed in accordance FR 46848, Aug. 6, 2015] with section 22.11.2; and (ii) Impoundment by drainage to a re- § 195.266 Construction records. mote impounding area must be in- stalled in accordance with section A complete record that shows the fol- 22.11.1. lowing must be maintained by the op- (2) For tanks built to API Std 2510 erator involved for the life of each pipeline facility: (incorporated by reference, see § 195.3) , the installation of impoundment must (a) The total number of girth welds be in accordance with section 5 or 11 of and the number nondestructively test- API Std 2510. ed, including the number rejected and (c) Aboveground breakout tank areas the disposition of each rejected weld. must be adequately protected against (b) The amount, location; and cover unauthorized entry. of each size of pipe installed. (d) Normal/emergency relief venting (c) The location of each crossing of must be provided for each atmospheric another pipeline. pressure breakout tank. Pressure/vacu- (d) The location of each buried util- um-relieving devices must be provided ity crossing. for each low-pressure and high-pressure (e) The location of each overhead breakout tank. crossing. (e) For normal/emergency relief vent- (f) The location of each valve and ing and pressure/vacuum-relieving de- corrosion test station. vices installed on aboveground break- out tanks after October 2, 2000, compli- [Amdt. 195–22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195–34, 50 FR 34474, Aug. ance with paragraph (d) of this section 26, 1985] requires the following for the tanks specified: (1) Normal/emergency relief venting Subpart E—Pressure Testing installed on atmospheric pressure tanks built to API Spec 12F must be in § 195.300 Scope. accordance with section 4 and Appen- This subpart prescribes minimum re- dices B and C of API Spec 12F (incor- quirements for the pressure testing of porated by reference, see § 195.3) . steel pipelines. However, this subpart

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does not apply to the movement of pipe (i) Plan and schedule testing accord- under § 195.424. ing to this paragraph; or (ii) Establish the pipeline’s maximum [Amdt. 195–51, 59 FR 29384, June 7, 1994] operating pressure under § 195.406(a)(5). § 195.302 General requirements. (2) For pipelines scheduled for test- ing, each operator shall— (a) Except as otherwise provided in (i) Before December 7, 2000, pressure this section and in § 195.305(b), no oper- test— ator may operate a pipeline unless it (A) Each pipeline identified by name, has been pressure tested under this symbol, or otherwise that existing subpart without leakage. In addition, records show contains more than 50 no operator may return to service a percent by mileage (length) of electric segment of pipeline that has been re- resistance welded pipe manufactured placed, relocated, or otherwise changed before 1970; and until it has been pressure tested under (B) At least 50 percent of the mileage this subpart without leakage. (length) of all other pipelines; and (b) Except for pipelines converted (ii) Before December 7, 2003, pressure under § 195.5, the following pipelines test the remainder of the pipeline mile- may be operated without pressure test- age (length). ing under this subpart: (1) Any hazardous liquid pipeline [Amdt. 195–51, 59 FR 29384, June 7, 1994, as whose maximum operating pressure is amended by Amdt. 195–53, 59 FR 35471, July 12, 1994; Amdt. 195–51B, 61 FR 43027, Aug. 20, established under § 195.406(a)(5) that 1996; Amdt. 195–58, 62 FR 54592, Oct. 21, 1997; is— Amdt. 195–63, 63 FR 37506, July 13, 1998; (i) An interstate pipeline constructed Amdt. 195–65, 63 FR 59479, Nov. 4, 1998] before January 8, 1971; (ii) An interstate offshore gathering § 195.303 Risk-based alternative to line constructed before August 1, 1977; pressure testing older hazardous (iii) An intrastate pipeline con- liquid and carbon dioxide pipelines. structed before October 21, 1985; or (a) An operator may elect to follow a (iv) A low-stress pipeline constructed program for testing a pipeline on risk- before August 11, 1994 that transports based criteria as an alternative to the HVL. pressure testing in § 195.302(b)(1)(i)–(iii) (2) Any carbon dioxide pipeline con- and § 195.302(b)(2)(i) of this subpart. Ap- structed before July 12, 1991, that— pendix B provides guidance on how this (i) Has its maximum operating pres- program will work. An operator elect- sure established under § 195.406(a)(5); or ing such a program shall assign a risk (ii) Is located in a rural area as part classification to each pipeline segment of a production field distribution sys- according to the indicators described in tem. paragraph (b) of this section as follows: (3) Any low-stress pipeline con- (1) Risk Classification A if the loca- structed before August 11, 1994 that tion indicator is ranked as low or me- does not transport HVL. dium risk, the product and volume in- (4) Those portions of older hazardous dicators are ranked as low risk, and liquid and carbon dioxide pipelines for the probability of failure indicator is which an operator has elected the risk- ranked as low risk; based alternative under § 195.303 and (2) Risk Classification C if the loca- which are not required to be tested tion indicator is ranked as high risk; or based on the risk-based criteria. (3) Risk Classification B. (c) Except for pipelines that trans- (b) An operator shall evaluate each port HVL onshore, low-stress pipelines, pipeline segment in the program ac- and pipelines covered under § 195.303, cording to the following indicators of the following compliance deadlines risk: apply to pipelines under paragraphs (1) The location indicator is— (b)(1) and (b)(2)(i) of this section that (i) High risk if an area is non-rural or have not been pressure tested under environmentally sensitive 1; or this subpart: (ii) Medium risk; or (1) Before December 7, 1998, for each (iii) Low risk if an area is not high or pipeline each operator shall— medium risk.

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(2) The product indicator is 1 steel’s mechanical properties, includ- (i) High risk if the product trans- ing fracture toughness; the manufac- ported is highly toxic or is both highly turing process and controls related to volatile and flammable; seam properties, including whether the (ii) Medium risk if the product trans- ERW process was high-frequency or ported is flammable with a flashpoint low-frequency, whether the weld seam of less than 100 °F, but not highly vola- was heat treated, whether the seam tile; or was inspected, the test pressure and (iii) Low risk if the product trans- duration during mill hydrotest; the ported is not high or medium risk. quality control of the steel-making (3) The volume indicator is— process; and other factors pertinent to (i) High risk if the line is at least 18 seam properties and quality. inches in nominal diameter; (e) Pressure testing done under this (ii) Medium risk if the line is at least section must be conducted in accord- 10 inches, but less than 18 inches, in ance with this subpart. Except for seg- nominal diameter; or ments in Risk Classification B which (iii) Low risk if the line is not high or are not constructed with pre-1970 ERW medium risk. pipe, water must be the test medium. (4) The probability of failure indi- (f) An operator electing to follow a cator is— program under paragraph (a) must de- (i) High risk if the segment has expe- velop plans that include the method of rienced more than three failures in the testing and a schedule for the testing last 10 years due to time-dependent de- by December 7, 1998. The compliance fects (e.g., corrosion, gouges, or prob- deadlines for completion of testing are lems developed during manufacture, as shown in the table below: construction or operation, etc.); or (ii) Low risk if the segment has expe- § 195.303—TEST DEADLINES rienced three failures or less in the last 10 years due to time-dependent defects. Pipeline Segment Risk classification Test deadline (c) The program under paragraph (a) Pre-1970 Pipe sus- C or B ...... 12/7/2000 of this section shall provide for pres- ceptible to longi- A ...... 12/7/2002 sure testing for a segment constructed tudinal seam fail- ures [defined in of electric resistance-welded (ERW) § 195.303(c) & pipe and lapwelded pipe manufactured (d)]. prior to 1970 susceptible to longitudinal All Other Pipeline C ...... 12/7/2002 seam failures as determined through Segments. B ...... 12/7//2004 A ...... Additional testing paragraph (d) of this section. The tim- not required ing of such pressure test may be deter- mined based on risk classifications dis- (g) An operator must review the risk cussed under paragraph (b) of this sec- classifications for those pipeline seg- tion. For other segments, the program ments which have not yet been tested may provide for use of a magnetic flux under paragraph (a) of this section or leakage or ultrasonic internal inspec- otherwise inspected under paragraph tion survey as an alternative to pres- (c) of this section at intervals not to sure testing and, in the case of such exceed 15 months. If the risk classifica- segments in Risk Classification A, may tion of an untested or uninspected seg- provide for no additional measures ment changes, an operator must take under this subpart. appropriate action within two years, or (d) All pre-1970 ERW pipe and establish the maximum operating pres- lapwelded pipe is deemed susceptible to sure under § 195.406(a)(5). longitudinal seam failures unless an (h) An operator must maintain engineering analysis shows otherwise. records establishing compliance with In conducting an engineering analysis this section, including records an operator must consider the seam-re- verifying the risk classifications, the lated leak history of the pipe and pipe plans and schedule for testing, the con- manufacturing information as avail- duct of the testing, and the review of able, which may include the pipe the risk classifications. (i) An operator may discontinue a 1 (See Appendix B, Table C). program under this section only after

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written notification to the Adminis- (1) The entire pipeline section under trator and approval, if needed, of a test is outside of cities and other popu- schedule for pressure testing. lated areas; (2) Each building within 300 feet (91 [Amdt. 195–65, 63 FR 59480, Nov. 4, 1998] meters) of the test section is unoccu- pied while the test pressure is equal to § 195.304 Test pressure. or greater than a pressure which pro- The test pressure for each pressure duces a hoop stress of 50 percent of test conducted under this subpart must specified minimum yield strength; be maintained throughout the part of (3) The test section is kept under sur- the system being tested for at least 4 veillance by regular patrols during the continuous hours at a pressure equal to test; and 125 percent, or more, of the maximum (4) Continuous communication is operating pressure and, in the case of a maintained along entire test section. pipeline that is not visually inspected (c) Carbon dioxide pipelines may use for leakage during the test, for at least inert gas or carbon dioxide as the test an additional 4 continuous hours at a medium if— pressure equal to 110 percent, or more, (1) The entire pipeline section under of the maximum operating pressure. test is outside of cities and other popu- lated areas; [Amdt. 195–51, 59 FR 29384, June 7, 1994. Re- (2) Each building within 300 feet (91 designated by Amdt. 195–65, 63 FR 59480, Nov. 4, 1998] meters) of the test section is unoccu- pied while the test pressure is equal to § 195.305 Testing of components. or greater than a pressure that pro- duces a hoop stress of 50 percent of (a) Each pressure test under § 195.302 specified minimum yield strength; must test all pipe and attached fit- (3) The maximum hoop stress during tings, including components, unless the test does not exceed 80 percent of otherwise permitted by paragraph (b) specified minimum yield strength; of this section. (4) Continuous communication is (b) A component, other than pipe, maintained along entire test section; that is the only item being replaced or and added to the pipeline system need not (5) The pipe involved is new pipe hav- be hydrostatically tested under para- ing a longitudinal joint factor of 1.00. graph (a) of this section if the manu- (d) Air or inert gas may be used as facturer certifies that either— the test medium in low-stress pipe- (1) The component was lines. hydrostatically tested at the factory; [Amdt. 195–22, 46 FR 38360, July 27, 1991, as or amended by Amdt. 195–45, 56 FR 26926, June (2) The component was manufactured 12, 1991; Amdt. 195–51, 59 FR 29385, June 7, under a quality control system that en- 1994; Amdt. 195–53, 59 FR 35471, July 12, 1994; sures each component is at least equal Amdt. 195–51A, 59 FR 41260, Aug. 11, 1994; in strength to a prototype that was Amdt. 195–63, 63 FR 37506, July 13, 1998] hydrostatically tested at the factory. § 195.307 Pressure testing above- [Amdt. 195–22, 46 FR 38360, July 27, 1981, as ground breakout tanks. amended by Amdt. 195–51, 59 FR 29385, June (a) For aboveground breakout tanks 7, 1994; Amdt. 195–52, 59 FR 33397, June 28, built to API Spec 12F (incorporated by 1994. Redesignated by Amdt. 195–65, 63 FR reference, see § 195.3) and first placed in 59480, Nov. 4, 1998] service after October 2, 2000, pneumatic testing must be performed in accord- § 195.306 Test medium. ance with section 5.3 of API Spec 12 F. (a) Except as provided in paragraphs (b) For aboveground breakout tanks (b), (c), and (d) of this section, water built to API Std 620 (incorporated by must be used as the test medium. reference, see § 195.3) and first placed in (b) Except for offshore pipelines, liq- service after October 2, 2000, hydro- uid petroleum that does not vaporize static and pneumatic testing must be rapidly may be used as the test me- performed in accordance with section dium if— 7.18 of API Std 620.

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(c) For aboveground breakout tanks (8) An explanation of any pressure built to API Std 650 (incorporated by discontinuities, including test failures, reference, see § 195.3) and first placed in that appear on the pressure recording service after October 2, 2000, testing charts; must be in accordance with sections (9) Where elevation differences in the 7.3.5 and 7.3.6 of API Standard 650 (in- section under test exceed 100 feet (30 corporated by reference, see § 195.3). meters), a profile of the pipeline that (d) For aboveground atmospheric shows the elevation and test sites over pressure breakout tanks constructed of the entire length of the test section; carbon and low alloy steel, welded or and riveted, and non-refrigerated tanks (10) Temperature of the test medium built to API Std 650 or its predecessor or pipe during the test period. Standard 12 C that are returned to [Amdt. 195–34, 50 FR 34474, Aug. 26, 1985, as service after October 2, 2000, the neces- amended by Amdt. 195–51, 59 FR 29385, June sity for the hydrostatic testing of re- 7, 1994; Amdt. 195–63, 63 FR 37506, July 13, pair, alteration, and reconstruction is 1998; Amdt. 195–78, 68 FR 53528, Sept. 11, 2003] covered in section 12.3 of API Standard 653 (incorporated by reference, see Subpart F—Operation and § 195.3). Maintenance (e) For aboveground breakout tanks built to API Std 2510 (incorporated by § 195.400 Scope. reference, see § 195.3) and first placed in This subpart prescribes minimum re- service after October 2, 2000, pressure quirements for operating and main- testing must be performed in accord- taining pipeline systems constructed ance with 2007 ASME Boiler and Pres- with steel pipe. sure Vessel Code (BPVC) (Section VIII, Division 1 or 2). § 195.401 General requirements. [Amdt. 195–99, 80 FR 187, Jan. 5, 2015, as (a) No operator may operate or main- amended by Amdt. 195–100, 80 FR 12780, Mar. tain its pipeline systems at a level of 11, 2015] safety lower than that required by this subpart and the procedures it is re- § 195.308 Testing of tie-ins. quired to establish under § 195.402(a) of Pipe associated with tie-ins must be this subpart. pressure tested, either with the section (b) An operator must make repairs on to be tied in or separately. its pipeline system according to the following requirements: [Amdt. 195–22, 46 FR 38360, July 27, 1981, as (1) Non Integrity management repairs. amended by Amdt. 195–51, 59 FR 29385, June Whenever an operator discovers any 7, 1994] condition that could adversely affect § 195.310 Records. the safe operation of its pipeline sys- tem, it must correct the condition (a) A record must be made of each within a reasonable time. However, if pressure test required by this subpart, the condition is of such a nature that and the record of the latest test must it presents an immediate hazard to per- be retained as long as the facility test- sons or property, the operator may not ed is in use. operate the affected part of the system (b) The record required by paragraph until it has corrected the unsafe condi- (a) of this section must include: tion. (1) The pressure recording charts; (2) Integrity management repairs. When (2) Test instrument calibration data; an operator discovers a condition on a (3) The name of the operator, the pipeline covered under § 195.452, the op- name of the person responsible for erator must correct the condition as making the test, and the name of the prescribed in § 195.452(h). test company used, if any; (3) Prioritizing repairs. An operator (4) The date and time of the test; must consider the risk to people, prop- (5) The minimum test pressure; erty, and the environment in (6) The test medium; prioritizing the correction of any con- (7) A description of the facility tested ditions referenced in paragraphs (b)(1) and the test apparatus; and (2) of this section.

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(c) Except as provided in § 195.5, no tunity for hearing as provided in 49 operator may operate any part of any CFR 190.206 or the relevant State pro- of the following pipelines unless it was cedures, require the operator to amend designed and constructed as required its plans and procedures as necessary by this part: to provide a reasonable level of safety. (1) An interstate pipeline, other than (c) Maintenance and normal operations. a low-stress pipeline, on which con- The manual required by paragraph (a) struction was begun after March 31, of this section must include procedures 1970, that transports hazardous liquid. for the following to provide safety dur- (2) An interstate offshore gathering ing maintenance and normal oper- line, other than a low-stress pipeline, ations: on which construction was begun after (1) Making construction records, July 31, 1977, that transports hazardous maps, and operating history available liquid. as necessary for safe operation and (3) An intrastate pipeline, other than maintenance. a low-stress pipeline, on which con- (2) Gathering of data needed for re- struction was begun after October 20, porting accidents under subpart B of 1985, that transports hazardous liquid. this part in a timely and effective man- (4) A pipeline on which construction ner. was begun after July 11, 1991, that (3) Operating, maintaining, and re- transports carbon dioxide. pairing the pipeline system in accord- (5) A low-stress pipeline on which ance with each of the requirements of construction was begun after August this subpart and subpart H of this part. 10, 1994. (4) Determining which pipeline facili- [Amdt. 195–22, 46 FR 38360, July 27, 1981, as ties are located in areas that would re- amended by Amdt. 195–33, 50 FR 15899, Apr. quire an immediate response by the op- 23, 1985; Amdt. 195–33A, 50 FR 39008, Sept. 26, erator to prevent hazards to the public 1985; Amdt. 195–36, 51 FR 15008, Apr. 22, 1986; if the facilities failed or malfunctioned. Amdt. 195–45, 56 FR 26926, June 12, 1991; (5) Analyzing pipeline accidents to Amdt. 195–53, 59 FR 35471, July 12, 1994; Amdt. 195–94, 75 FR 48607, Aug. 11, 2010; determine their causes. Amdt. 195–102, 84 FR 52295, Oct. 1, 2019] (6) Minimizing the potential for haz- ards identified under paragraph (c)(4) § 195.402 Procedural manual for oper- of this section and the possibility of re- ations, maintenance, and emer- currence of accidents analyzed under gencies. paragraph (c)(5) of this section. (a) General. Each operator shall pre- (7) Starting up and shutting down pare and follow for each pipeline sys- any part of the pipeline system in a tem a manual of written procedures for manner designed to assure operation conducting normal operations and within the limits prescribed by maintenance activities and handling § 195.406, consider the hazardous liquid abnormal operations and emergencies. or carbon dioxide in transportation, This manual shall be reviewed at inter- variations in altitude along the pipe- vals not exceeding 15 months, but at line, and pressure monitoring and con- least once each calendar year, and ap- trol devices. propriate changes made as necessary to (8) In the case of a pipeline that is insure that the manual is effective. not equipped to fail safe, monitoring This manual shall be prepared before from an attended location pipeline initial operations of a pipeline system pressure during startup until steady commence, and appropriate parts shall state pressure and flow conditions are be kept at locations where operations reached and during shut-in to assure and maintenance activities are con- operation within limits prescribed by ducted. § 195.406. (b) The Associate Administrator or (9) In the case of facilities not the State Agency that has submitted a equipped to fail safe that are identified current certification under the pipeline under paragraph 195.402(c)(4) or that safety laws (49 U.S.C. 60101 et seq.) with control receipt and delivery of the haz- respect to the pipeline facility gov- ardous liquid or carbon dioxide, detect- erned by an operator’s plans and proce- ing abnormal operating conditions by dures may, after notice and oppor- monitoring pressure, temperature, flow

