pt. 195 49 cfr ch. i (101 01 edition) - legismex...

120

49 CFR Ch. I (10–1–01 Edition)Pt. 195

Major rivers Nearest town and state

Smokey Hill River .................. Abilene, KS.Susquehanna River ............... Darlington, MD.Tenessee River ..................... New Johnsonville, TN.Wabash River ........................ Harmony, IN.Wabash River ........................ Terre Haute, IN.Wabash River ........................ Mt. Carmel, IL.White River ............................ Batesville, AR.White River ............................ Grand Glaise, AR.Wisconsin River ..................... Wisconsin Rapids, WI.Yukon River ........................... Fairbanks, AK.

Other Navigable Waters

Arthur Kill Channel, NYCook Inlet, AKFreeport, TXLos Angeles/Long Beach Harbor, CAPort Lavaca, TXSan Fransico/San Pablo Bay, CA

PART 195—TRANSPORTATION OFHAZARDOUS LIQUIDS BY PIPELINE

Subpart A—General

Sec.195.0 Scope.195.1 Applicability.195.2 Definitions.195.3 Matter incorporated by reference.195.4 Compatibility necessary for transpor-

tation of hazardous liquids or carbon di-oxide.

195.5 Conversion to service subject to thispart.

195.6 Unusually Sensitive Areas (USAs).195.8 Transportation of hazardous liquid or

carbon dioxide in pipelines constructedwith other than steel pipe.

195.9 Outer continental shelf pipelines.195.10 Responsibility of operator for compli-

ance with this part.

Subpart B—Reporting Accidents andSafety–Related Conditions

195.50 Reporting accidents.195.52 Telephonic notice of certain acci-

dents.195.54 Accident reports.195.55 Reporting safety–related conditions.195.56 Filing safety–related condition re-

ports.195.57 Filing offshore pipeline condition re-

ports.195.58 Address for written reports.195.59 Abandoned underwater facilities re-

port.195.60 Operator assistance in investigation.195.62 Supplies of accident report DOT

Form 7000–1.195.63 OMB control number assigned to in-

formation collection.

Subpart C—Design Requirements

195.100 Scope.195.101 Qualifying metallic components

other than pipe.195.102 Design temperature.195.104 Variations in pressure.195.106 Internal design pressure.195.108 External pressure.195.110 External loads.195.111 Fracture propagation.195.112 New pipe.195.114 Used pipe.195.116 Valves.195.118 Fittings.195.120 Passage of internal inspection de-

vices.195.122 Fabricated branch connections.195.124 Closures.195.126 Flange connection.195.128 Station piping.195.130 Fabricated assemblies.195.132 Design and construction of above-

ground breakout tanks.195.134 CPM leak detection.

Subpart D—Construction

195.200 Scope.195.202 Compliance with specifications or

standards.195.204 Inspection—general.195.205 Repair, alteration and reconstruc-

tion of aboveground breakout tanks thathave been in service.

195.206 Material inspection.195.208 Welding of supports and braces.195.210 Pipeline location.195.212 Bending of pipe.195.214 Welding: General.195.216 Welding: Miter joints.195.222 Welders: Qualification of welders.195.224 Welding: Weather.195.226 Welding: Arc burns.195.228 Welds and welding inspection:

Standards of acceptability.195.230 Welds: Repair or removal of defects.195.234 Welds: Nondestructive testing.195.236 External corrosion protection.195.238 External coating.195.242 Cathodic protection system.195.244 Test leads.195.246 Installation of pipe in a ditch.195.248 Cover over buried pipeline.195.250 Clearance between pipe and under-

ground structures.195.252 Backfilling.195.254 Above ground components.195.256 Crossing of railroads and highways.195.258 Valves: General.195.260 Valves: Location.195.262 Pumping equipment.195.264 Impoundment, protection against

entry, normal/emergency venting orpressure/vacuum relief for abovegroundbreakout tanks.

195.266 Construction records.

VerDate 11<MAY>2000 12:25 Nov 06, 2001 Jkt 194202 PO 00000 Frm 00120 Fmt 8010 Sfmt 8010 Y:\SGML\194202T.XXX pfrm01 PsN: 194202T

121

Research and Special Programs Administration, DOT § 195.1

Subpart E—Pressure Testing

195.300 Scope.195.302 General requirements.195.303 Risk-based alternative to pressure

testing older hazardous liquid and carbondioxide pipelines.