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or other appropriate operational data (i) Unintended closure of valves or and transmitting this data to an at- shutdowns; tended location. (ii) Increase or decrease in pressure (10) Abandoning pipeline facilities, or flow rate outside normal operating including safe disconnection from an limits; operating pipeline system, purging of (iii) Loss of communications; combustibles, and sealing abandoned (iv) Operation of any safety device; facilities left in place to minimize safe- (v) Any other malfunction of a com- ty and environmental hazards. For ponent, deviation from normal oper- each abandoned offshore pipeline facil- ation, or personnel error which could ity or each abandoned onshore pipeline cause a hazard to persons or property. facility that crosses over, under or (2) Checking variations from normal through commercially navigable wa- operation after abnormal operation has terways the last operator of that facil- ended at sufficient critical locations in ity must file a report upon abandon- the system to determine continued in- ment of that facility in accordance tegrity and safe operation. with § 195.59 of this part. (3) Correcting variations from normal (11) Minimizing the likelihood of ac- operation of pressure and flow equip- cidental ignition of vapors in areas ment and controls. near facilities identified under para- (4) Notifying responsible operator graph (c)(4) of this section where the personnel when notice of an abnormal potential exists for the presence of operation is received. flammable liquids or gases. (5) Periodically reviewing the re- (12) Establishing and maintaining li- sponse of operator personnel to deter- aison with fire, police, and other appro- mine the effectiveness of the proce- priate public officials to learn the re- dures controlling abnormal operation sponsibility and resources of each gov- and taking corrective action where de- ernment organization that may re- ficiencies are found. spond to a hazardous liquid or carbon (e) Emergencies. The manual required dioxide pipeline emergency and ac- by paragraph (a) of this section must quaint the officials with the operator’s include procedures for the following to ability in responding to a hazardous provide safety when an emergency con- liquid or carbon dioxide pipeline emer- dition occurs: gency and means of communication. (1) Receiving, identifying, and (13) Periodically reviewing the work classifying notices of events which done by operator personnel to deter- need immediate response by the oper- mine the effectiveness of the proce- ator or notice to fire, police, or other dures used in normal operation and appropriate public officials and com- maintenance and taking corrective ac- municating this information to appro- tion where deficiencies are found. priate operator personnel for correc- (14) Taking adequate precautions in tive action. excavated trenches to protect per- (2) Prompt and effective response to a sonnel from the hazards of unsafe accu- notice of each type emergency, includ- mulations of vapor or gas, and making ing fire or explosion occurring near or available when needed at the exca- directly involving a pipeline facility, vation, emergency rescue equipment, accidental release of hazardous liquid including a breathing apparatus and, a or carbon dioxide from a pipeline facil- rescue harness and line. ity, operational failure causing a haz- (15) Implementing the applicable con- ardous condition, and natural disaster trol room management procedures re- affecting pipeline facilities. quired by § 195.446. (3) Having personnel, equipment, in- (d) Abnormal operation. The manual struments, tools, and material avail- required by paragraph (a) of this sec- able as needed at the scene of an emer- tion must include procedures for the gency. following to provide safety when oper- (4) Taking necessary action, such as ating design limits have been exceeded: emergency shutdown or pressure reduc- (1) Responding to, investigating, and tion, to minimize the volume of haz- correcting the cause of: ardous liquid or carbon dioxide that is

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released from any section of a pipeline § 195.403 Emergency response train- system in the event of a failure. ing. (5) Control of released hazardous liq- (a) Each operator shall establish and uid or carbon dioxide at an accident conduct a continuing training program scene to minimize the hazards, includ- to instruct emergency response per- ing possible intentional ignition in the sonnel to: cases of flammable highly volatile liq- (1) Carry out the emergency proce- uid. dures established under 195.402 that re- (6) Minimization of public exposure late to their assignments; to injury and probability of accidental (2) Know the characteristics and haz- ignition by assisting with evacuation ards of the hazardous liquids or carbon of residents and assisting with halting dioxide transported, including, in case traffic on roads and railroads in the af- of flammable HVL, flammability of fected area, or taking other appro- mixtures with air, odorless vapors, and priate action. water reactions; (7) Notifying fire, police, and other (3) Recognize conditions that are appropriate public officials of haz- likely to cause emergencies, predict ardous liquid or carbon dioxide pipeline the consequences of facility malfunc- emergencies and coordinating with tions or failures and hazardous liquids them preplanned and actual responses or carbon dioxide spills, and take ap- during an emergency, including addi- propriate corrective action; tional precautions necessary for an (4) Take steps necessary to control emergency involving a pipeline system any accidental release of hazardous liq- transporting a highly volatile liquid. uid or carbon dioxide and to minimize (8) In the case of failure of a pipeline the potential for fire, explosion, tox- system transporting a highly volatile icity, or environmental damage; and liquid, use of appropriate instruments (5) Learn the potential causes, types, to assess the extent and coverage of sizes, and consequences of fire and the the vapor cloud and determine the haz- appropriate use of portable fire extin- ardous areas. guishers and other on-site fire control (9) Providing for a post accident re- equipment, involving, where feasible, a view of employee activities to deter- simulated pipeline emergency condi- mine whether the procedures were ef- tion. fective in each emergency and taking (b) At the intervals not exceeding 15 corrective action where deficiencies months, but at least once each cal- are found. endar year, each operator shall: (10) Actions required to be taken by a (1) Review with personnel their per- controller during an emergency, in ac- formance in meeting the objectives of cordance with § 195.446. the emergency response training pro- (f) Safety-related condition reports. The gram set forth in paragraph (a) of this manual required by paragraph (a) of section; and this section must include instructions (2) Make appropriate changes to the enabling personnel who perform oper- emergency response training program ation and maintenance activities to as necessary to ensure that it is effec- recognize conditions that potentially tive. may be safety-related conditions that (c) Each operator shall require and are subject to the reporting require- verify that its supervisors maintain a ments of § 195.55. thorough knowledge of that portion of the emergency response procedures es- [Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982, as amended by Amdt. tablished under 195.402 for which they 195–24, 47 FR 46852, Oct. 21, 1982; Amdt. 195–39, are responsible to ensure compliance. 53 FR 24951, July 1, 1988; Amdt. 195–45, 56 FR [Amdt. 195–67, 64 FR 46866, Aug. 27, 1999, as 26926, June 12, 1991; Amdt. 195–46, 56 FR 31090, amended at Amdt. 195–78, 68 FR 53528, Sept. July 9, 1991; Amdt. 195–49, 59 FR 6585, Feb. 11, 11, 2003] 1994; Amdt. 195–55, 61 FR 18518, Apr. 26, 1996; Amdt. 195–69, 65 FR 54444, Sept. 8, 2000; Amdt. § 195.404 Maps and records. 195–173, 66 FR 67004, Dec. 27, 2001; Amdt. 195– 93, 74 FR 63329, Dec. 3, 2009; Amdt. 195–98, 78 (a) Each operator shall maintain cur- FR 58915, Sept. 25, 2013] rent maps and records of its pipeline

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systems that include at least the fol- porated by reference, see § 195.3), unless lowing information: the operator notes in the procedural (1) Location and identification of the manual (§ 195.402(c)) why compliance following pipeline facilities: with all or certain provisions of API (i) Breakout tanks; RP 2003 is not necessary for the safety (ii) Pump stations; of a particular breakout tank. (iii) Scraper and sphere facilities; (b) The hazards associated with ac- (iv) Pipeline valves; cess/egress onto floating roofs of in- (v) Facilities to which § 195.402(c)(9) service aboveground breakout tanks to applies; perform inspection, service, mainte- (vi) Rights-of-way; and nance, or repair activities (other than (vii) Safety devices to which § 195.428 specified general considerations, speci- applies. fied routine tasks or entering tanks re- (2) All crossings of public roads, rail- moved from service for cleaning) are roads, rivers, buried utilities, and for- addressed in API Pub 2026 (incor- eign pipelines. porated by reference, see § 195.3) . After (3) The maximum operating pressure October 2, 2000, the operator must re- of each pipeline. view and consider the potentially haz- (4) The diameter, grade, type, and ardous conditions, safety practices, and nominal wall thickness of all pipe. procedures in API Pub 2026 for inclu- (b) Each operator shall maintain for sion in the procedure manual at least 3 years daily operating records (§ 195.402(c)). that indicate— [Amdt. 195–99,80 FR 187, Jan. 5, 2015; 80 FR (1) The discharge pressure at each 46848, Aug. 6, 2015] pump station; and (2) Any emergency or abnormal oper- § 195.406 Maximum operating pres- ation to which the procedures under sure. § 195.402 apply. (a) Except for surge pressures and (c) Each operator shall maintain the other variations from normal oper- following records for the periods speci- ations, no operator may operate a pipe- fied: line at a pressure that exceeds any of (1) The date, location, and descrip- the following: tion of each repair made to pipe shall (1) The internal design pressure of be maintained for the useful life of the the pipe determined in accordance with pipe. § 195.106. However, for steel pipe in pipe- (2) The date, location, and descrip- lines being converted under § 195.5, if tion of each repair made to parts of the one or more factors of the design for- pipeline system other than pipe shall mula (§ 195.106) are unknown, one of the be maintained for at least 1 year. following pressures is to be used as de- (3) A record of each inspection and sign pressure: test required by this subpart shall be (i) Eighty percent of the first test maintained for at least 2 years or until pressure that produces yield under sec- the next inspection or test is per- tion N5.0 of appendix N of ASME/ANSI formed, whichever is longer. B31.8 (incorporated by reference, see [Amdt. 195–22, 46 FR 38360, July 27, 1981, as § 195.3), reduced by the appropriate fac- amended by Amdt. 195–34, 50 FR 34474, Aug. tors in §§ 195.106 (a) and (e); or 26, 1985; Amdt. 195–173, 66 FR 67004, Dec. 27, (ii) If the pipe is 12 3⁄4 inch (324 mm) 2001] or less outside diameter and is not tested to yield under this paragraph, § 195.405 Protection against ignitions 200 p.s.i. (1379 kPa) gage. and safe access/egress involving (2) The design pressure of any other floating roofs. component of the pipeline. (a) After October 2, 2000, protection (3) Eighty percent of the test pres- provided against ignitions arising out sure for any part of the pipeline which of static electricity, lightning, and has been pressure tested under subpart stray currents during operation and E of this part. maintenance activities involving (4) Eighty percent of the factory test aboveground breakout tanks must be pressure or of the prototype test pres- in accordance with API RP 2003 (incor- sure for any individually installed

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component which is excepted from § 195.410 Line markers. testing under § 195.305. (a) Except as provided in paragraph (5) For pipelines under §§ 195.302(b)(1) (b) of this section, each operator shall and (b)(2)(i) that have not been pres- place and maintain line markers over sure tested under subpart E of this each buried pipeline in accordance with part, 80 percent of the test pressure or the following: highest operating pressure to which (1) Markers must be located at each the pipeline was subjected for 4 or more public road crossing, at each railroad continuous hours that can be dem- crossing, and in sufficient number onstrated by recording charts or logs along the remainder of each buried line made at the time the test or operations so that its location is accurately were conducted. known. (b) No operator may permit the pres- (2) The marker must state at least sure in a pipeline during surges or the following on a background of sharply contrasting color: other variations from normal oper- (i) The word ‘‘Warning,’’ ‘‘Caution,’’ ations to exceed 110 percent of the op- or ‘‘Danger’’ followed by the words erating pressure limit established ‘‘Petroleum (or the name of the haz- under paragraph (a) of this section. ardous liquid transported) Pipeline’’, or Each operator must provide adequate ‘‘Carbon Dioxide Pipeline,’’ all of controls and protective equipment to which, except for markers in heavily control the pressure within this limit. developed urban areas, must be in let- [Amdt. 195–22, 46 FR 38360, July 27, 1981, as ters at least 1 inch (25 millimeters) amended by Amdt. 195–33, 50 FR 15899, Apr. high with an approximate stroke of 1⁄4 23, 1985; 50 FR 38660, Sept. 24, 1985; Amdt. 195– inch (6.4 millimeters). 51, 59 FR 29385, June 7, 1994; Amdt. 195–52, 59 (ii) The name of the operator and a FR 33397, June 28, 1994; Amdt. 195–63, 63 FR telephone number (including area code) 37506, July 13, 1998; Amdt. 195–65, 63 FR 59480, where the operator can be reached at Nov. 4, 1998; Amdt. 195–99, 80 FR 184, Jan. 5, all times. 2015] (b) Line markers are not required for buried pipelines located— § 195.408 Communications. (1) Offshore or at crossings of or (a) Each operator must have a com- under waterways and other bodies of munication system to provide for the water; or transmission of information needed for (2) In heavily developed urban areas the safe operation of its pipeline sys- such as downtown business centers tem. where— (i) The placement of markers is im- (b) The communication system re- practical and would not serve the pur- quired by paragraph (a) of this section pose for which markers are intended; must, as a minimum, include means and for: (ii) The local government maintains (1) Monitoring operational data as re- current substructure records. quired by § 195.402(c)(9); (c) Each operator shall provide line (2) Receiving notices from operator marking at locations where the line is personnel, the public, and public au- above ground in areas that are acces- thorities of abnormal or emergency sible to the public. conditions and sending this informa- [Amdt. 195–22, 46 FR 38360, July 27, 1981, as tion to appropriate personnel or gov- amended by Amdt. 195–27, 48 FR 25208, June ernment agencies for corrective action; 6, 1983; Amdt. 195–54, 60 FR 14650, Mar. 20, (3) Conducting two-way vocal com- 1995; Amdt. 195–63, 63 FR 37506, July 13, 1998] munication between a control center and the scene of abnormal operations § 195.412 Inspection of rights-of-way and crossings under navigable and emergencies; and waters. (4) Providing communication with (a) Each operator shall, at intervals fire, police, and other appropriate pub- not exceeding 3 weeks, but at least 26 lic officials during emergency condi- times each calendar year, inspect the tions, including a natural disaster. surface conditions on or adjacent to

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each pipeline right-of-way. Methods of top of the pipe is 36 inches (914 milli- inspection include walking, driving, meters) below the underwater natural flying or other appropriate means of bottom (as determined by recognized traversing the right-of-way. and generally accepted practices) for (b) Except for offshore pipelines, each normal excavation or 18 inches (457 operator shall, at intervals not exceed- millimeters) for rock excavation. ing 5 years, inspect each crossing under (i) An operator may employ engi- a navigable waterway to determine the neered alternatives to burial that meet condition of the crossing. or exceed the level of protection pro- [Amdt. 195–22, 46 FR 38360, July 27, 1981, as vided by burial. amended by Amdt. 195–24, 47 FR 46852, Oct. (ii) If an operator cannot obtain re- 21, 1982; Amdt. 195–52, 59 FR 33397, June 28, quired state or Federal permits in time 1994] to comply with this section, it must notify OPS; specify whether the re- § 195.413 Underwater inspection and quired permit is State or Federal; and, reburial of pipelines in the Gulf of justify the delay. Mexico and its inlets.

(a) Except for gathering lines of 41⁄2 [Amdt. 195–82, 69 FR 48407, Aug. 10, 2004] inches (114mm) nominal outside diame- ter or smaller, each operator shall pre- § 195.414 Inspections of pipelines in pare and follow a procedure to identify areas affected by extreme weather and natural disasters. its pipelines in the Gulf of Mexico and its inlets in waters less than 15 feet (4.6 (a) General. Following an extreme meters) deep as measured from mean weather event or natural disaster that low water that are at risk of being an has the likelihood of damage to infra- exposed underwater pipeline or a haz- structure by the scouring or movement ard to navigation. The procedures must of the soil surrounding the pipeline, be in effect August 10, 2005. such as a named tropical storm or hur- (b) Each operator shall conduct ap- ricane; a flood that exceeds the river, propriate periodic underwater inspec- shoreline, or creek high-water banks in tions of its pipelines in the Gulf of the area of the pipeline; a landslide in Mexico and its inlets in waters less the area of the pipeline; or an earth- than 15 feet (4.6 meters) deep as meas- quake in the area of the pipeline, an ured from mean low water based on the operator must inspect all potentially identified risk. affected pipeline facilities to detect (c) If an operator discovers that its conditions that could adversely affect pipeline is an exposed underwater pipe- the safe operation of that pipeline. line or poses a hazard to navigation, (b) Inspection method. An operator the operator shall— must consider the nature of the event (1) Promptly, but not later than 24 and the physical characteristics, oper- hours after discovery, notify the Na- ating conditions, location, and prior tional Response Center, telephone: 1– history of the affected pipeline in de- 800–424–8802, of the location and, if termining the appropriate method for available, the geographic coordinates performing the initial inspection to de- of that pipeline. termine the extent of any damage and (2) Promptly, but not later than 7 the need for the additional assessments days after discovery, mark the location required under paragraph (a) of this of the pipeline in accordance with 33 section. CFR Part 64 at the ends of the pipeline (c) Time period. The inspection re- segment and at intervals of not over quired under paragraph (a) of this sec- 500 yards (457 meters) long, except that tion must commence within 72 hours a pipeline segment less than 200 yards after the cessation of the event, defined (183 meters) long need only be marked as the point in time when the affected at the center; and area can be safely accessed by the per- (3) Within 6 months after discovery, sonnel and equipment required to per- or not later than November 1 of the fol- form the inspection as determined lowing year if the 6 month period is under paragraph (b) of this section. In later than November 1 of the year of the event that the operator is unable discovery, bury the pipeline so that the to commence the inspection due to the

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unavailability of personnel or equip- pipe with a seam factor less than 1.0 as ment, the operator must notify the ap- defined in § 195.106(e) or lap-welded pipe propriate PHMSA Region Director as susceptible to longitudinal seam fail- soon as practicable. ure must be capable of assessing seam (d) Remedial action. An operator must integrity, cracking, and of detecting take prompt and appropriate remedial corrosion and deformation anomalies. action to ensure the safe operation of a The following alternative assessment pipeline based on the information ob- methods may be used as specified in tained as a result of performing the in- this paragraph: spection required under paragraph (a) (1) A pressure test conducted in ac- of this section. Such actions might in- cordance with subpart E of this part; clude, but are not limited to: (2) External corrosion direct assess- (1) Reducing the operating pressure ment in accordance with § 195.588; or or shutting down the pipeline; (3) Other technology in accordance with paragraph (d). (d) Other technology. Operators may § 195.416 Pipeline assessments. elect to use other technologies if the (a) Scope. This section applies to on- operator can demonstrate the tech- shore line pipe that can accommodate nology can provide an equivalent un- inspection by means of in-line inspec- derstanding of the condition of the line tion tools and is not subject to the in- pipe for threat being assessed. An oper- tegrity management requirements in ator choosing this option must notify § 195.452. the Office of Pipeline Safety (OPS) 90 (b) General. An operator must per- days before conducting the assessment form an initial assessment of each of by: its pipeline segments by October 1, (1) Sending the notification, along 2029, and perform periodic assessments with the information required to dem- of its pipeline segments at least once onstrate compliance with this para- every 10 calendar years from the year graph, to the Information Resources of the prior assessment or as otherwise Manager, Office of Pipeline Safety, necessary to ensure public safety or Pipeline and Hazardous Materials Safe- the protection of the environment. ty Administration, 1200 New Jersey Av- (c) Method. Except as specified in enue SE, Washington, DC 20590; or paragraph (d) of this section, an oper- (2) Sending the notification, along ator must perform the integrity assess- with the information required to dem- ment for the range of relevant threats onstrate compliance with this para- to the pipeline segment by the use of graph, to the Information Resources an appropriate in-line inspection Manager by facsimile to (202) 366–7128. tool(s). When performing an assess- (3) Prior to conducting the ‘‘other ment using an in-line inspection tool, technology’’ assessments, the operator an operator must comply with § 195.591. must receive a notice of ‘‘no objection’’ An operator must explicitly consider from the PHMSA Information Services uncertainties in reported results (in- Manager or Designee. cluding tool tolerance, anomaly find- (e) Data analysis. A person qualified ings, and unity chart plots or other by knowledge, training, and experience equivalent methods for determining must analyze the data obtained from uncertainties) in identifying anoma- an assessment performed under para- lies. If this is impracticable based on graph (b) of this section to determine if operational limits, including operating a condition could adversely affect the pressure, low flow, and pipeline length safe operation of the pipeline. Opera- or availability of in-line inspection tors must consider uncertainties in any tool technology for the pipe diameter, reported results (including tool toler- then the operator must perform the as- ance) as part of that analysis. sessment using the appropriate meth- (f) Discovery of condition. For pur- od(s) in paragraphs (c)(1), (2), or (3) of poses of § 195.401(b)(1), discovery of a this section for the range of relevant condition occurs when an operator has threats being assessed. The methods an adequate information to determine operator selects to assess low-fre- that a condition presenting a potential quency electric resistance welded pipe, threat to the integrity of the pipeline

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exists. An operator must promptly, but designed and constructed as required no later than 180 days after an assess- by this part. ment, obtain sufficient information about a condition to make that deter- § 195.424 Pipe movement. mination required under paragraph (e) (a) No operator may move any line of this section, unless the operator can pipe, unless the pressure in the line demonstrate the 180-day interval is im- section involved is reduced to not more practicable. If the operator believes than 50 percent of the maximum oper- that 180 days are impracticable to ating pressure. make a determination about a condi- (b) No operator may move any pipe- tion found during an assessment, the line containing highly volatile liquids pipeline operator must notify PHMSA where materials in the line section in- and provide an expected date when ade- volved are joined by welding unless— quate information will become avail- (1) Movement when the pipeline does able. This notification must be made in not contain highly volatile liquids is accordance with § 195.452 (m). impractical; (g) Remediation. An operator must (2) The procedures of the operator comply with the requirements in under § 195.402 contain precautions to § 195.401 if a condition that could ad- protect the public against the hazard versely affect the safe operation of a in moving pipelines containing highly pipeline is discovered in complying volatile liquids, including the use of with paragraphs (e) and (f) of this sec- warnings, where necessary, to evacuate tion. the area close to the pipeline; and (h) Consideration of information. An (3) The pressure in that line section operator must consider all relevant in- is reduced to the lower of the fol- formation about a pipeline in com- lowing: plying with the requirements in para- (i) Fifty percent or less of the max- graphs (a) through (g) of this section. imum operating pressure; or (ii) The lowest practical level that [Amdt. 195–102, 84 FR 52295, Oct. 1, 2019] will maintain the highly volatile liquid in a liquid state with continuous flow, §§ 195.417–419 [Reserved] but not less than 50 p.s.i. (345 kPa) gage § 195.420 Valve maintenance. above the vapor pressure of the com- modity. (a) Each operator shall maintain (c) No operator may move any pipe- each valve that is necessary for the line containing highly volatile liquids safe operation of its pipeline systems where materials in the line section in- in good working order at all times. volved are not joined by welding un- (b) Each operator shall, at intervals less— not exceeding 71⁄2 months, but at least (1) The operator complies with para- twice each calendar year, inspect each graphs (b) (1) and (2) of this section; mainline valve to determine that it is and functioning properly. (2) That line section is isolated to (c) Each operator shall provide pro- prevent the flow of highly volatile liq- tection for each valve from unauthor- uid. ized operation and from vandalism. [Amdt. 195–22, 46 FR 38360, July 27, 1981; 46 [Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 FR 38922, July 30, 1981, as amended by Amdt. FR 32721, July 29, 1982, as amended by Amdt. 195–63, 63 FR 37506, July 13, 1998] 195–24, 47 FR 46852, Oct. 21, 1982] § 195.426 Scraper and sphere facilities. § 195.422 Pipeline repairs. No operator may use a launcher or (a) Each operator shall, in repairing receiver that is not equipped with a re- its pipeline systems, insure that the re- lief device capable of safely relieving pairs are made in a safe manner and pressure in the barrel before insertion are made so as to prevent damage to or removal of scrapers or spheres. The persons or property. operator must use a suitable device to (b) No operator may use any pipe, indicate that pressure has been re- valve, or fitting, for replacement in re- lieved in the barrel or must provide a pairing pipeline facilities, unless it is means to prevent insertion or removal

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of scrapers or spheres if pressure has § 195.430 Firefighting equipment. not been relieved in the barrel. Each operator shall maintain ade- [Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 quate firefighting equipment at each FR 32721, July 29, 1982] pump station and breakout tank area. The equipment must be— § 195.428 Overpressure safety devices (a) In proper operating condition at and overfill protection systems. all times; (a) Except as provided in paragraph (b) Plainly marked so that its iden- (b) of this section, each operator shall, tity as firefighting equipment is clear; at intervals not exceeding 15 months, and but at least once each calendar year, or (c) Located so that it is easily acces- in the case of pipelines used to carry sible during a fire. highly volatile liquids, at intervals not to exceed 71⁄2 months, but at least twice § 195.432 Inspection of in-service each calendar year, inspect and test breakout tanks. each pressure limiting device, relief (a) Except for breakout tanks in- valve, pressure regulator, or other item spected under paragraphs (b) and (c) of of pressure control equipment to deter- this section, each operator shall, at in- mine that it is functioning properly, is tervals not exceeding 15 months, but at in good mechanical condition, and is least once each calendar year, inspect adequate from the standpoint of capac- each in-service breakout tank. ity and reliability of operation for the (b) Each operator must inspect the service in which it is used. physical integrity of in-service atmos- (b) In the case of relief valves on pheric and low-pressure steel above- pressure breakout tanks containing ground breakout tanks according to highly volatile liquids, each operator API Std 653 (except section 6.4.3, Alter- shall test each valve at intervals not native Internal Inspection Interval) (in- exceeding 5 years. corporated by reference, see § 195.3). (c) Aboveground breakout tanks that However, if structural conditions pre- are constructed or significantly altered vent access to the tank bottom, its in- according to API Std 2510 (incorporated tegrity may be assessed according to a by reference, see § 195.3) after October 2, plan included in the operations and 2000, must have an overfill protection maintenance manual under system installed according to API Std § 195.402(c)(3). The risk-based internal 2510, section 7.1.2. Other aboveground inspection procedures in API Std 653, breakout tanks with 600 gallons (2271 section 6.4.3 cannot be used to deter- liters) or more of storage capacity that mine the internal inspection interval. are constructed or significantly altered (1) Operators who established inter- after October 2, 2000, must have an nal inspection intervals based on risk- overfill protection system installed ac- based inspection procedures prior to cording to API RP 2350 (incorporated March 6, 2015 must re-establish inter- by reference, see § 195.3). However, an nal inspection intervals based on API operator need not comply with any Std 653, section 6.4.2 (incorporated by part of API RP 2350 for a particular reference, see § 195.3). breakout tank if the operator describes (i) If the internal inspection interval in the manual required by § 195.402 why was determined by the prior risk-based compliance with that part is not nec- inspection procedure using API Std 653, essary for safety of the tank. section 6.4.3 and the resulting calcula- (d) After October 2, 2000, the require- tion exceeded 20 years, and it has been ments of paragraphs (a) and (b) of this more than 20 years since an internal section for inspection and testing of inspection was performed, the operator pressure control equipment apply to must complete a new internal inspec- the inspection and testing of overfill tion in accordance with § 195.432(b)(1) protection systems. by January 5, 2017. (ii) If the internal inspection interval [Amdt. 195–22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195–24, 47 FR 46852, Oct. was determined by the prior risk-based 21, 1982; Amdt. 195–66, 64 FR 15936, Apr. 2, inspection procedure using API Std 653, 1999, as amended by Amdt. 195–100, 80 FR section 6.4.3 and the resulting calcula- 12780, Mar. 11, 2015] tion was less than or equal to 20 years,

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and the time since the most recent in- age of a flammable hazardous liquid or ternal inspection exceeds the re-estab- of the presence of flammable vapors. lished inspection interval in accord- ance with § 195.432(b)(1), the operator § 195.440 Public awareness. must complete a new internal inspec- (a) Each pipeline operator must de- tion by January 5, 2017. velop and implement a written con- (iii) If the internal inspection inter- tinuing public education program that val was not based upon current engi- follows the guidance provided in the neering and operational information American Petroleum Institute’s (API) (i.e., actual corrosion rate of floor Recommended Practice (RP) 1162 (in- plates, actual remaining thickness of corporated by reference, see § 195.3). the floor plates, etc.), the operator (b) The operator’s program must fol- must complete a new internal inspec- low the general program recommenda- tion by January 5, 2017 and re-establish tions of API RP 1162 and assess the a new internal inspection interval in unique attributes and characteristics accordance with § 195.432(b)(1). of the operator’s pipeline and facilities. (2) [Reserved] (c) The operator must follow the gen- (c) Each operator must inspect the eral program recommendations, includ- physical integrity of in-service steel ing baseline and supplemental require- aboveground breakout tanks built to ments of API RP 1162, unless the oper- API Std 2510 (incorporated by ref- ator provides justification in its pro- erence, see § 195.3) according to section gram or procedural manual as to why 6 of API Std 510 (incorporated by ref- compliance with all or certain provi- erence, see § 195.3). sions of the recommended practice is (d) The intervals of inspection speci- not practicable and not necessary for fied by documents referenced in para- safety. graphs (b) and (c) of this section begin (d) The operator’s program must spe- on May 3, 1999, or on the operator’s last cifically include provisions to educate recorded date of the inspection, which- the public, appropriate government or- ever is earlier. ganizations, and persons engaged in ex- cavation related activities on: [Amdt. 195–66, 64 FR 15936, Apr. 2, 1999, as (1) Use of a one-call notification sys- amended by Amdt. 195–94, 75 FR 48607, Aug. tem prior to excavation and other dam- 11, 2010, Amdt. 195–99, 80 FR 187, Jan. 5, 2015; age prevention activities; 80 FR 46848, Aug. 6, 2015] (2) Possible hazards associated with unintended releases from a hazardous § 195.434 Signs. liquid or carbon dioxide pipeline facil- Each operator must maintain signs ity; visible to the public around each pump- (3) Physical indications that such a ing station and breakout tank area. release may have occurred; Each sign must contain the name of (4) Steps that should be taken for the operator and a telephone number public safety in the event of a haz- (including area code) where the oper- ardous liquid or carbon dioxide pipeline ator can be reached at all times. release; and (5) Procedures to report such an [Amdt. 195–78, 68 FR 53528, Sept. 11, 2003] event. § 195.436 Security of facilities. (e) The program must include activi- ties to advise affected municipalities, Each operator shall provide protec- school districts, businesses, and resi- tion for each pumping station and dents of pipeline facility locations. breakout tank area and other exposed (f) The program and the media used facility (such as scraper traps) from must be as comprehensive as necessary vandalism and unauthorized entry. to reach all areas in which the operator transports hazardous liquid or carbon § 195.438 Smoking or open flames. dioxide. Each operator shall prohibit smoking (g) The program must be conducted and open flames in each pump station in English and in other languages com- area and each breakout tank area monly understood by a significant where there is a possibility of the leak- number and concentration of the non-

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English speaking population in the op- (1) The state has adopted a one-call erator’s area. damage prevention program under (h) Operators in existence on June 20, § 198.37 of this chapter; or 2005, must have completed their writ- (2) The one-call system: ten programs no later than June 20, (i) Is operated in accordance with 2006. Upon request, operators must sub- § 198.39 of this chapter; mit their completed programs to (ii) Provides a pipeline operator an PHMSA or, in the case of an intrastate opportunity similar to a voluntary par- pipeline facility operator, the appro- ticipant to have a part in management priate State agency. responsibilities; and (i) The operator’s program docu- (iii) Assesses a participating pipeline mentation and evaluation results must operator a fee that is proportionate to be available for periodic review by ap- the costs of the one-call system’s cov- propriate regulatory agencies. erage of the operator’s pipeline. [Amdt. 195–84, 70 FR 28843, May 19, 2005] (c) The damage prevention program required by paragraph (a) of this sec- § 195.442 Damage prevention program. tion must, at a minimum: (1) Include the identity, on a current (a) Except as provided in paragraph basis, of persons who normally engage (d) of this section, each operator of a in excavation activities in the area in buried pipeline must carry out, in ac- which the pipeline is located. cordance with this section, a written program to prevent damage to that (2) Provides for notification of the pipeline from excavation activities. public in the vicinity of the pipeline For the purpose of this section, the and actual notification of persons iden- term ‘‘excavation activities’’ includes tified in paragraph (c)(1) of this section excavation, blasting, boring, tunneling, of the following as often as needed to backfilling, the removal of above- make them aware of the damage pre- ground structures by either explosive vention program: or mechanical means, and other (i) The program’s existence and pur- earthmoving operations. pose; and (b) An operator may comply with any (ii) How to learn the location of un- of the requirements of paragraph (c) of derground pipelines before excavation this section through participation in a activities are begun. public service program, such as a one- (3) Provide a means of receiving and call system, but such participation recording notification of planned exca- does not relieve the operator of the re- vation activities. sponsibility for compliance with this (4) If the operator has buried pipe- section. However, an operator must lines in the area of excavation activity, perform the duties of paragraph (c)(3) provide for actual notification of per- of this section through participation in sons who give notice of their intent to a one-call system, if that one-call sys- excavate of the type of temporary tem is a qualified one-call system. In marking to be provided and how to areas that are covered by more than identify the markings. one qualified one-call system, an oper- (5) Provide for temporary marking of ator need only join one of the qualified buried pipelines in the area of exca- one-call systems if there is a central vation activity before, as far as prac- telephone number for excavators to tical, the activity begins. call for excavation activities, or if the (6) Provide as follows for inspection one-call systems in those areas com- of pipelines that an operator has rea- municate with one another. An opera- son to believe could be damaged by ex- tor’s pipeline system must be covered cavation activities: by a qualified one-call system where (i) The inspection must be done as there is one in place. For the purpose frequently as necessary during and of this section, a one-call system is after the activities to verify the integ- considered a ‘‘qualified one-call sys- rity of the pipeline; and tem’’ if it meets the requirements of (ii) In the case of blasting, any in- section (b)(1) or (b)(2) or this section. spection must include leakage surveys.

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(d) A damage prevention program schedule. The procedures required by under this section is not required for paragraphs (b), (c)(5), (d)(2) and (d)(3), the following pipelines: (f) and (g) of this section must be im- (1) Pipelines located offshore. plemented no later than October 1, (2) Pipelines to which access is phys- 2011. The procedures required by para- ically controlled by the operator. graphs (c)(1) through (4), (d)(1), (d)(4), and (e) must be implemented no later [Amdt. 195–54, 60 FR 14651, Mar. 20, 1995, as amended by Amdt. 195–60, 62 FR 61699, Nov. than August 1, 2012. The training proce- 19, 1997] dures required by paragraph (h) must be implemented no later than August 1, § 195.444 Leak detection. 2012, except that any training required (a) Scope. Except for offshore gath- by another paragraph of this section ering and regulated rural gathering must be implemented no later than the pipelines, this section applies to all deadline for that paragraph. hazardous liquid pipelines transporting (b) Roles and responsibilities. Each op- liquid in single phase (without gas in erator must define the roles and re- the liquid). sponsibilities of a controller during (b) General. A pipeline must have an normal, abnormal, and emergency op- effective system for detecting leaks in erating conditions. To provide for a accordance with §§ 195.134 or 195.452, as controller’s prompt and appropriate re- appropriate. An operator must evalu- sponse to operating conditions, an op- ate the capability of its leak detection erator must define each of the fol- system to protect the public, property, lowing: and the environment and modify it as (1) A controller’s authority and re- necessary to do so. At a minimum, an sponsibility to make decisions and operator’s evaluation must consider take actions during normal operations; the following factors—length and size (2) A controller’s role when an abnor- of the pipeline, type of product carried, mal operating condition is detected, the swiftness of leak detection, loca- even if the controller is not the first to tion of nearest response personnel, and detect the condition, including the con- leak history. troller’s responsibility to take specific (c) CPM leak detection systems. Each actions and to communicate with oth- computational pipeline monitoring ers; (CPM) leak detection system installed (3) A controller’s role during an on a hazardous liquid pipeline must emergency, even if the controller is not comply with API RP 1130 (incorporated the first to detect the emergency, in- by reference, see § 195.3) in operating, cluding the controller’s responsibility maintaining, testing, record keeping, to take specific actions and to commu- and dispatcher training of the system. nicate with others; (4) A method of recording controller [Amdt. 195–102, 84 FR 52296, Oct. 1, 2019] shift-changes and any hand-over of re- sponsibility between controllers; and § 195.446 Control room management. (5) The roles, responsibilities and (a) General. This section applies to qualifications of others who have the each operator of a pipeline facility authority to direct or supersede the with a controller working in a control specific technical actions of control- room who monitors and controls all or lers. part of a pipeline facility through a (c) Provide adequate information. Each SCADA system. Each operator must operator must provide its controllers have and follow written control room with the information, tools, processes management procedures that imple- and procedures necessary for the con- ment the requirements of this section. trollers to carry out the roles and re- The procedures required by this section sponsibilities the operator has defined must be integrated, as appropriate, by performing each of the following: with the operator’s written procedures (1) Implement API RP 1165 (incor- required by § 195.402. An operator must porated by reference, see § 195.3) when- develop the procedures no later than ever a SCADA system is added, ex- August 1, 2011, and must implement the panded or replaced, unless the operator procedures according to the following demonstrates that certain provisions of

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API RP 1165 are not practical for the that have been taken off scan in the SCADA system used; SCADA host, have had alarms inhib- (2) Conduct a point-to-point ited, generated false alarms, or that verification between SCADA displays have had forced or manual values for and related field equipment when field periods of time exceeding that required equipment is added or moved and when for associated maintenance or oper- other changes that affect pipeline safe- ating activities; ty are made to field equipment or (3) Verify the correct safety-related SCADA displays; alarm set-point values and alarm de- (3) Test and verify an internal com- scriptions when associated field instru- munication plan to provide adequate ments are calibrated or changed and at means for manual operation of the least once each calendar year, but at pipeline safely, at least once each cal- intervals not to exceed 15 months; endar year, but at intervals not to ex- (4) Review the alarm management ceed 15 months; plan required by this paragraph at (4) Test any backup SCADA systems least once each calendar year, but at at least once each calendar year, but at intervals not exceeding 15 months, to intervals not to exceed 15 months; and determine the effectiveness of the plan; (5) Implement section 5 of API RP (5) Monitor the content and volume 1168 (incorporated by reference, see of general activity being directed to § 195.3) to establish procedures for when and required of each controller at least a different controller assumes responsi- once each calendar year, but at inter- bility, including the content of infor- vals not exceeding 15 months, that will mation to be exchanged. assure controllers have sufficient time (d) Fatigue mitigation. Each operator to analyze and react to incoming must implement the following methods alarms; and to reduce the risk associated with con- troller fatigue that could inhibit a con- (6) Address deficiencies identified troller’s ability to carry out the roles through the implementation of para- and responsibilities the operator has graphs (e)(1) through (e)(5) of this sec- defined: tion. (1) Establish shift lengths and sched- (f) Change management. Each operator ule rotations that provide controllers must assure that changes that could off-duty time sufficient to achieve affect control room operations are co- eight hours of continuous sleep; ordinated with the control room per- (2) Educate controllers and super- sonnel by performing each of the fol- visors in fatigue mitigation strategies lowing: and how off-duty activities contribute (1) Implement section 7 of API RP to fatigue; 1168 (incorporated by reference, see (3) Train controllers and supervisors § 195.3) for control room management to recognize the effects of fatigue; and change and require coordination be- (4) Establish a maximum limit on tween control room representatives, controller hours-of-service, which may operator’s management, and associated provide for an emergency deviation field personnel when planning and im- from the maximum limit if necessary plementing physical changes to pipe- for the safe operation of a pipeline fa- line equipment or configuration; and cility. (2) Require its field personnel to con- (e) Alarm management. Each operator tact the control room when emergency using a SCADA system must have a conditions exist and when making field written alarm management plan to changes that affect control room oper- provide for effective controller re- ations. sponse to alarms. An operator’s plan (g) Operating experience. Each oper- must include provisions to: ator must assure that lessons learned (1) Review SCADA safety-related from its operating experience are in- alarm operations using a process that corporated, as appropriate, into its ensures alarms are accurate and sup- control room management procedures port safe pipeline operations; by performing each of the following: (2) Identify at least once each cal- (1) Review accidents that must be re- endar month points affecting safety ported pursuant to § 195.50 and 195.52 to