195.304 Test pressure.195.305 Testing of components.195.306 Test medium.195.307 Pressure testing aboveground break-

out tanks.195.308 Testing of tie-ins.195.310 Records.

Subpart F—Operation and Maintenance

195.400 Scope.195.401 General requirements.195.402 Procedural manual for operations,

maintenance, and emergencies.195.403 Training.195.404 Maps and records.195.405 Protection against ignitions and safe

access/egress involving floating roofs.195.406 Maximum operating pressure.195.408 Communications.195.410 Line markers.195.412 Inspection of rights-of-way and

crossings under navigable waters.195.413 Underwater inspection and reburial

of pipelines in the Gulf of Mexico and itsinlets.

195.414 Cathodic protection.195.416 External corrosion control.195.418 Internal corrosion control.195.420 Valve maintenance.195.422 Pipeline repairs.195.424 Pipe movement.195.426 Scraper and sphere facilities.195.428 Overpressure safety devices and

overfill protection systems.195.430 Firefighting equipment.195.432 Inspection of in-service breakout

tanks.195.434 Signs.195.436 Security of facilities.195.438 Smoking or open flames.195.440 Public education.195.442 Damage prevention program.195.444 CPM leak detection.

HIGH CONSEQUENCE AREAS

195.450 Definitions.

PIPELINE INTEGRITY MANAGEMENT

195.452 Pipeline integrity management inhigh consequence areas.

Subpart G—Qualification of PipelinePersonnel

195.501 Scope.195.503 Definitions.195.505 Qualification program.195.507 Recordkeeping.195.509 General.

APPENDIX A TO PART 195—DELINEATION BE-TWEEN FEDERAL AND STATE JURISDIC-TION—STATEMENT OF AGENCY POLICY ANDINTERPRETATION

APPENDIX B TO PART 195—RISK-BASED ALTER-NATIVE TO PRESSURE TESTING OLDER HAZ-ARDOUS LIQUID AND CARBON DIOXIDE PIPE-LINES

APPENDIX C TO PART 195—GUIDANCE FOR IM-PLEMENTATION OF INTEGRITY MANAGE-MENT PROGRAM

AUTHORITY: 49 U.S.C. 5103, 60102, 60104,60108, 60109, 60118; and 49 CFR 1.53.

SOURCE: Amdt. 195–22, 46 FR 38360, July 27,1981, unless otherwise noted.

Subpart A—General

§ 195.0 Scope.

This part prescribes safety standardsand reporting requirements for pipelinefacilities used in the transportation ofhazardous liquids or carbon dioxide.

[Amdt. 195–45, 56 FR 26925, June 12, 1991]

§ 195.1 Applicability.

(a) Except as provided in paragraph(b) of this section, this part applies topipeline facilities and the transpor-tation of hazardous liquids or carbondioxide associated with those facilitiesin or affecting interstate or foreigncommerce, including pipeline facilitieson the Outer Continental Shelf.

(b) This part does not apply to—(1) Transportation of a hazardous liq-

uid that is transported in a gaseousstate;

(2) Transportation of a hazardous liq-uid through a pipeline by gravity;

(3) Transportation through any of thefollowing low-stress pipelines:

(i) An onshore pipeline or pipelinesegment that—

(A) Does not transport HVL;(B) Is located in a rural area; and(C) Is located outside a waterway

currently used for commercial naviga-tion;

(ii) A pipeline subject to safety regu-lations of the U.S. Coast Guard; or

(iii) A pipeline that serves refining,manufacturing, or truck, rail, or vesselterminal facilities, if the pipeline isless than 1 mile long (measured outsidefacility grounds) and does not cross anoffshore area or a waterway currentlyused for commercial navigation;


122

49 CFR Ch. I (10–1–01 Edition)§ 195.2

(4) Transportation of petroleum inonshore gathering lines in rural areasexcept gathering lines in the inlets ofthe Gulf of Mexico subject to § 195.413;

(5) Transportation of hazardous liq-uid or carbon dioxide in offshore pipe-lines which are located upstream fromthe outlet flange of each facility wherehydrocarbons or carbon dioxide areproduced or where produced hydro-carbons or carbon dioxide are first sep-arated, dehydrated, or otherwise proc-essed, whichever facility is fartherdownstream;

(6) Transportation of hazardous liq-uid or carbon dioxide in Outer Conti-nental Shelf pipelines which are lo-cated upstream of the point at whichoperating responsibility transfers froma producing operator to a transportingoperator.