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determine if control room actions con- (i) Compliance validation. Upon re- tributed to the event and, if so, cor- quest, operators must submit their pro- rect, where necessary, deficiencies re- cedures to PHMSA or, in the case of an lated to: intrastate pipeline facility regulated (i) Controller fatigue; by a State, to the appropriate State (ii) Field equipment; agency. (iii) The operation of any relief de- (j) Compliance and deviations. An oper- vice; ator must maintain for review during (iv) Procedures; inspection: (v) SCADA system configuration; and (1) Records that demonstrate compli- ance with the requirements of this sec- (vi) SCADA system performance. tion; and (2) Include lessons learned from the (2) Documentation to demonstrate operator’s experience in the training that any deviation from the procedures program required by this section. required by this section was necessary (h) Training. Each operator must es- for the safe operation of the pipeline tablish a controller training program facility. and review the training program con- tent to identify potential improve- [Amdt. 195–93, 74 FR 63329, Dec. 3, 2009, as ments at least once each calendar year, amended at 75 FR 5537, Feb. 3, 2010; 76 FR but at intervals not to exceed 15 35135, June 16, 2011; Amdt. 195–101, 82 FR 7999, Jan. 23, 2017] months. An operator’s program must provide for training each controller to HIGH CONSEQUENCE AREAS carry out the roles and responsibilities defined by the operator. In addition, § 195.450 Definitions. the training program must include the The following definitions apply to following elements: this section and § 195.452: (1) Responding to abnormal operating Emergency flow restricting device or conditions likely to occur simulta- EFRD means a check valve or remote neously or in sequence; control valve as follows: (2) Use of a computerized simulator (1) Check valve means a valve that or non-computerized (tabletop) method permits fluid to flow freely in one di- for training controllers to recognize rection and contains a mechanism to abnormal operating conditions; automatically prevent flow in the (3) Training controllers on their re- other direction. sponsibilities for communication under (2) Remote control valve or RCV means the operator’s emergency response pro- any valve that is operated from a loca- cedures; tion remote from where the valve is in- (4) Training that will provide a con- stalled. The RCV is usually operated by troller a working knowledge of the the supervisory control and data acqui- pipeline system, especially during the sition (SCADA) system. The linkage development of abnormal operating between the pipeline control center and conditions; the RCV may be by fiber optics, micro- (5) For pipeline operating setups that wave, telephone lines, or satellite. are periodically, but infrequently used, High consequence area means: providing an opportunity for control- (1) A commercially navigable waterway, lers to review relevant procedures in which means a waterway where a sub- advance of their application; and stantial likelihood of commercial navi- (6) Control room team training and gation exists; exercises that include both controllers (2) A high population area, which and other individuals, defined by the means an urbanized area, as defined operator, who would reasonably be ex- and delineated by the Census Bureau, pected to operationally collaborate that contains 50,000 or more people and with controllers (control room per- has a population density of at least sonnel) during normal, abnormal or 1,000 people per square mile; emergency situations. Operators must (3) An other populated area, which comply with the team training require- means a place, as defined and delin- ments under this paragraph no later eated by the Census Bureau, that con- than January 23, 2018. tains a concentrated population, such

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as an incorporated or unincorporated (2) Include in the program an identi- city, town, village, or other designated fication of each pipeline or pipeline residential or commercial area; segment in the first column of the fol- (4) An unusually sensitive area, as de- lowing table not later than the date in fined in § 195.6. the second column:

[Amdt. 195–70, 65 FR 75405, Dec. 1, 2000] Pipeline Date

Category 1 ...... December 31, 2001. PIPELINE INTEGRITY MANAGEMENT Category 2 ...... November 18, 2002. Category 3 ...... Date the pipeline begins op- § 195.452 Pipeline integrity manage- eration. ment in high consequence areas. (3) Include in the program a plan to (a) Which pipelines are covered by this carry out baseline assessments of line section? This section applies to each pipe as required by paragraph (c) of hazardous liquid pipeline and carbon this section. dioxide pipeline that could affect a (4) Include in the program a frame- high consequence area, including any work that— pipeline located in a high consequence (i) Addresses each element of the in- area unless the operator effectively tegrity management program under demonstrates by risk assessment that paragraph (f) of this section, including the pipeline could not affect the area. continual integrity assessment and (Appendix C of this part provides guid- evaluation under paragraph (j) of this ance on determining if a pipeline could section; and affect a high consequence area.) Cov- (ii) Initially indicates how decisions ered pipelines are categorized as fol- will be made to implement each ele- lows: ment. (1) Category 1 includes pipelines ex- (5) Implement and follow the pro- isting on May 29, 2001, that were owned gram. or operated by an operator who owned (6) Follow recognized industry prac- or operated a total of 500 or more miles tices in carrying out this section, un- of pipeline subject to this part. less— (2) Category 2 includes pipelines ex- (i) This section specifies otherwise; isting on May 29, 2001, that were owned or or operated by an operator who owned (ii) The operator demonstrates that or operated less than 500 miles of pipe- an alternative practice is supported by line subject to this part. a reliable engineering evaluation and (3) Category 3 includes pipelines con- provides an equivalent level of public structed or converted after May 29, safety and environmental protection. 2001, and low-stress pipelines in rural (c) What must be in the baseline assess- areas under § 195.12. ment plan? (1) An operator must include (4) Low stress pipelines as specified each of the following elements in its in § 195.12. written baseline assessment plan: (b) What program and practices must (i) The methods selected to assess the operators use to manage pipeline integ- integrity of the line pipe. An operator rity? Each operator of a pipeline cov- must assess the integrity of the line ered by this section must: pipe by in-line inspection tool(s) de- (1) Develop a written integrity man- scribed in paragraph (c)(1)(i)(A) of this agement program that addresses the section for the range of relevant risks on each segment of pipeline in threats to the pipeline segment. If it is the first column of the following table impracticable based upon the construc- no later than the date in the second tion of the pipeline (e.g., diameter column: changes, sharp bends, and elbows) or operational limits including operating Pipeline Date pressure, low flow, pipeline length, or Category 1 ..... March 31, 2002. availability of in-line inspection tool Category 2 ..... February 18, 2003. technology for the pipe diameter, then Category 3 ..... Date the pipeline begins operation or as the operator must use the appropriate provided in § 195.12 for low stress pipe- method(s) in paragraphs (c)(1)(i)(B), lines in rural areas. (C), or (D) of this section for the range

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of relevant threats to the pipeline seg- pipeline begins operation through the ment. The methods an operator selects development of procedures, identifica- to assess low-frequency electric resist- tion of high consequence areas, and ance welded pipe, pipe with a seam fac- pressure testing of could-affect high tor less than 1.0 as defined in § 195.106(e) consequence areas in accordance with or lap-welded pipe susceptible to longi- § 195.304. tudinal seam failure, must be capable (2) Newly identified areas. If an oper- of assessing seam integrity, cracking, ator obtains information (whether and of detecting corrosion and defor- from the information analysis required mation anomalies. under paragraph (g) of this section, (A) In-line inspection tool or tools Census Bureau maps, or any other capable of detecting corrosion and de- source) demonstrating that the area formation anomalies including dents, around a pipeline segment has changed gouges, and grooves. For pipeline seg- to meet the definition of a high con- ments with an identified or probable sequence area (see § 195.450), that area risk or threat related to cracks (such must be incorporated into the opera- as at pipe body or weld seams) based on tor’s baseline assessment plan within 1 the risk factors specified in paragraph year from the date that the informa- (e), an operator must use an in-line in- tion is obtained. An operator must spection tool or tools capable of detect- complete the baseline assessment of ing crack anomalies. When performing any pipeline segment that could affect an assessment using an in-line inspec- a newly identified high consequence tion tool, an operator must comply area within 5 years from the date an with § 195.591. An operator using this operator identifies the area. method must explicitly consider uncer- (e) What are the risk factors for estab- tainties in reported results (including lishing an assessment schedule (for both tool tolerance, anomaly findings, and the baseline and continual integrity as- unity chart plots or equivalent for de- sessments)? (1) An operator must estab- termining uncertainties) in identifying lish an integrity assessment schedule anomalies; that prioritizes pipeline segments for (B) Pressure test conducted in ac- assessment (see paragraphs (d)(1) and cordance with subpart E of this part; (j)(3) of this section). An operator must (C) External corrosion direct assess- base the assessment schedule on all ment in accordance with § 195.588; or risk factors that reflect the risk condi- (D) Other technology that the oper- tions on the pipeline segment. The fac- ator demonstrates can provide an tors an operator must consider include, equivalent understanding of the condi- but are not limited to: tion of the line pipe. An operator (i) Results of the previous integrity choosing this option must notify the assessment, defect type and size that Office of Pipeline Safety (OPS) 90 days the assessment method can detect, and before conducting the assessment, by defect growth rate; sending a notice to the address or fac- (ii) Pipe size, material, manufac- simile number specified in paragraph turing information, coating type and (m) of this section. condition, and seam type; (ii) A schedule for completing the in- (iii) Leak history, repair history and tegrity assessment; cathodic protection history; (iii) An explanation of the assess- (iv) Product transported; ment methods selected and evaluation (v) Operating stress level; of risk factors considered in estab- (vi) Existing or projected activities lishing the assessment schedule. in the area; (2) An operator must document, prior (vii) Local environmental factors to implementing any changes to the that could affect the pipeline (e.g., plan, any modification to the plan, and seismicity, corrosivity of soil, subsid- reasons for the modification. ence, climatic); (d) When must operators complete base- (viii) geo-technical hazards; and line assessments? (ix) Physical support of the segment (1) All pipelines. An operator must such as by a cable suspension bridge. complete the baseline assessment be- (2) Appendix C of this part provides fore a new or conversion-to-service further guidance on risk factors.

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(f) What are the elements of an integrity ments specified in this section starting management program? An integrity October 1, 2020, with all attributes inte- management program begins with the grated by October 1, 2022. This analysis initial framework. An operator must must: continually change the program to re- (1) Integrate information and at- flect operating experience, conclusions tributes about the pipeline that in- drawn from results of the integrity as- clude, but are not limited to: sessments, and other maintenance and (i) Pipe diameter, wall thickness, surveillance data, and evaluation of grade, and seam type; consequences of a failure on the high (ii) Pipe coating, including girth weld consequence area. An operator must in- coating; clude, at minimum, each of the fol- (iii) Maximum operating pressure lowing elements in its written integ- (MOP) and temperature; rity management program: (iv) Endpoints of segments that could (1) A process for identifying which affect high consequence areas (HCAs); pipeline segments could affect a high (v) Hydrostatic test pressure includ- consequence area; ing any test failures or leaks—if (2) A baseline assessment plan meet- known; ing the requirements of paragraph (c) (vi) Location of casings and if short- of this section; ed; (3) An analysis that integrates all (vii) Any in-service ruptures or available information about the integ- leaks—including identified causes; rity of the entire pipeline and the con- (viii) Data gathered through integ- sequences of a failure (see paragraph rity assessments required under this (g) of this section); section; (4) Criteria for remedial actions to (ix) Close interval survey (CIS) sur- address integrity issues raised by the vey results; assessment methods and information (x) Depth of cover surveys; analysis (see paragraph (h) of this sec- (xi) Corrosion protection (CP) rec- tion); tifier readings; (5) A continual process of assessment (xii) CP test point survey readings and evaluation to maintain a pipeline’s and locations; integrity (see paragraph (j) of this sec- (xiii) AC/DC and foreign structure in- tion); terference surveys; (6) Identification of preventive and (xiv) Pipe coating surveys and ca- mitigative measures to protect the thodic protection surveys. high consequence area (see paragraph (xv) Results of examinations of ex- (i) of this section); posed portions of buried pipelines (i.e., (7) Methods to measure the program’s pipe and pipe coating condition, see effectiveness (see paragraph (k) of this § 195.569); section); (xvi) Stress corrosion cracking (SCC) (8) A process for review of integrity and other cracking (pipe body or weld) assessment results and information excavations and findings, including in- analysis by a person qualified to evalu- situ non-destructive examinations and ate the results and information (see analysis results for failure stress pres- paragraph (h)(2) of this section). sures and cyclic fatigue crack growth (g) What is an information analysis? In analysis to estimate the remaining life periodically evaluating the integrity of of the pipeline; each pipeline segment (see paragraph (xvii) Aerial photography; (j) of this section), an operator must (xviii) Location of foreign line cross- analyze all available information about ings; the integrity of its entire pipeline and (xix) Pipe exposures resulting from the consequences of a possible failure repairs and encroachments; along the pipeline. Operators must con- (xx) Seismicity of the area; and tinue to comply with the data integra- (xxi) Other pertinent information de- tion elements specified in § 195.452(g) rived from operations and maintenance that were in effect on October 1, 2018, activities and any additional tests, in- until October 1, 2022. Operators must spections, surveys, patrols, or moni- begin to integrate all the data ele- toring required under this part.

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(2) Consider information critical to the operator must notify PHMSA in ac- determining the potential for, and pre- cordance with paragraph (m) of this venting, damage due to excavation, in- section and explain the reasons for the cluding current and planned damage delay. An operator must also take fur- prevention activities, and development ther remedial action to ensure the safe- or planned development along the pipe- ty of the pipeline. line; (2) Discovery of condition. Discovery of (3) Consider how a potential failure a condition occurs when an operator would affect high consequence areas, has adequate information to determine such as location of a water intake. that a condition presenting a potential (4) Identify spatial relationships threat to the integrity of the pipeline among anomalous information (e.g., exists. An operator must promptly, but corrosion coincident with foreign line no later than 180 days after an assess- crossings; evidence of pipeline damage ment, obtain sufficient information where aerial photography shows evi- about a condition to make that deter- dence of encroachment). Storing the mination, unless the operator can dem- information in a geographic informa- onstrate the 180-day interval is imprac- tion system (GIS), alone, is not suffi- ticable. If the operator believes that cient. An operator must analyze for 180 days are impracticable to make a interrelationships among the data. determination about a condition found (h) What actions must an operator take during an assessment, the pipeline op- —(1) to address integrity issues? General erator must notify PHMSA in accord- requirements. An operator must take ance with paragraph (m) of this section prompt action to address all anomalous and provide an expected date when ade- conditions in the pipeline that the op- quate information will become avail- erator discovers through the integrity able. assessment or information analysis. In addressing all conditions, an operator (3) Schedule for evaluation and remedi- must evaluate all anomalous condi- ation. An operator must complete re- tions and remediate those that could mediation of a condition according to a reduce a pipeline’s integrity, as re- schedule prioritizing the conditions for quired by this part. An operator must evaluation and remediation. If an oper- be able to demonstrate that the reme- ator cannot meet the schedule for any diation of the condition will ensure condition, the operator must explain that the condition is unlikely to pose a the reasons why it cannot meet the threat to the long-term integrity of the schedule and how the changed schedule pipeline. An operator must comply will not jeopardize public safety or en- with all other applicable requirements vironmental protection. in this part in remediating a condition. (4) Special requirements for scheduling Each operator must, in repairing its remediation—(i) Immediate repair condi- pipeline systems, ensure that the re- tions. An operator’s evaluation and re- pairs are made in a safe and timely mediation schedule must provide for manner and are made so as to prevent immediate repair conditions. To main- damage to persons, property, or the en- tain safety, an operator must tempo- vironment. The calculation method(s) rarily reduce the operating pressure or used for anomaly evaluation must be shut down the pipeline until the oper- applicable for the range of relevant ator completes the repair of these con- threats. ditions. An operator must calculate the (i) Temporary pressure reduction. An temporary reduction in operating pres- operator must notify PHMSA, in ac- sure using the formulas referenced in cordance with paragraph (m) of this paragraph (h)(4)(i)(B) of this section. If section, if the operator cannot meet no suitable remaining strength calcula- the schedule for evaluation and reme- tion method can be identified, an oper- diation required under paragraph (h)(3) ator must implement a minimum 20 of this section and cannot provide safe- percent or greater operating pressure ty through a temporary reduction in reduction, based on actual operating operating pressure. pressure for two months prior to the (ii) Long-term pressure reduction. When date of inspection, until the anomaly is a pressure reduction exceeds 365 days, repaired. An operator must treat the

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following conditions as immediate re- depth for a pipeline diameter less than pair conditions: NPS 12). (A) Metal loss greater than 80% of (C) A dent located on the bottom of nominal wall regardless of dimensions. the pipeline with a depth greater than (B) A calculation of the remaining 6% of the pipeline’s diameter. strength of the pipe shows a predicted (D) A calculation of the remaining burst pressure less than the established strength of the pipe shows an operating maximum operating pressure at the lo- pressure that is less than the current cation of the anomaly. Suitable re- established maximum operating pres- maining strength calculation methods sure at the location of the anomaly. include, but are not limited to, ASME/ Suitable remaining strength calcula- ANSI B31G (incorporated by reference, tion methods include, but are not lim- see § 195.3) and PRCI PR–3–805 (R– ited to, ASME/ANSI B31G and PRCI STRENG) (incorporated by reference, PR–3–805 (R–STRENG). see § 195.3). (E) An area of general corrosion with (C) A dent located on the top of the a predicted metal loss greater than 50% pipeline (above the 4 and 8 o’clock posi- of nominal wall. tions) that has any indication of metal (F) Predicted metal loss greater than loss, cracking or a stress riser. 50% of nominal wall that is located at (D) A dent located on the top of the a crossing of another pipeline, or is in pipeline (above the 4 and 8 o’clock posi- an area with widespread circumferen- tions) with a depth greater than 6% of tial corrosion, or is in an area that the nominal pipe diameter. could affect a girth weld. (E) An anomaly that in the judgment (G) A potential crack indication that of the person designated by the oper- when excavated is determined to be a ator to evaluate the assessment results crack. requires immediate action. (H) Corrosion of or along a longitu- (ii) 60-day conditions. Except for con- dinal seam weld. ditions listed in paragraph (h)(4)(i) of (I) A gouge or groove greater than this section, an operator must schedule 12.5% of nominal wall. evaluation and remediation of the fol- (iv) Other conditions. In addition to lowing conditions within 60 days of dis- the conditions listed in paragraphs covery of condition. (h)(4)(i) through (iii) of this section, an (A) A dent located on the top of the operator must evaluate any condition pipeline (above the 4 and 8 o’clock posi- identified by an integrity assessment tions) with a depth greater than 3% of or information analysis that could im- the pipeline diameter (greater than pair the integrity of the pipeline, and 0.250 inches in depth for a pipeline di- as appropriate, schedule the condition ameter less than Nominal Pipe Size for remediation. Appendix C of this (NPS) 12). part contains guidance concerning (B) A dent located on the bottom of other conditions that an operator the pipeline that has any indication of should evaluate. metal loss, cracking or a stress riser. (i) What preventive and mitigative (iii) 180-day conditions. Except for measures must an operator take to protect conditions listed in paragraph (h)(4)(i) the high consequence area?—(1) General or (ii) of this section, an operator must requirements. An operator must take schedule evaluation and remediation of measures to prevent and mitigate the the following within 180 days of dis- consequences of a pipeline failure that covery of the condition: could affect a high consequence area. (A) A dent with a depth greater than These measures include conducting a 2% of the pipeline’s diameter (0.250 risk analysis of the pipeline segment to inches in depth for a pipeline diameter identify additional actions to enhance less than NPS 12) that affects pipe cur- public safety or environmental protec- vature at a girth weld or a longitudinal tion. Such actions may include, but are seam weld. not limited to, implementing damage (B) A dent located on the top of the prevention best practices, better moni- pipeline (above 4 and 8 o’clock posi- toring of cathodic protection where tion) with a depth greater than 2% of corrosion is a concern, establishing the pipeline’s diameter (0.250 inches in shorter inspection intervals, installing

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EFRDs on the pipeline segment, modi- mination, an operator must, at least, fying the systems that monitor pres- consider the following factors—the sure and detect leaks, providing addi- swiftness of leak detection and pipeline tional training to personnel on re- shutdown capabilities, the type of com- sponse procedures, conducting drills modity carried, the rate of potential with local emergency responders and leakage, the volume that can be re- adopting other management controls. leased, topography or pipeline profile, (2) Risk analysis criteria. In identi- the potential for ignition, proximity to fying the need for additional preven- power sources, location of nearest re- tive and mitigative measures, an oper- sponse personnel, specific terrain be- ator must evaluate the likelihood of a tween the pipeline segment and the pipeline release occurring and how a high consequence area, and benefits ex- release could affect the high con- pected by reducing the spill size. sequence area. This determination (j) What is a continual process of eval- must consider all relevant risk factors, uation and assessment to maintain a pipe- including, but not limited to: line’s integrity?—(1) General. After com- (i) Terrain surrounding the pipeline pleting the baseline integrity assess- segment, including drainage systems ment, an operator must continue to as- such as small streams and other small- sess the line pipe at specified intervals er waterways that could act as a con- and periodically evaluate the integrity duit to the high consequence area; of each pipeline segment that could af- (ii) Elevation profile; fect a high consequence area. (iii) Characteristics of the product (2) Verifying covered segments. An op- transported; erator must verify the risk factors used (iv) Amount of product that could be released; in identifying pipeline segments that (v) Possibility of a spillage in a farm could affect a high consequence area on field following the drain tile into a wa- at least an annual basis not to exceed terway; 15 months (Appendix C of this part pro- (vi) Ditches along side a roadway the vides additional guidance on factors pipeline crosses; that can influence whether a pipeline (vii) Physical support of the pipeline segment could affect a high con- segment such as by a cable suspension sequence area). If a change in cir- bridge; cumstance indicates that the prior con- (viii) Exposure of the pipeline to op- sideration of a risk factor is no longer erating pressure exceeding established valid or that an operator should con- maximum operating pressure; sider new risk factors, an operator (ix) Seismicity of the area. must perform a new integrity analysis (3) Leak detection. An operator must and evaluation to establish the have a means to detect leaks on its endpoints of any previously identified pipeline system. An operator must covered segments. The integrity anal- evaluate the capability of its leak de- ysis and evaluation must include con- tection means and modify, as nec- sideration of the results of any baseline essary, to protect the high consequence and periodic integrity assessments (see area. An operator’s evaluation must, at paragraphs (b), (c), (d), and (e) of this least, consider, the following factors— section), information analyses (see length and size of the pipeline, type of paragraph (g) of this section), and deci- product carried, the pipeline’s prox- sions about remediation and preventive imity to the high consequence area, and mitigative actions (see paragraphs the swiftness of leak detection, loca- (h) and (i) of this section). An operator tion of nearest response personnel, leak must complete the first annual history, and risk assessment results. verification under this paragraph no (4) Emergency Flow Restricting Devices later than July 1, 2021. (EFRD). If an operator determines that (3) Assessment intervals. An operator an EFRD is needed on a pipeline seg- must establish five-year intervals, not ment to protect a high consequence to exceed 68 months, for continually area in the event of a hazardous liquid assessing the line pipe’s integrity. An pipeline release, an operator must in- operator must base the assessment in- stall the EFRD. In making this deter- tervals on the risk the line pipe poses

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to the high consequence area to deter- and of detecting corrosion and defor- mine the priority for assessing the mation anomalies. pipeline segments. An operator must (i) In-Line Inspection tool or tools establish the assessment intervals capable of detecting corrosion and de- based on the factors specified in para- formation anomalies, including dents, graph (e) of this section, the analysis of gouges, and grooves. For pipeline seg- the results from the last integrity as- ments that are susceptible to cracks sessment, and the information analysis (pipe body and weld seams), an oper- required by paragraph (g) of this sec- ator must use an in-line inspection tool tion. or tools capable of detecting crack (4) Variance from the 5-year intervals in anomalies. When performing an assess- limited situations—(i) Engineering basis. ment using an In-Line Inspection tool, An operator may be able to justify an an operator must comply with § 195.591; engineering basis for a longer assess- (ii) Pressure test conducted in ac- ment interval on a segment of line cordance with subpart E of this part; pipe. The justification must be sup- (iii) External corrosion direct assess- ported by a reliable engineering eval- ment in accordance with § 195.588; or uation combined with the use of other (iv) Other technology that the oper- technology, such as external moni- ator demonstrates can provide an toring technology, that provides an un- equivalent understanding of the condi- derstanding of the condition of the line tion of the line pipe. An operator pipe equivalent to that which can be choosing this option must notify OPS 90 days before conducting the assess- obtained from the assessment methods ment, by sending a notice to the ad- allowed in paragraph (j)(5) of this sec- dress or facsimile number specified in tion. An operator must notify OPS 270 paragraph (m) of this section. days before the end of the five-year (or (k) What methods to measure program less) interval of the justification for a effectiveness must be used? An operator’s longer interval, and propose an alter- program must include methods to native interval. An operator must send measure whether the program is effec- the notice to the address specified in tive in assessing and evaluating the in- paragraph (m) of this section. tegrity of each pipeline segment and in (ii) Unavailable technology. An oper- protecting the high consequence areas. ator may require a longer assessment See Appendix C of this part for guid- period for a segment of line pipe (for ance on methods that can be used to example, because sophisticated inter- evaluate a program’s effectiveness. nal inspection technology is not avail- (l) What records must an operator keep able). An operator must justify the rea- to demonstrate compliance? (1) An oper- sons why it cannot comply with the re- ator must maintain, for the useful life quired assessment period and must also of the pipeline, records that dem- demonstrate the actions it is taking to onstrate compliance with the require- evaluate the integrity of the pipeline ments of this subpart. At a minimum, segment in the interim. An operator an operator must maintain the fol- must notify OPS 180 days before the lowing records for review during an in- end of the five-year (or less) interval spection: that the operator may require a longer (i) A written integrity management assessment interval, and provide an es- program in accordance with paragraph timate of when the assessment can be (b) of this section. completed. An operator must send a (ii) Documents to support the deci- notice to the address specified in para- sions and analyses, including any graph (m) of this section. modifications, justifications, devi- (5) Assessment methods. An operator ations and determinations made, must assess the integrity of the line variances, and actions taken, to imple- pipe by any of the following methods. ment and evaluate each element of the The methods an operator selects to as- integrity management program listed sess low frequency electric resistance in paragraph (f) of this section. welded pipe or lap welded pipe suscep- (2) See Appendix C of this part for ex- tible to longitudinal seam failure must amples of records an operator would be be capable of assessing seam integrity required to keep.

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(m) How does an operator notify year after the date of the notice of the PHMSA? An operator must provide any denial. notification required by this section [Amdt. 195–70, 65 FR 75406, Dec. 1, 2000] by: (1) Sending the notification by elec- EDITORIAL NOTES: 1. For FEDERAL REGISTER citations affecting § 195.452, see the List of tronic mail to CFR Sections Affected, which appears in the [email protected]; Finding Aids section of the printed volume or and at www.govinfo.gov. (2) Sending the notification by mail 2. At 84 FR 52296, Oct. 1, 2019, § 195.452 was to ATTN: Information Resources Man- amended by adding paragraph (o); however, ager, DOT/PHMSA/OPS, East Building, the amendment could not be incorporated 2nd Floor, E22–321, 1200 New Jersey Ave because the revised text was not provided. SE., Washington, DC 20590. § 195.454 Integrity assessments for cer- (n) Accommodation of instrumented in- tain underwater hazardous liquid ternal inspection devices— pipeline facilities located in high (1) Scope. This paragraph does not consequence areas. apply to any pipeline facilities listed in Notwithstanding any pipeline integ- § 195.120(b). rity management program or integrity (2) General. An operator must ensure assessment schedule otherwise required that each pipeline is modified to ac- under § 195.452, each operator of any un- commodate the passage of an instru- derwater hazardous liquid pipeline fa- mented internal inspection device by cility located in a high consequence July 2, 2040. area that is not an offshore pipeline fa- (3) Newly identified areas. If a pipeline cility and any portion of which is lo- could affect a newly identified high cated at depths greater than 150 feet consequence area (see paragraph (d)(2) under the surface of the water must en- of this section) after July 2, 2035, an op- sure that: erator must modify the pipeline to ac- (a) Pipeline integrity assessments commodate the passage of an instru- using internal inspection technology mented internal inspection device appropriate for the integrity threats to within 5 years of the date of identifica- the pipeline are completed not less tion or before performing the baseline often than once every 12 months, and; assessment, whichever is sooner. (b) Pipeline integrity assessments using pipeline route surveys, depth of (4) Lack of accommodation. An oper- cover surveys, pressure tests, external ator may file a petition under § 190.9 of corrosion direct assessment, or other this chapter for a finding that the basic technology that the operator dem- construction (i.e., length, diameter, op- onstrates can further the under- erating pressure, or location) of a pipe- standing of the condition of the pipe- line cannot be modified to accommo- line facility, are completed on a sched- date the passage of an instrumented in- ule based on the risk that the pipeline ternal inspection device or that the op- facility poses to the high consequence erator determines it would abandon or area in which the pipeline facility is lo- shut-down a pipeline as a result of the cated. cost to comply with the requirement of this section. [Amdt. 195–102, 84 FR 52298, Oct. 1, 2019] (5) Emergencies. An operator may file a petition under § 190.9 of this chapter Subpart G—Qualification of for a finding that a pipeline cannot be Pipeline Personnel modified to accommodate the passage of an instrumented internal inspection SOURCE: Amdt. 195–67, 64 FR 46866, Aug. 27, device as a result of an emergency. An 1999, unless otherwise noted. operator must file such a petition with- in 30 days after discovering the emer- § 195.501 Scope. gency. If the petition is denied, the op- (a) This subpart prescribes the min- erator must modify the pipeline to imum requirements for operator quali- allow the passage of an instrumented fication of individuals performing cov- internal inspection device within 1 ered tasks on a pipeline facility.

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(b) For the purpose of this subpart, a dividual’s performance of a covered covered task is an activity, identified task contributed to an accident as de- by the operator, that: fined in Part 195; (1) Is performed on a pipeline facility; (e) Evaluate an individual if the oper- (2) Is an operations or maintenance ator has reason to believe that the in- task; dividual is no longer qualified to per- (3) Is performed as a requirement of form a covered task; this part; and (f) Communicate changes that affect (4) Affects the operation or integrity covered tasks to individuals per- of the pipeline. forming those covered tasks; (g) Identify those covered tasks and § 195.503 Definitions. the intervals at which evaluation of Abnormal operating condition means a the individual’s qualifications is need- condition identified by the operator ed; that may indicate a malfunction of a (h) After December 16, 2004, provide component or deviation from normal training, as appropriate, to ensure that operations that may: individuals performing covered tasks (a) Indicate a condition exceeding de- have the necessary knowledge and sign limits; or skills to perform the tasks in a manner (b) Result in a hazard(s) to persons, that ensures the safe operation of pipe- property, or the environment. line facilities; and Evaluation means a process, estab- (i) After December 16, 2004, notify the lished and documented by the operator, Administrator or a state agency par- to determine an individual’s ability to ticipating under 49 U.S.C. Chapter 601 perform a covered task by any of the if the operator significantly modifies following: the program after the administrator or (a) Written examination; state agency has verified that it com- (b) Oral examination; plies with this section. Notifications to (c) Work performance history review; PHMSA may be submitted by elec- (d) Observation during: tronic mail to (1) performance on the job, [email protected], (2) on the job training, or or by mail to ATTN: Information Re- (3) simulations; sources Manager DOT/PHMSA/OPS, (e) Other forms of assessment. East Building, 2nd Floor, E22–321, New Qualified means that an individual Jersey Avenue SE., Washington, DC has been evaluated and can: 20590. (a) Perform assigned covered tasks and [Amdt. 195–67, 64 FR 46866, Aug. 27, 1999, as amended by Amdt. 195–84, 70 FR 10336, Mar. 3, (b) Recognize and react to abnormal 2005; Amdt. 195–100, 80 FR 12780, Mar. 11, 2015] operating conditions. [Amdt. 195–67, 64 FR 46866, Aug. 27, 1999, as § 195.507 Recordkeeping. amended by Amdt. 195–72, 66 FR 43524, Aug. Each operator shall maintain records 20, 2001] that demonstrate compliance with this subpart. § 195.505 Qualification program. (a) Qualification records shall in- Each operator shall have and follow a clude: written qualification program. The (1) Identification of qualified indi- program shall include provisions to: vidual(s); (a) Identify covered tasks; (2) Identification of the covered tasks (b) Ensure through evaluation that the individual is qualified to perform; individuals performing covered tasks (3) Date(s) of current qualification; are qualified; and (c) Allow individuals that are not (4) Qualification method(s). qualified pursuant to this subpart to (b) Records supporting an individ- perform a covered task if directed and ual’s current qualification shall be observed by an individual that is quali- maintained while the individual is per- fied; forming the covered task. Records of (d) Evaluate an individual if the oper- prior qualification and records of indi- ator has reason to believe that the in- viduals no longer performing covered

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tasks shall be retained for a period of tion of risk factor data, indirect exam- five years. ination or analysis to identify areas of suspected corrosion, direct examina- § 195.509 General. tion of the pipeline in these areas, and (a) Operators must have a written post assessment evaluation. qualification program by April 27, 2001. Electrical survey means a series of The program must be available for re- closely spaced pipe-to-soil readings view by the Administrator or by a over a pipeline that are subsequently state agency participating under 49 analyzed to identify locations where a U.S.C. Chapter 601 if the program is corrosive current is leaving the pipe- under the authority of that state agen- line. cy. External corrosion direct assessment (b) Operators must complete the (ECDA) means a four-step process that qualification of individuals performing combines pre-assessment, indirect in- covered tasks by October 28, 2002. spection, direct examination, and post- (c) Work performance history review may be used as a sole evaluation meth- assessment to evaluate the threat of od for individuals who were performing external corrosion to the integrity of a a covered task prior to October 26, 1999. pipeline. (d) After October 28, 2002, work per- Pipeline environment includes soil re- formance history may not be used as a sistivity (high or low), soil moisture sole evaluation method. (wet or dry), soil contaminants that (e) After December 16, 2004, observa- may promote corrosive activity, and tion of on-the-job performance may not other known conditions that could af- be used as the sole method of evalua- fect the probability of active corrosion. tion. You means operator. [Amdt. 195–67, 64 FR 46866, Aug. 27, 1999, as [Amdt. 195–73, 66 FR 67004, Dec. 27, 2001, as amended by Amdt. 195–72, 66 FR 43524, Aug. amended by Amdt. 195–85, 70 FR 61576, Oct. 20, 2001; Amdt. 195–84, 70 FR 10336, Mar. 3, 25, 2005] 2005] § 195.555 What are the qualifications Subpart H—Corrosion Control for supervisors? You must require and verify that su- SOURCE: Amdt. 195–73, 66 FR 67004, Dec. 27, pervisors maintain a thorough knowl- 2001, unless otherwise noted. edge of that portion of the corrosion control procedures established under § 195.551 What do the regulations in this subpart cover? § 195.402(c)(3) for which they are respon- sible for insuring compliance. This subpart prescribes minimum re- quirements for protecting steel pipe- § 195.557 Which pipelines must have lines against corrosion. coating for external corrosion con- trol? § 195.553 What special definitions apply to this subpart? Except bottoms of aboveground breakout tanks, each buried or sub- As used in this subpart— merged pipeline must have an external Active corrosion means continuing coating for external corrosion control corrosion which, unless controlled, if the pipeline is— could result in a condition that is det- rimental to public safety or the envi- (a) Constructed, relocated, replaced, ronment. or otherwise changed after the applica- Buried means covered or in contact ble date in § 195.401(c), not including with soil. the movement of pipe covered by Direct assessment means an integrity § 195.424; or assessment method that utilizes a (b) Converted under § 195.5 and— process to evaluate certain threats (1) Has an external coating that sub- (i.e., external corrosion, internal corro- stantially meets § 195.559 before the sion and stress corrosion cracking) to a pipeline is placed in service; or pipeline segment’s integrity. The proc- (2) Is a segment that is relocated, re- ess includes the gathering and integra- placed, or substantially altered.

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§ 195.559 What coating material may I does not apply to breakout tanks and use for external corrosion control? does not apply to buried piping in Coating material for external corro- breakout tank areas and pumping sta- sion control under § 195.557 must— tions until December 29, 2003. (a) Be designed to mitigate corrosion (d) Bare pipelines, breakout tank of the buried or submerged pipeline; areas, and buried pumping station pip- (b) Have sufficient adhesion to the ing must have cathodic protection in metal surface to prevent under film places where regulations in effect be- migration of moisture; fore January 28, 2002 required cathodic protection as a result of electrical in- (c) Be sufficiently ductile to resist spections. See previous editions of this cracking; part in 49 CFR, parts 186 to 199. (d) Have enough strength to resist (e) Unprotected pipe must have ca- damage due to handling and soil stress; thodic protection if required by (e) Support any supplemental ca- § 195.573(b). thodic protection; and (f) If the coating is an insulating § 195.565 How do I install cathodic type, have low moisture absorption and protection on breakout tanks? provide high electrical resistance. After October 2, 2000, when you in- § 195.561 When must I inspect pipe stall cathodic protection under coating used for external corrosion § 195.563(a) to protect the bottom of an control? aboveground breakout tank of more than 500 barrels 79.49m3 capacity built (a) You must inspect all external pipe to API Spec 12F (incorporated by ref- coating required by § 195.557 just prior erence, § 195.3), API Std 620 (incor- to lowering the pipe into the ditch or see porated by reference, § 195.3), API submerging the pipe. see Std 650 (incorporated by reference, (b) You must repair any coating dam- see § 195.3), or API Std 650’s predecessor, age discovered. Standard 12C, you must install the sys- § 195.563 Which pipelines must have tem in accordance with ANSI/API RP cathodic protection? 651 (incorporated by reference, see § 195.3). However, you don’t need to (a) Each buried or submerged pipe- comply with ANSI/API RP 651 when in- line that is constructed, relocated, re- stalling any tank for which you note in placed, or otherwise changed after the the corrosion control procedures estab- applicable date in § 195.401(c) must have lished under § 195.402(c)(3) why com- cathodic protection. The cathodic pro- plying with all or certain provisions of tection must be in operation not later ANSI/API RP 651 is not necessary for than 1 year after the pipeline is con- the safety of the tank. structed, relocated, replaced, or other- wise changed, as applicable. [Amdt. 195–99, 80 FR 188, Jan. 5, 2015] (b) Each buried or submerged pipe- line converted under § 195.5 must have § 195.567 Which pipelines must have cathodic protection if the pipeline— test leads and what must I do to in- (1) Has cathodic protection that sub- stall and maintain the leads? stantially meets § 195.571 before the (a) General. Except for offshore pipe- pipeline is placed in service; or lines, each buried or submerged pipe- (2) Is a segment that is relocated, re- line or segment of pipeline under ca- placed, or substantially altered. thodic protection required by this sub- (c) All other buried or submerged part must have electrical test leads for pipelines that have an effective exter- external corrosion control. However, nal coating must have cathodic protec- this requirement does not apply until tion. 1 Except as provided by paragraph December 27, 2004 to pipelines or pipe- (d) of this section, this requirement line segments on which test leads were not required by regulations in effect 1 A pipeline does not have an effective ex- before January 28, 2002. ternal coating material if the current re- (b) Installation. You must install test quired to cathodically protect the pipeline is leads as follows: substantially the same as if the pipeline (1) Locate the leads at intervals fre- were bare. quent enough to obtain electrical

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measurements indicating the adequacy thodic protection required by this sub- of cathodic protection. part complies with § 195.571: (2) Provide enough looping or slack (1) Conduct tests on the protected so backfilling will not unduly stress or pipeline at least once each calendar break the lead and the lead will other- year, but with intervals not exceeding wise remain mechanically secure and 15 months. However, if tests at those electrically conductive. intervals are impractical for separately (3) Prevent lead attachments from protected short sections of bare or inef- causing stress concentrations on pipe. fectively coated pipelines, testing may (4) For leads installed in conduits, be done at least once every 3 calendar suitably insulate the lead from the years, but with intervals not exceeding conduit. 39 months. (5) At the connection to the pipeline, (2) Identify not more than 2 years coat each bared test lead wire and after cathodic protection is installed, bared metallic area with an electrical the circumstances in which a close-in- insulating material compatible with terval survey or comparable tech- the pipe coating and the insulation on nology is practicable and necessary to the wire. accomplish the objectives of paragraph (c) Maintenance. You must maintain 10.1.1.3 of NACE SP 0169 (incorporated the test lead wires in a condition that by reference, see § 195.3). enables you to obtain electrical meas- (b) Unprotected pipe. You must re- urements to determine whether ca- evaluate your unprotected buried or thodic protection complies with submerged pipe and cathodically pro- § 195.571. tect the pipe in areas in which active corrosion is found, as follows: § 195.569 Do I have to examine ex- posed portions of buried pipelines? (1) Determine the areas of active cor- rosion by electrical survey, or where an Whenever you have knowledge that electrical survey is impractical, by any portion of a buried pipeline is ex- other means that include review and posed, you must examine the exposed analysis of leak repair and inspection portion for evidence of external corro- records, corrosion monitoring records, sion if the pipe is bare, or if the coating exposed pipe inspection records, and is deteriorated. If you find external the pipeline environment. corrosion requiring corrective action (2) For the period in the first column, under § 195.585, you must investigate the second column prescribes the fre- circumferentially and longitudinally quency of evaluation. beyond the exposed portion (by visual examination, indirect method, or both) Period Evaluation frequency to determine whether additional corro- sion requiring remedial action exists in Before December 29, 2003 ... At least once every 5 cal- endar years, but with inter- the vicinity of the exposed portion. vals not exceeding 63 months. § 195.571 What criteria must I use to Beginning December 29, At least once every 3 cal- determine the adequacy of cathodic 2003. endar years, but with inter- protection? vals not exceeding 39 months. Cathodic protection required by this subpart must comply with one or more (c) Rectifiers and other devices. You of the applicable criteria and other must electrically check for proper per- considerations for cathodic protection formance each device in the first col- contained paragraphs 6.2.2, 6.2.3, 6.2.4, umn at the frequency stated in the sec- 6.2.5 and 6.3 in NACE SP 0169 (incor- ond column. porated by reference, see § 195.3). Device Check frequency [Amdt. 195–100, 80 FR 12781, Mar. 11, 2015] Rectifier ...... At least six times each cal- § 195.573 What must I do to monitor endar year, but with inter- external corrosion control? vals not exceeding 21⁄2 months. (a) Protected pipelines. You must do Reverse current switch. the following to determine whether ca- Diode.

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Device Check frequency (e) If a pipeline is in close proximity to electrical transmission tower foot- Interference bond whose fail- ure would jeopardize struc- ings, ground cables, or counterpoise, or tural protection. in other areas where it is reasonable to foresee fault currents or an unusual Other interference bond ...... At least once each calendar risk of lightning, you must protect the year, but with intervals not exceeding 15 months. pipeline against damage from fault currents or lightning and take protec- (d) Breakout tanks. You must inspect tive measures at insulating devices. each cathodic protection system used to control corrosion on the bottom of § 195.577 What must I do to alleviate an aboveground breakout tank to en- interference currents? sure that operation and maintenance of (a) For pipelines exposed to stray the system are in accordance with API currents, you must have a program to RP 651 (incorporated by reference, see identify, test for, and minimize the § 195.3). However, this inspection is not detrimental effects of such currents. required if you note in the corrosion (b) You must design and install each control procedures established under impressed current or galvanic anode § 195.402(c)(3) why complying with all or system to minimize any adverse effects certain operation and maintenance on existing adjacent metallic struc- provisions of API RP 651 is not nec- tures. essary for the safety of the tank. (e) Corrective action. You must correct § 195.579 What must I do to mitigate any identified deficiency in corrosion internal corrosion? control as required by § 195.401(b). How- (a) General. If you transport any haz- ever, if the deficiency involves a pipe- ardous liquid or carbon dioxide that line in an integrity management pro- would corrode the pipeline, you must gram under § 195.452, you must correct investigate the corrosive effect of the the deficiency as required by hazardous liquid or carbon dioxide on § 195.452(h). the pipeline and take adequate steps to mitigate internal corrosion. [Amdt. 195–73, 66 FR 67004, Dec. 27, 2001; 67 FR (b) Inhibitors. If you use corrosion in- 70118, Nov. 20, 2002, as amended by Amdt. 195– 86, 71 FR 33411, June 9, 2006; Amdt. 195–94, 75 hibitors to mitigate internal corrosion, FR 48607, Aug. 11, 2010; Amdt. 195–99, 80 FR you must— 188, Jan. 5, 2015] (1) Use inhibitors in sufficient quan- tity to protect the entire part of the § 195.575 Which facilities must I elec- pipeline system that the inhibitors are trically isolate and what inspec- designed to protect; tions, tests, and safeguards are re- (2) Use coupons or other monitoring quired? equipment to determine the effective- (a) You must electrically isolate each ness of the inhibitors in mitigating in- buried or submerged pipeline from ternal corrosion; and other metallic structures, unless you (3) Examine the coupons or other electrically interconnect and cathodi- monitoring equipment at least twice cally protect the pipeline and the other each calendar year, but with intervals structures as a single unit. not exceeding 71⁄2 months. (b) You must install one or more in- (c) Removing pipe. Whenever you re- sulating devices where electrical isola- move pipe from a pipeline, you must tion of a portion of a pipeline is nec- inspect the internal surface of the pipe essary to facilitate the application of for evidence of corrosion. If you find in- corrosion control. ternal corrosion requiring corrective (c) You must inspect and electrically action under § 195.585, you must inves- test each electrical isolation to assure tigate circumferentially and longitu- the isolation is adequate. dinally beyond the removed pipe (by (d) If you install an insulating device visual examination, indirect method, in an area where a combustible atmos- or both) to determine whether addi- phere is reasonable to foresee, you tional corrosion requiring remedial ac- must take precautions to prevent arc- tion exists in the vicinity of the re- ing. moved pipe.

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(d) Breakout tanks. After October 2, If the pipeline is Then the frequency of in- 2000, when you install a tank bottom located: spection is: lining in an aboveground breakout Onshore ...... At least once every 3 cal- tank built to API Spec 12F (incor- endar years, but with inter- vals not exceeding 39 porated by reference, see § 195.3), API months. Std 620 (incorporated by reference, see Offshore ...... At least once each calendar § 195.3), API Std 650 (incorporated by year, but with intervals not reference, see § 195.3), or API Std 650’s exceeding 15 months. predecessor, Standard 12C, you must (b) During inspections you must give install the lining in accordance with particular attention to pipe at soil-to- API RP 652 (incorporated by reference, air interfaces, under thermal insula- see § 195.3). However, you don’t need to tion, under disbonded coatings, at pipe comply with API RP 652 when install- supports, in splash zones, at deck pene- ing any tank for which you note in the trations, and in spans over water. corrosion control procedures estab- (c) If you find atmospheric corrosion lished under § 195.402(c)(3) why compli- during an inspection, you must provide ance with all or certain provisions of protection against the corrosion as re- API RP 652 is not necessary for the quired by § 195.581. safety of the tank. § 195.585 What must I do to correct [Amdt. 195–73, 66 FR 67004, Dec. 27, 2001, as corroded pipe? amended by Amdt. 195–99, 80 FR 188, Jan. 5, (a) General corrosion. If you find pipe 2015] so generally corroded that the remain- ing wall thickness is less than that re- § 195.581 Which pipelines must I pro- quired for the maximum operating tect against atmospheric corrosion pressure of the pipeline, you must re- and what coating material may I place the pipe. However, you need not use? replace the pipe if you— (a) You must clean and coat each (1) Reduce the maximum operating pipeline or portion of pipeline that is pressure commensurate with the exposed to the atmosphere, except strength of the pipe needed for service- pipelines under paragraph (c) of this ability based on actual remaining wall section. thickness; or (b) Coating material must be suitable (2) Repair the pipe by a method that for the prevention of atmospheric cor- reliable engineering tests and analyses rosion. show can permanently restore the serv- (c) Except portions of pipelines in off- iceability of the pipe. (b) Localized corrosion pitting. If you shore splash zones or soil-to-air inter- find pipe that has localized corrosion faces, you need not protect against at- pitting to a degree that leakage might mospheric corrosion any pipeline for result, you must replace or repair the which you demonstrate by test, inves- pipe, unless you reduce the maximum tigation, or experience appropriate to operating pressure commensurate with the environment of the pipeline that the strength of the pipe based on ac- corrosion will— tual remaining wall thickness in the (1) Only be a light surface oxide; or pits. (2) Not affect the safe operation of the pipeline before the next scheduled § 195.587 What methods are available inspection. to determine the strength of cor- roded pipe? § 195.583 What must I do to monitor at- Under § 195.585, you may use the pro- mospheric corrosion control? cedure in ASME/ANSI B31G (incor- porated by reference, see § 195.3) or in (a) You must inspect each pipeline or PRCI PR–3–805 (R–STRENG) (incor- portion of pipeline that is exposed to porated by reference, see § 195.3) to de- the atmosphere for evidence of atmos- termine the strength of corroded pipe pheric corrosion, as follows: based on actual remaining wall thick- ness. These procedures apply to cor- roded regions that do not penetrate the

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pipe wall, subject to the limitations set ECDA for the first time on a pipeline out in the respective procedures. segment; (ii) Criteria for identifying and docu- [Amdt. 195–99, 80 FR 188, Jan. 5, 2015] menting those indications that must be § 195.588 What standards apply to di- considered for excavation and direct rect assessment? examination, including at least the fol- lowing: (a) If you use direct assessment on an (A) The known sensitivities of assess- onshore pipeline to evaluate the effects ment tools; of external corrosion or stress corro- sion cracking, you must follow the re- (B) The procedures for using each quirements of this section. This section tool; and does not apply to methods associated (C) The approach to be used for de- with direct assessment, such as close creasing the physical spacing of indi- interval surveys, voltage gradient sur- rect assessment tool readings when the veys, or examination of exposed pipe- presence of a defect is suspected; lines, when used separately from the (iii) For each indication identified direct assessment process. during the indirect examination, cri- (b) The requirements for performing teria for— external corrosion direct assessment (A) Defining the urgency of exca- are as follows: vation and direct examination of the (1) General. You must follow the re- indication; and quirements of NACE SP0502 (incor- (B) Defining the excavation urgency porated by reference, see § 195.3). Also, as immediate, scheduled, or monitored; you must develop and implement a Ex- and ternal Corrosion Direct Assessment (iv) Criteria for scheduling exca- (ECDA) plan that includes procedures vations of indications in each urgency addressing pre-assessment, indirect ex- level. amination, direct examination, and (4) Direct examination. In addition to post-assessment. the requirements in Section 5 of NACE (2) Pre-assessment. In addition to the SP0502 (incorporated by reference, see requirements in Section 3 of NACE § 195.3), the procedures for direct exam- SP0502 (incorporated by reference, see ination of indications from the indirect § 195.3), the ECDA plan procedures for examination must include— pre-assessment must include— (i) Provisions for applying more re- (i) Provisions for applying more re- strictive criteria when conducting strictive criteria when conducting ECDA for the first time on a pipeline ECDA for the first time on a pipeline segment; segment; (ii) Criteria for deciding what action (ii) The basis on which you select at should be taken if either: least two different, but complemen- (A) Corrosion defects are discovered tary, indirect assessment tools to as- that exceed allowable limits (Section sess each ECDA region; and 5.5.2.2 of NACE SP0502 (incorporated by (iii) If you utilize an indirect inspec- reference, see § 195.3) provides guidance tion method not described in Appendix for criteria); or A of NACE SP0502 (incorporated by ref- (B) Root cause analysis reveals con- erence, see § 195.3), you must dem- ditions for which ECDA is not suitable onstrate the applicability, validation (Section 5.6.2 of NACE SP0502 (incor- basis, equipment used, application pro- porated by reference, see § 195.3) pro- cedure, and utilization of data for the vides guidance for criteria); inspection method. (iii) Criteria and notification proce- (3) Indirect examination. In addition to dures for any changes in the ECDA the requirements in Section 4 of NACE plan, including changes that affect the SP0502 (incorporated by reference, see severity classification, the priority of § 195.3), the procedures for indirect ex- direct examination, and the time frame amination of the ECDA regions must for direct examination of indications; include— and (i) Provisions for applying more re- (iv) Criteria that describe how and on strictive criteria when conducting what basis you will reclassify and re-

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prioritize any of the provisions speci- teria in NACE SP0204–2008 indicate the fied in Section 5.9 of NACE SP0502 (in- potential for Stress Corrosion Cracking corporated by reference, see § 195.3). Direct Assessment. This data gathering (5) Post assessment and continuing process must be conducted in accord- evaluation. In addition to the require- ance with NACE SP0204–2008, Section ments in Section 6 of NACE SP 0502 5.3, and must include, at a minimum, (incorporated by reference, see § 195.3), all data listed in NACE SP0204–2008, the procedures for post assessment of Table 2. Further, an operator must the effectiveness of the ECDA process analyze the following factors as part of must include— this evaluation: (i) Measures for evaluating the long- (i) The effects of a carbonate-bicar- term effectiveness of ECDA in address- bonate environment, including the im- ing external corrosion in pipeline seg- plications of any factors that promote ments; and the production of a carbonate-bicar- (ii) Criteria for evaluating whether bonate environment such as soil tem- conditions discovered by direct exam- perature, moisture, factors that affect ination of indications in each ECDA re- the rate of carbon dioxide generation, gion indicate a need for reassessment and/or cathodic protection. of the pipeline segment at an interval (ii) The effects of cyclic loading con- less than that specified in Sections 6.2 ditions on the susceptibility and propa- and 6.3 of NACE SP0502 (see appendix D gation of SCC in both high-pH and of NACE SP0502) (incorporated by ref- near-neutral-pH environments. erence, see § 195.3). (iii) The effects of variations in ap- (c) If you use direct assessment on an plied cathodic protection such as over- onshore pipeline to evaluate the effects protection, cathodic protection loss for of stress corrosion cracking, you must extended periods, and high negative po- develop and follow a Stress Corrosion tentials. Cracking Direct Assessment plan that meets all requirements and rec- (iv) The effects of coatings that ommendations of NACE SP0204–2008 shield cathodic protection when (incorporated by reference, see § 195.3) disbonded from the pipe. and that implements all four steps of (v) Other factors that affect the the Stress Corrosion Cracking Direct mechanistic properties associated with Assessment process including pre-as- SCC including but not limited to oper- sessment, indirect inspection, detailed ating pressures, high tensile residual examination and post-assessment. As stresses, and the presence of sulfides. specified in NACE SP0204–2008, Section (2) Indirect inspection. In addition to 1.1.7, Stress Corrosion Cracking Direct the requirements and recommenda- Assessment is complementary with tions of NACE SP0204–2008, Section 4, other inspection methods such as in- the plan’s procedures for indirect in- line inspection or hydrostatic testing spection must include provisions for and is not necessarily an alternative or conducting at least two different, but replacement for these methods in all complementary, indirect assessment instances. In addition, the plan must electrical surveys, and the basis on the provide for— selections as the most appropriate for (1) Data gathering and integration. An the pipeline segment based on the data operator’s plan must provide for a sys- gathering and integration step. tematic process to collect and evaluate (3) Direct examination. In addition to data to identify whether the conditions the requirements and recommenda- for stress corrosion cracking are tions of NACE SP0204–2008, Section 5, present and to prioritize the segments the plan’s procedures for direct exam- for assessment in accordance with ination must provide for conducting a NACE SP0204–2008, Sections 3 and 4, minimum of four direct examinations and Table 1. This process must also in- within the SCC segment at locations clude gathering and evaluating data re- determined to be the most likely for lated to SCC at all sites an operator ex- SCC to occur. cavates during the conduct of its pipe- (4) Remediation and mitigation. If any line operations (both within and out- indication of SCC is discovered in a side covered segments) where the cri- segment, an operator must mitigate

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the threat in accordance with one of (iii) Conditions in the application (or the following applicable methods: loss) of cathodic protection that can (i) Non-significant SCC, as defined by create or exacerbate SCC; NACE SP0204–2008, may be mitigated (iv) Operating temperature and pres- by either hydrostatic testing in accord- sure conditions; ance with paragraph (b)(4)(ii) of this (v) Cyclic loading conditions; section, or by grinding out with (vi) Conditions that influence crack verification by Non-Destructive Exam- initiation and growth rates; ination (NDE) methods that the SCC (vii) The effects of interacting crack defect is removed and repairing the clusters; pipe. If grinding is used for repair, the (viii) The presence of sulfides; and remaining strength of the pipe at the (ix) Disbonded coatings that shield repair location must be determined CP from the pipe. using ASME/ANSI B31G or RSTRENG (incorporated by reference, see § 195.3) [Amdt. 195–85, 70 FR 61576, Oct. 25, 2005, as amended by Amdt. 195–94, 75 FR 48607, Aug. and must be sufficient to meet the de- 11, 2010; Amdt. 195–101, 82 FR 8000, Jan. 23, sign requirements of subpart C of this 2017] part. (ii) Significant SCC must be miti- § 195.589 What corrosion control infor- gated using a hydrostatic testing pro- mation do I have to maintain? gram with a minimum test pressure be- (a) You must maintain current tween 100% up to 110% of the specified records or maps to show the location minimum yield strength for a 30- of— minute spike test immediately fol- (1) Cathodically protected pipelines; lowed by a pressure test in accordance (2) Cathodic protection facilities, in- with subpart E of this part. The test cluding galvanic anodes, installed after pressure for the entire sequence must January 28, 2002; and be continuously maintained for at least (3) Neighboring structures bonded to 8 hours, in accordance with subpart E cathodic protection systems. of this part. Any test failures due to (b) Records or maps showing a stated SCC must be repaired by replacement number of anodes, installed in a stated of the pipe segment, and the segment manner or spacing, need not show spe- retested until the pipe passes the com- cific distances to each buried anode. plete test without leakage. Pipe seg- (c) You must maintain a record of ments that have SCC present, but that each analysis, check, demonstration, pass the pressure test, may be repaired examination, inspection, investigation, by grinding in accordance with para- review, survey, and test required by graph (c)(4)(i) of this section. this subpart in sufficient detail to dem- (5) Post assessment. In addition to the onstrate the adequacy of corrosion con- requirements and recommendations of trol measures or that corrosion requir- NACE SP0204–2008, sections 6.3, peri- ing control measures does not exist. odic reassessment, and 6.4, effective- You must retain these records for at ness of Stress Corrosion Cracking Di- least 5 years, except that records re- rect Assessment, the plan’s procedures lated to §§ 195.569, 195.573(a) and (b), and for post assessment must include devel- 195.579(b)(3) and (c) must be retained opment of a reassessment plan based for as long as the pipeline remains in on the susceptibility of the operator’s service. pipe to Stress Corrosion Cracking as well as on the behavior mechanism of § 195.591 In-Line inspection of pipe- identified cracking. Factors to be con- lines. sidered include, but are not limited to: When conducting in-line inspection (i) Evaluation of discovered crack of pipelines required by this part, each clusters during the direct examination operator must comply with the re- step in accordance with NACE SP0204– quirements and recommendations of 2008, sections 5.3.5.7, 5.4, and 5.5; API Std 1163, Inline Inspection Systems (ii) Conditions conducive to creation Qualification Standard; ANSI/ASNT ILI– of the carbonate-bicarbonate environ- PQ, Inline Inspection Personnel Quali- ment; fication and Certification; and NACE

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SP0102–2010, Inline Inspection of Pipe- eral Energy Regulatory Commission (FERC). lines (incorporated by reference, see Experience has proven this approach prac- § 195.3). An in-line inspection may also tical. Unlike the NGPSA however, the be conducted using tethered or remote HLPSA has no specific reference to FERC ju- control tools provided they generally risdiction, but instead defines interstate liq- uid pipeline facilities by the more commonly comply with those sections of NACE used means of specifying the end points of SP0102–2010 that are applicable. the transportation involved. For example, [Amdt. 195–101, 82 FR 8000, Jan. 23, 2017] the economic regulatory jurisdiction of FERC over the transportation of both gas and liquids by pipeline is defined in much the same way. In implementing the HLPSA DOT has sought a practicable means of distin- APPENDIX A TO PART 195—DELINEATION guishing between interstate and intrastate BETWEEN FEDERAL AND STATE JU- pipeline facilities that provide the requisite RISDICTION—STATEMENT OF AGENCY degree of certainty to Federal and State en- POLICY AND INTERPRETATION forcement personnel and to the regulated en- tities. DOT intends that this statement of In 1979, Congress enacted comprehensive agency policy and interpretation provide safety legislation governing the transpor- that certainty. tation of hazardous liquids by pipeline, the In 1981, DOT decided that the inventory of Hazardous Liquids Pipeline Safety Act of liquid pipeline facilities identified as subject 1979, 49 U.S.C. 2001 et seq. (HLPSA). The to the jurisdiction of FERC approximates HLPSA expanded the existing statutory au- the HLPSA category of ‘‘interstate pipeline thority for safety regulation, which was lim- facilities.’’ Administrative use of the FERC ited to transportation by common carriers in inventory has the added benefit of avoiding interstate and foreign commerce, to trans- the creation of a separate Federal scheme for portation through facilities used in or affect- determination of jurisdiction over the same ing interstate or foreign commerce. It also regulated entities. DOT recognizes that the added civil penalty, compliance order, and FERC inventory is only an approximation injunctive enforcement authorities to the and may not be totally satisfactory without existing criminal sanctions. Modeled largely some modification. The difficulties stem on the Natural Gas Pipeline Safety Act of from some significant differences in the eco- 1968, 49 U.S.C. 1671 et seq. (NGPSA), the HLPSA provides for a national hazardous nomic regulation of liquid and of natural gas liquid pipeline safety program with nation- pipelines. There is an affirmative assertion ally uniform minimal standards and with en- of jurisdiction by FERC over natural gas forcement administered through a Federal- pipelines through the issuance of certificates State partnership. The HLPSA leaves to ex- of public convenience and necessity prior to clusive Federal regulation and enforcement commencing operations. With liquid pipe- the ‘‘interstate pipeline facilities,’’ those lines, there is only a rebuttable presumption used for the pipeline transportation of haz- of jurisdiction created by the filing by pipe- ardous liquids in interstate or foreign com- line operators of tariffs (or concurrences) for merce. For the remainder of the pipeline fa- movement of liquids through existing facili- cilities, denominated ‘‘intrastate pipeline fa- ties. Although FERC does police the filings cilities,’’ the HLPSA provides that the same for such matters as compliance with the gen- Federal regulation and enforcement will eral duties of common carriers, the question apply unless a State certifies that it will as- of jurisdiction is normally only aired upon sume those responsibilities. A certified State complaint. While any person, including must adopt the same minimal standards but State or Federal agencies, can avail them- may adopt additional more stringent stand- selves of the FERC forum by use of the com- ards so long as they are compatible. There- plaint process, that process has only been fore, in States which participate in the haz- rarely used to review jurisdictional matters ardous liquid pipeline safety program (probably because of the infrequency of real through certification, it is necessary to dis- disputes on the issue). Where the issue has tinguish the interstate from the intrastate arisen, the reviewing body has noted the pipeline facilities. need to examine various criteria primarily of In deciding that an administratively prac- an economic nature. DOT believes that, in tical approach was necessary in distin- most cases, the formal FERC forum can bet- guishing between interstate and intrastate ter receive and evaluate the type of informa- liquid pipeline facilities and in determining tion that is needed to make decisions of this how best to accomplish this, DOT has logi- nature than can DOT. cally examined the approach used in the In delineating which liquid pipeline facili- NGPSA. The NGPSA defines the interstate ties are interstate pipeline facilities within gas pipeline facilities subject to exclusive the meaning of the HLPSA, DOT will gen- Federal jurisdiction as those subject to the erally rely on the FERC filings; that is, if economic regulatory jurisdiction of the Fed- there is a tariff or concurrence filed with

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FERC governing the transportation of haz- that lateral as determinative of interstate ardous liquids over a pipeline facility or if commerce. there has been an exemption from the obliga- Example 6. Same as in example 1 except tion to file tariffs obtained from FERC, then that the certified agency in State X has DOT will, as a general rule, consider the fa- brought an enforcement action (under the cility to be an interstate pipeline facility pipeline safety laws) against P because of its within the meaning of the HLPSA. The types operation of the line between ‘‘Point A’’ and of situations in which DOT will ignore the ‘‘Point B’’. P has successfully defended existence or non-existence of a filing with against the action on jurisdictional grounds. FERC will be limited to those cases in which DOT will assume jurisdiction if necessary to it appears obvious that a complaint filed avoid the anomaly of a pipeline subject to with FERC would be successful or in which neither State or Federal safety enforcement. blind reliance on a FERC filing would result DOT’s assertion of jurisdiction in such a case in a situation clearly not intended by the would be based on the gap in the state’s en- HLPSA such as a pipeline facility not being forcement authority rather than a DOT deci- subject to either State or Federal safety reg- sion that the pipeline is an interstate pipe- ulation. DOT anticipates that the situations line facility. in which there is any question about the va- Example 7. Pipeline Company P operates a lidity of the FERC filings as a ready ref- pipeline that originates on the Outer Conti- erence will be few and that the actual vari- nental Shelf. P does not file any tariff for ations from reliance on those filings will be that line with FERC. DOT will consider the rare. The following examples indicate the pipeline to be an interstate pipeline facility. types of facilities which DOT believes are Example 8. Pipeline Company P is con- interstate pipeline facilities subject to the structing a pipeline from ‘‘Point C’’ (in State HLPSA despite the lack of a filing with X) to ‘‘Point D’’ (in State Y). DOT will con- FERC and the types of facilities over which sider the pipeline to be an interstate pipeline DOT will generally defer to the jurisdiction facility. of a certifying state despite the existence of Example 9. Pipeline company P is con- a filing with FERC. structing a pipeline from ‘‘Point C’’ to Example 1. Pipeline company P operates a ‘‘Point E’’ (both in State X) but intends to pipeline from ‘‘Point A’’ located in State X file tariffs with FERC in the transportation to ‘‘Point B’’ (also in X). The physical facili- of hazardous liquid in interstate commerce. ties never cross a state line and do not con- Assuming there is some connection to an nect with any other pipeline which does interstate pipeline facility, DOT will con- cross a state line. Pipeline company P also sider this line to be an interstate pipeline fa- operates another pipeline between ‘‘Point C’’ cility. in State X and ‘‘Point D’’ in an adjoining Example 10. Pipeline Company P has oper- State Y. Pipeline company P files a tariff ated a pipeline subject to FERC economic with FERC for transportation from ‘‘Point regulation. Solely because of some statutory A’’ to ‘‘Point B’’ as well as for transpor- economic deregulation, that pipeline is no tation from ‘‘Point C’’ to ‘‘Point D.’’ DOT longer regulated by FERC. DOT will con- will ignore filing for the line from ‘‘Point A’’ tinue to consider that pipeline to be an to ‘‘Point B’’ and consider the line to be interstate pipeline facility. intrastate. Example 2. Same as in example 1 except As seen from the examples, the types of that P does not file any tariffs with FERC. situations in which DOT will not defer to the DOT will assume jurisdiction of the line be- FERC regulatory scheme are generally clear- tween ‘‘Point C’’ and ‘‘Point D.’’ cut cases. For the remainder of the situa- Example 3. Same as in example 1 except tions where variation from the FERC scheme that P files its tariff for the line between would require DOT to replicate the forum al- ‘‘Point C’’ and ‘‘Point D’’ not only with ready provided by FERC and to consider eco- FERC but also with State X. DOT will rely nomic factors better left to that agency, on the FERC filing as indication of inter- DOT will decline to vary its reliance on the state commerce. FERC filings unless, of course, not doing so Example 4. Same as in example 1 except would result in situations clearly not in- that the pipeline from ‘‘Point A’’ to ‘‘Point tended by the HLPSA. B’’ (in State X) connects with a pipeline op- [Amdt. 195–33, 50 FR 15899, Apr. 23, 1985] erated by another company transports liquid between ‘‘Point B’’ (in State X) and ‘‘Point APPENDIX B TO PART 195—RISK-BASED D’’ (in State Y). DOT will rely on the FERC ALTERNATIVE TO PRESSURE TESTING filing as indication of interstate commerce. Example 5. Same as in example 1 except OLDER HAZARDOUS LIQUID AND CAR- that the line between ‘‘Point C’’ and ‘‘Point BON DIOXIDE PIPELINES D’’ has a lateral line connected to it. The RISK-BASED ALTERNATIVE lateral is located entirely with State X. DOT will rely on the existence or non-existence of This Appendix provides guidance on how a a FERC filing covering transportation over risk-based alternative to pressure testing

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older hazardous liquid and carbon dioxide higher risk associated with the suscepti- pipelines rule allowed by § 195.303 will work. bility of this pipe to longitudinal seam fail- This risk-based alternative establishes test ures. priorities for older pipelines, not previously In all cases, operators shall annually, at pressure tested, based on the inherent risk of intervals not to exceed 15 months, review a given pipeline segment. The first step is to their facilities to reassess the classification determine the classification based on the and shall take appropriate action within two type of pipe or on the pipeline segment’s years or operate the pipeline system at a proximity to populated or environmentally lower pressure. Pipeline failures, changes in sensitive area. Secondly, the classifications the characteristics of the pipeline route, or must be adjusted based on the pipeline fail- ure history, product transported, and the re- changes in service should all trigger a reas- lease volume potential. sessment of the originally classification. Tables 2–6 give definitions of risk classi- Table 1 explains different levels of test re- fication A, B, and C facilities. For the pur- quirements depending on the inherent risk of poses of this rule, pipeline segments con- a given pipeline segment. The overall risk taining high risk electric resistance-welded classification is determined based on the pipe (ERW pipe) and lapwelded pipe manufac- type of pipe involved, the facility’s location, tured prior to 1970 and considered a risk clas- the product transported, the relative volume sification C or B facility shall be treated as of flow and pipeline failure history as deter- the top priority for testing because of the mined from Tables 2–6.

TABLE 1. TEST REQUIREMENTS—MAINLINE SEGMENTS OUTSIDE OF TERMINALS, STATIONS, AND TANK FARMS

Pipeline segment Risk classification Test deadline 1 Test medium

Pre-1970 Pipeline Segments susceptible to longitu- C or B 12/7/2000 3 ...... Water only. dinal seam failures 2. A 12/7/2002 3 ...... Water only. All Other Pipeline Segments ...... C 12/7/2002 4 ...... Water only. B 12/7/2004 4 ...... Water/Liq. 5 A Additional pressure testing not required. 1 If operational experience indicates a history of past failures for a particular pipeline segment, failure causes (time-dependent defects due to corrosion, construction, manufacture, or transmission problems, etc.) shall be reviewed in determining risk classi- fication (See Table 6) and the timing of the pressure test should be accelerated. 2 All pre-1970 ERW pipeline segments may not require testing. In determining which ERW pipeline segments should be in- cluded in this category, an operator must consider the seam-related leak history of the pipe and pipe manufacturing information as available, which may include the pipe steel’s mechanical properties, including fracture toughness; the manufacturing process and controls related to seam properties, including whether the ERW process was high-frequency or low-frequency, whether the weld seam was heat treated, whether the seam was inspected, the test pressure and duration during mill hydrotest; the quality control of the steel-making process; and other factors pertinent to seam properties and quality. 3 For those pipeline operators with extensive mileage of pre-1970 ERW pipe, any waiver requests for timing relief should be supported by an assessment of hazards in accordance with location, product, volume, and probability of failure considerations consistent with Tables 3, 4, 5, and 6. 4 A magnetic flux leakage or ultrasonic internal inspection survey may be utilized as an alternative to pressure testing where leak history and operating experience do not indicate leaks caused by longitudinal cracks or seam failures. 5 Pressure tests utilizing a hydrocarbon liquid may be conducted, but only with a liquid which does not vaporize rapidly.

Using LOCATION, PRODUCT, VOLUME, factor which determines overall risk, with and FAILURE HISTORY ‘‘Indicators’’ from the PRODUCT, VOLUME, and PROB- Tables 3, 4, 5, and 6 respectively, the overall ABILITY OF FAILURE Indicators used to risk classification of a given pipeline or pipe- adjust to a higher or lower overall risk clas- line segment can be established from Table sification per the following table. 2. The LOCATION Indicator is the primary

TABLE 2—RISK CLASSIFICATION

Risk classification Hazard location indicator Product/volume indicator Probability of failure indicator

A ...... L or M ...... L/L ...... L. B ...... Not A or C Risk Classification C ...... H ...... Any ...... Any. H = High M = Moderate L = Low. NOTE: For Location, Product, Volume, and Probability of Failure Indicators, see Tables 3, 4, 5, and 6.

Table 3 is used to establish the LOCATION ciated with a pipeline facility’s location, a Indicator used in Table 2. Based on the popu- LOCATION Indicator of H, M or L is se- lation and environment characteristics asso- lected.

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TABLE 3—LOCATION INDICATORS—PIPELINE SEGMENTS

Indicator Population 1 Environment 2

H ...... Non-rural areas ...... Environmentally sensitive 2 areas. M ...... L ...... Rural areas ...... Not environmentally sensitive 2 areas. 1 The effects of potential vapor migration should be considered for pipeline segments transporting highly volatile or toxic prod- ucts. 2 We expect operators to use their best judgment in applying this factor.

Tables 4, 5 and 6 are used to establish the product transported. The VOLUME Indicator PRODUCT, VOLUME, and PROBABILITY is selected from Table 5 as H, M, or L based OF FAILURE Indicators respectively, in on the nominal diameter of the pipeline. The Table 2. The PRODUCT Indicator is selected Probability of Failure Indicator is selected from Table 4 as H, M, or L based on the acute from Table 6. and chronic hazards associated with the

TABLE 4—PRODUCT INDICATORS

Indicator Considerations Product examples

H ...... (Highly volatile and flammable) ...... (Propane, butane, Natural Gas Liquid (NGL), ammonia) Highly toxic ...... (Benzene, high Hydrogen Sulfide con- tent crude oils). M ...... Flammable—flashpoint <100F...... (Gasoline, JP4, low flashpoint crude oils). L ...... Non-flammable—flashpoint 100 + F ...... (Diesel, fuel oil, kerosene, JP5, most crude oils). Highly volatile and non-flammable/non- Carbon Dioxide. toxic.

Considerations: The degree of acute and 1 Pipeline segments with greater than three product spills in chronic toxicity to humans, wildlife, and the last 10 years should be reviewed for failure causes as de- scribed in subnote 2. The pipeline operator should make an aquatic life; reactivity; and, volatility, flam- appropriate investigation and reach a decision based on mability, and water solubility determine the sound engineering judgment, and be able to demonstrate the Product Indicator. Comprehensive Environ- basis of the decision. 2 Time-Dependent Defects are defects that result in spills mental Response, Compensation and Liabil- due to corrosion, gouges, or problems developed during man- ity Act Reportable Quantity values can be ufacture, construction or operation, etc. used as an indication of chronic toxicity. Na- tional Fire Protection Association health [Amdt. 195–65, 63 FR 59480, Nov. 4, 1998; 64 FR factors can be used for rating acute hazards. 6815, Feb. 11, 1999]

TABLE 5—VOLUME INDICATORS APPENDIX C TO PART 195—GUIDANCE FOR IMPLEMENTATION OF AN INTEGRITY Indicator Line size MANAGEMENT PROGRAM

H ...... ≥18″. This Appendix gives guidance to help an M ...... 10″–16″ nominal diameters. operator implement the requirements of the L ...... ≤8″ nominal diameter. integrity management program rule in H = High M = Moderate L = Low. §§ 195.450 and 195.452. Guidance is provided on: (1) Information an operator may use to Table 6 is used to establish the PROB- identify a high consequence area and factors ABILITY OF FAILURE Indicator used in an operator can use to consider the potential Table 2. The ‘‘Probability of Failure’’ Indi- impacts of a release on an area; cator is selected from Table 6 as H or L. (2) Risk factors an operator can use to de- termine an integrity assessment schedule; TABLE 6—PROBABILITY OF FAILURE INDICATORS (3) Safety risk indicator tables for leak [in each haz. location] history, volume or line size, age of pipeline, and product transported, an operator may Indicator Failure history (time-dependent defects) 2 use to determine if a pipeline segment falls into a high, medium or low risk category; H 1 ...... >Three spills in last 10 years. (4) Types of internal inspection tools an L ...... ≤Three spills in last 10 years. operator could use to find pipeline anoma- H = High L = Low. lies;

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(5) Measures an operator could use to area. An operator can get this information measure an integrity management program’s from topographical maps such as U.S. Geo- performance; and logical Survey quadrangle maps. (6) Types of records an operator will have (2) Drainage systems such as small streams to maintain. and other smaller waterways that could (7) Types of conditions that an integrity serve as a conduit to a high consequence assessment may identify that an operator area. should include in its required schedule for (3) Crossing of farm tile fields. An operator evaluation and remediation. should consider the possibility of a spillage I. Identifying a high consequence area and in the field following the drain tile into a factors for considering a pipeline segment’s waterway. potential impact on a high consequence area. (4) Crossing of roadways with ditches along A. The rule defines a High Consequence the side. The ditches could carry a spillage Area as a high population area, an other pop- to a waterway. ulated area, an unusually sensitive area, or a (5) The nature and characteristics of the commercially navigable waterway. The Of- product the pipeline is transporting (refined fice of Pipeline Safety (OPS) will map these products, crude oils, highly volatile liquids, areas on the National Pipeline Mapping Sys- etc.) Highly volatile liquids becomes gaseous tem (NPMS). An operator, member of the when exposed to the atmosphere. A spillage public or other government agency may view could create a vapor cloud that could settle and download the data from the NPMS home into the lower elevation of the ground pro- page http://www.npms.phmsa.gov/. OPS will file. maintain the NPMS and update it periodi- (6) Physical support of the pipeline seg- cally. However, it is an operator’s responsi- ment such as by a cable suspension bridge. bility to ensure that it has identified all high An operator should look for stress indicators consequence areas that could be affected by on the pipeline (strained supports, inad- a pipeline segment. An operator is also re- equate support at towers), atmospheric cor- sponsible for periodically evaluating its pipe- rosion, vandalism, and other obvious signs of line segments to look for population or envi- improper maintenance. ronmental changes that may have occurred around the pipeline and to keep its program (7) Operating conditions of the pipeline current with this information. (Refer to (pressure, flow rate, etc.). Exposure of the § 195.452(d)(3).) pipeline to an operating pressure exceeding (1) Digital Data on populated areas avail- the established maximum operating pres- able on U.S. Census Bureau maps. sure. (2) Geographic Database on the commer- (8) The hydraulic gradient of the pipeline. cial navigable waterways available on http:// (9) The diameter of the pipeline, the poten- www.bts.gov/gis/ntatlas/networks.html. tial release volume, and the distance be- (3) The Bureau of Transportation Statis- tween the isolation points. tics database that includes commercially (10) Potential physical pathways between navigable waterways and non-commercially the pipeline and the high consequence area. navigable waterways. The database can be (11) Response capability (time to respond, downloaded from the BTS website at http:// nature of response). www.bts.gov/gis/ntatlas/networks.html. (12) Potential natural forces inherent in B. The rule requires an operator to include the area (flood zones, earthquakes, subsid- a process in its program for identifying ence areas, etc.) which pipeline segments could affect a high II. Risk factors for establishing frequency consequence area and to take measures to of assessment. prevent and mitigate the consequences of a A. By assigning weights or values to the pipeline failure that could affect a high con- risk factors, and using the risk indicator ta- sequence area. (See §§ 195.452 (f) and (i).) bles, an operator can determine the priority Thus, an operator will need to consider how for assessing pipeline segments, beginning each pipeline segment could affect a high with those segments that are of highest risk, consequence area. The primary source for that have not previously been assessed. This the listed risk factors is a US DOT study on list provides some guidance on some of the instrumented Internal Inspection devices risk factors to consider (see § 195.452(e)). An (November 1992). Other sources include the operator should also develop factors specific National Transportation Safety Board, the to each pipeline segment it is assessing, in- Environmental Protection Agency and the cluding: Technical Hazardous Liquid Pipeline Safety (1) Populated areas, unusually sensitive en- Standards Committee. The following list vironmental areas, National Fish Hatcheries, provides guidance to an operator on both the commercially navigable waters, areas where mandatory and additional factors: people congregate. (1) Terrain surrounding the pipeline. An (2) Results from previous testing/inspec- operator should consider the contour of the tion. (See § 195.452(h).) land profile and if it could allow the liquid (3) Leak History. (See leak history risk from a release to enter a high consequence table.)

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(4) Known corrosion or condition of pipe- 31⁄2 years and the remaining segments within line. (See § 195.452(g).) the seven-year period. For the continuing in- (5) Cathodic protection history. tegrity assessments, we would plan to assess (6) Type and quality of pipe coating the C segments within the first two (2) years (disbonded coating results in corrosion). of the schedule, the segments classified as (7) Age of pipe (older pipe shows more cor- moderate risk no later than year three or rosion—may be uncoated or have an ineffec- four and the remaining lowest risk segments tive coating) and type of pipe seam. (See Age no later than year five (5). of Pipe risk table.) ii. For our hypothetical pipeline segment, (8) Product transported (highly volatile, we have chosen the following risk factors highly flammable and toxic liquids present a and obtained risk factor values from the ap- greater threat for both people and the envi- propriate table. The values assigned to the ronment) (see Product transported risk risk factors are for illustration only. table.) (9) Pipe wall thickness (thicker walls give Age of pipeline: assume 30 years old (refer to a better safety margin) ‘‘Age of Pipeline’’ risk table)— (10) Size of pipe (higher volume release if Risk Value = 5 the pipe ruptures). Pressure tested: tested once during construc- (11) Location related to potential ground tion— movement (e.g., seismic faults, rock quar- Risk Value = 5 ries, and coal mines); climatic (permafrost Coated: (yes/no)—yes causes settlement—Alaska); geologic (land- Coating Condition: Recent excavation of sus- slides or subsidence). pected areas showed holidays in coating (12) Security of throughput (effects on cus- (potential corrosion risk)— tomers if there is failure requiring shut- Risk Value = 5 down). Cathodically Protected: (yes/no)—yes—Risk (13) Time since the last internal inspection/ Value = 1 pressure testing. Date cathodic protection installed: five years (14) With respect to previously discovered after pipeline was constructed (Cathodic defects/anomalies, the type, growth rate, and protection installed within one year of the size. pipeline’s construction is generally consid- (15) Operating stress levels in the pipeline. ered low risk.)—Risk Value = 3 (16) Location of the pipeline segment as it relates to the ability of the operator to de- Close interval survey: (yes/no)—no—Risk tect and respond to a leak. (e.g., pipelines Value = 5 deep underground, or in locations that make Internal Inspection tool used: (yes/no)—yes. leak detection difficult without specific sec- Date of pig run? In last five years—Risk tional monitoring and/or significantly im- Value = 1 pede access for spill response or any other Anomalies found: (yes/no)—yes, but do not purpose). pose an immediate safety risk or environ- (17) Physical support of the segment such mental hazard—Risk Value = 3 as by a cable suspension bridge. Leak History: yes, one spill in last 10 years. (18) Non-standard or other than recognized (refer to ‘‘Leak History’’ risk table)—Risk industry practice on pipeline installation Value = 2 (e.g., horizontal directional drilling). Product transported: Diesel fuel. Product low B. Example: This example illustrates a hy- risk. (refer to ‘‘Product’’ risk table)—Risk pothetical model used to establish an integ- Value = 1 rity assessment schedule for a hypothetical Pipe size: 16 inches. Size presents moderate pipeline segment. After we determine the risk (refer to ‘‘Line Size’’ risk table)—Risk risk factors applicable to the pipeline seg- Value = 3 ment, we then assign values or numbers to iii. Overall risk value for this hypothetical each factor, such as, high (5), moderate (3), segment of pipe is 34. Assume we have two or low (1). We can determine an overall risk other pipeline segments for which we con- classification (A, B, C) for the segment using duct similar risk rankings. The second pipe- the risk tables and a sliding scale (values 5 line segment has an overall risk value of 20, to 1) for risk factors for which tables are not and the third segment, 11. For the baseline provided. We would classify a segment as C if assessment we would establish a schedule it fell above 2⁄3 of maximum value (highest where we assess the first segment (highest overall risk value for any one segment when risk segment) within two years, the second compared with other segments of a pipeline), segment within five years and the third seg- a segment as B if it fell between 1⁄3 to 2⁄3 of ment within seven years. Similarly, for the maximum value, and the remaining seg- continuing integrity assessment, we could ments as A. establish an assessment schedule where we i. For the baseline assessment schedule, we assess the highest risk segment no later than would plan to assess 50% of all pipeline seg- the second year, the second segment no later ments covered by the rule, beginning with than the third year, and the third segment the highest risk segments, within the first no later than the fifth year.

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III. Safety risk indicator tables for leak tion flaws or soil movement, or other outside history, volume or line size, age of pipeline, force damage; and product transported. (2) Metal Loss Tools (Ultrasonic and Mag- netic Flux Leakage) for determining pipe LEAK HISTORY wall anomalies, e.g., wall loss due to corro- sion. Safety risk Leak history (3) Crack Detection Tools for detecting 1 indicator (Time-dependent defects) cracks and crack-like features, e.g., stress High ...... >3 Spills in last 10 years corrosion cracking (SCC), fatigue cracks, Low ...... <3 Spills in last 10 years narrow axial corrosion, toe cracks, hook cracks, etc. 1 Time-dependent defects are those that result in spills due to corrosion, gouges, or problems developed during manufac- V. Methods to measure performance. ture, construction or operation, etc. A. General. (1) This guidance is to help an operator establish measures to evaluate the LINE SIZE OR VOLUME TRANSPORTED effectiveness of its integrity management program. The performance measures re- Safety risk Line size quired will depend on the details of each in- indicator tegrity management program and will be High ...... ≥18′ based on an understanding and analysis of Moderate ...... 10′—16′ nominal diameters the failure mechanisms or threats to integ- Low ...... ≤8′ nominal diameter rity of each pipeline segment. (2) An operator should select a set of meas- urements to judge how well its program is AGE OF PIPELINE performing. An operator’s objectives for its program are to ensure public safety, prevent Safety risk Age Pipeline condition indicator dependent) 1 or minimize leaks and spills and prevent property and environmental damage. A typ- High ...... >25 years ical integrity management program will be Low ...... <25 years an ongoing program and it may contain 1 Depends on pipeline’s coating & corrosion condition, and many elements. Therefore, several perform- steel quality, toughness, welding. ance measure are likely to be needed to measure the effectiveness of an ongoing pro- PRODUCT TRANSPORTED gram. B. Performance measures. These measures Safety show how a program to control risk on pipe- risk 1 indi- Considerations Product examples line segments that could affect a high con- cator sequence area is progressing under the integ- rity management requirements. Perform- High ... (Highly volatile and flam- (Propane, butane, Nat- ance measures generally fall into three cat- mable). ural Gas Liquid (NGL), ammonia). egories: Highly toxic ...... (Benzene, high Hydro- (1) Selected Activity Measures—Measures gen Sulfide content that monitor the surveillance and preventive crude oils). activities the operator has implemented. Me- Flammable—flashpoint (Gasoline, JP4, low These measure indicate how well an operator dium. <100F. flashpoint crude oils). is implementing the various elements of its Low .... Non-flammable— (Diesel, fuel oil, ker- integrity management program. flashpoint 100 + F. osene, JP5, most (2) Deterioration Measures—Operation and crude oils). maintenance trends that indicate when the 1 The degree of acute and chronic toxicity to humans, wild- integrity of the system is weakening despite life, and aquatic life; reactivity; and, volatility, flammability, and water solubility determine the Product Indicator. Comprehen- preventive measures. This category of per- sive Environmental Response, Compensation and Liability Act formance measure may indicate that the sys- Reportable Quantity values may be used as an indication of tem condition is deteriorating despite well chronic toxicity. National Fire Protection Association health factors may be used for rating acute hazards. executed preventive activities. (3) Failure Measures—Leak History, inci- IV. Types of internal inspection tools to dent response, product loss, etc. These meas- use. ures will indicate progress towards fewer An operator should consider at least two spills and less damage. types of internal inspection tools for the in- C. Internal vs. External Comparisons. These tegrity assessment from the following list. comparisons show how a pipeline segment The type of tool or tools an operator selects that could affect a high consequence area is will depend on the results from previous in- progressing in comparison to the operator’s ternal inspection runs, information analysis other pipeline segments that are not covered and risk factors specific to the pipeline seg- by the integrity management requirements ment: and how that pipeline segment compares to (1) Geometry Internal inspection tools for other operators’ pipeline segments. detecting changes to ovality, e.g., bends, (1) Internal—Comparing data from the dents, buckles or wrinkles, due to construc- pipeline segment that could affect the high

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consequence area with data from pipeline (2) a plan for baseline assessment of the segments in other areas of the system may line pipe that includes each required plan indicate the effects from the attention given element; to the high consequence area. (3) modifications to the baseline plan and (2) External—Comparing data external to reasons for the modification; the pipeline segment (e.g., OPS incident (4) use of and support for an alternative data) may provide measures on the fre- practice; quency and size of leaks in relation to other (5) a framework addressing each required companies. element of the integrity management pro- D. Examples. Some examples of perform- gram, updates and changes to the initial ance measures an operator could use in- framework and eventual program; clude— (6) a process for identifying a new high (1) A performance measurement goal to re- consequence area and incorporating it into duce the total volume from unintended re- the baseline plan, particularly, a process for leases by -% (percent to be determined by op- identifying population changes around a erator) with an ultimate goal of zero. pipeline segment; (2) A performance measurement goal to re- (7) an explanation of methods selected to duce the total number of unintended releases assess the integrity of line pipe; (based on a threshold of 5 gallons) by ll-% (8) a process for review of integrity assess- (percent to be determined by operator) with ment results and data analysis by a person an ultimate goal of zero. qualified to evaluate the results and data; (3) A performance measurement goal to (9) the process and risk factors for deter- document the percentage of integrity man- mining the baseline assessment interval; agement activities completed during the cal- (10) results of the baseline integrity assess- endar year. ment; (4) A performance measurement goal to (11) the process used for continual evalua- track and evaluate the effectiveness of the tion, and risk factors used for determining operator’s community outreach activities. the frequency of evaluation; (12) process for integrating and analyzing (5) A narrative description of pipeline sys- information about the integrity of a pipe- tem integrity, including a summary of per- line, information and data used for the infor- formance improvements, both qualitative mation analysis; and quantitative, to an operator’s integrity management program prepared periodically. (13) results of the information analyses and periodic evaluations; (6) A performance measure based on inter- (14) the process and risk factors for estab- nal audits of the operator’s pipeline system lishing continual re-assessment intervals; per 49 CFR Part 195. (15) justification to support any variance (7) A performance measure based on exter- from the required re-assessment intervals; nal audits of the operator’s pipeline system (16) integrity assessment results and anom- per 49 CFR Part 195. alies found, process for evaluating and reme- (8) A performance measure based on oper- diating anomalies, criteria for remedial ac- ational events (for example: relief occur- tions and actions taken to evaluate and re- rences, unplanned valve closure, SCADA out- mediate the anomalies; ages, etc.) that have the potential to ad- (17) other remedial actions planned or versely affect pipeline integrity. taken; (9) A performance measure to demonstrate (18) schedule for evaluation and remedi- that the operator’s integrity management ation of anomalies, justification to support program reduces risk over time with a focus deviation from required remediation times; on high risk items. (19) risk analysis used to identify addi- (10) A performance measure to dem- tional preventive or mitigative measures, onstrate that the operator’s integrity man- records of preventive and mitigative actions agement program for pipeline stations and planned or taken; terminals reduces risk over time with a (20) criteria for determining EFRD instal- focus on high risk items. lation; VI. Examples of types of records an oper- (21) criteria for evaluating and modifying ator must maintain. leak detection capability; The rule requires an operator to maintain (22) methods used to measure the pro- certain records. (See § 195.452(l)). This section gram’s effectiveness. provides examples of some records that an VII. Conditions that may impair a pipe- operator would have to maintain for inspec- line’s integrity. tion to comply with the requirement. This is Section 195.452(h) requires an operator to not an exhaustive list. evaluate and remediate all pipeline integrity (1) a process for identifying which pipelines issues raised by the integrity assessment or could affect a high consequence area and a information analysis. An operator must de- document identifying all pipeline segments velop a schedule that prioritizes conditions that could affect a high consequence area; discovered on the pipeline for evaluation and

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remediation. The following are some exam- SOURCE: 80 FR 43866, July 23, 2015, unless ples of conditions that an operator should otherwise noted. schedule for evaluation and remediation. A. Any change since the previous assess- ment. Subpart A—General B. Mechanical damage that is located on the top side of the pipe. § 196.1 What is the purpose and scope C. An anomaly abrupt in nature. of this part? D. An anomaly longitudinal in orientation. This part prescribes the minimum re- E. An anomaly over a large area. F. An anomaly located in or near a casing, quirements that excavators must fol- a crossing of another pipeline, or an area low to protect underground pipelines with suspect cathodic protection. from excavation-related damage. It [Amdt. 195–70, 65 FR 75409, Dec. 1, 2000, as also establishes an enforcement process amended by Amdt. 195–74, 67 FR 1661, Jan. 14, for violations of these requirements. 2002; Amdt. 195–94, 75 FR 48608, Aug. 11, 2010] § 196.3 Definitions. PART 196—PROTECTION OF UN- Damage or excavation damage means DERGROUND PIPELINES FROM any excavation activity that results in EXCAVATION ACTIVITY the need to repair or replace a pipeline due to a weakening, or the partial or Subpart A—General complete destruction, of the pipeline, including, but not limited to, the pipe, 196.1 What is the purpose and scope of this part? appurtenances to the pipe, protective 196.3 Definitions. coatings, support, cathodic protection or the housing for the line device or fa- Subpart B—Damage Prevention cility. Requirements Excavation refers to excavation ac- 196.101 What is the purpose and scope of this tivities as defined in § 192.614, and cov- subpart? ers all excavation activity involving 196.103 What must an excavator do to pro- both mechanized and non-mechanized tect underground pipelines from exca- equipment, including hand tools. vation-related damage? 196.105 [Reserved] Excavator means any person or legal 196.107 What must an excavator do if a pipe- entity, public or private, proposing to line is damaged by excavation activity? or engaging in excavation. 196.109 What must an excavator do if dam- One-call means a notification system age to a pipeline from excavation activ- through which a person can notify ity causes a leak where product is re- pipeline operators of planned exca- leased from the pipeline? 196.111 What if a pipeline operator fails to vation to facilitate the locating and respond to a locate request or fails to ac- marking of any pipelines in the exca- curately locate and mark its pipeline? vation area. Pipeline means all parts of those Subpart C—Administrative Enforcement physical facilities through which gas, Process carbon dioxide, or a hazardous liquid 196.201 What is the purpose and scope of this moves in transportation, including, but subpart? not limited to, pipe, valves, and other 196.203 What is the administrative process appurtenances attached or connected PHMSA will use to conduct enforcement to pipe (including, but not limited to, proceedings for alleged violations of ex- cavation damage prevention require- tracer wire, radio frequency identifica- ments? tion or other electronic marking sys- 196.205 Can PHMSA assess administrative tem devices), pumping units, com- civil penalties for violations? pressor units, metering stations, regu- 196.207 What are the maximum administra- lator stations, delivery stations, hold- tive civil penalties for violations? 196.209 May other civil enforcement actions ers, fabricated assemblies, and break- be taken? out tanks. 196.211 May criminal penalties be imposed?

AUTHORITY: 49 U.S.C. 60101 et seq.; and 49 CFR 1.97.

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