(7) Transportation of a hazardous liq-uid or carbon dioxide through onshoreproduction (including flow lines), refin-ing, or manufacturing facilities, orstorage or in-plant piping systems as-sociated with such facilities;

(8) Transportation of hazardous liq-uid or carbon dioxide—

(i) By vessel, aircraft, tank truck,tank car, or other non-pipeline mode oftransportation; or

(ii) Through facilities located on thegrounds of a materials transportationterminal that are used exclusively totransfer hazardous liquid or carbon di-oxide between non-pipeline modes oftransportation or between a non-pipe-line mode and a pipeline, not includingany device and associated piping thatare necessary to control pressure in thepipeline under § 195.406(b); and

(9) Transportation of carbon dioxidedownstream from the following point,as applicable:

(i) The inlet of a compressor used inthe injection of carbon dioxide for oilrecovery operations, or the point whererecycled carbon dioxide enters the in-jection system, whichever is fartherupstream; or

(ii) The connection of the firstbranch pipeline in the production fieldthat transports carbon dioxide to injec-tion wells or to headers or manifoldsfrom which pipelines branch to injec-tion wells.

(c) Breakout tanks subject to thispart must comply with requirements

that apply specifically to breakouttanks and, to the extent applicable,with requirements that apply to pipe-line systems and pipeline facilities. If aconflict exists between a requirementthat applies specifically to breakouttanks and a requirement that appliesto pipeline systems or pipeline facili-ties, the requirement that applies spe-cifically to breakout tanks prevails.Anhydrous ammonia breakout tanksneed not comply with §§ 195.132(b),195.205(b), 195.242 (c) and (d), 195.264 (b)and (e), 195.307, 195.428 (c) and (d), and195.432 (b) and (c).

[Amdt. 195–22, 46 FR 38360, July 27, 1981]

EDITORIAL NOTE: For FEDERAL REGISTER ci-tations affecting § 195.1, see the List of Sec-tions Affected, which appears in the FindingAids section of the printed volume and onGPO Access.

§ 195.2 Definitions.

As used in this part—Abandoned means permanently re-

moved from service.Administrator means the Adminis-

trator of the Research and Special Pro-grams Administration or any person towhom authority in the matter con-cerned has been delegated by the Sec-retary of Transportation.

Barrel means a unit of measurementequal to 42 U.S. standard gallons.

Breakout tank means a tank used to(a) relieve surges in a hazardous liquidpipeline system or (b) receive and storehazardous liquid transported by a pipe-line for reinjection and continuedtransportation by pipeline.

Carbon dioxide means a fluid con-sisting of more than 90 percent carbondioxide molecules compressed to asupercritical state.

Component means any part of a pipe-line which may be subjected to pumppressure including, but not limited to,pipe, valves, elbows, tees, flanges, andclosures.

Computation Pipeline Monitoring(CPM) means a software-based moni-toring tool that alerts the pipeline dis-patcher of a possible pipeline operatinganomaly that may be indicative of acommodity release.

Corrosive product means ‘‘corrosivematerial’’ as defined by § 173.136 Class8–Definitions of this chapter.


123


Exposed pipeline means a pipelinewhere the top of the pipe is protrudingabove the seabed in water less than 15feet (4.6 meters) deep, as measuredfrom the mean low water.

Flammable product means ‘‘flammableliquid’’ as defined by § 173.120 Class 3–Definitions of this chapter.

Gathering line means a pipeline 219.1mm (85⁄8 in) or less nominal outside di-ameter that transports petroleum froma production facility.

Gulf of Mexico and its inlets means thewaters from the mean high water markof the coast of the Gulf of Mexico andits inlets open to the sea (excludingrivers, tidal marshes, lakes, and ca-nals) seaward to include the territorialsea and Outer Continental Shelf to adepth of 15 feet (4.6 meters), as meas-ured from the mean low water.

Hazard to navigation means, for thepurpose of this part, a pipeline wherethe top of the pipe is less than 12inches (305 millimeters) below the sea-bed in water less than 15 feet (4.6 me-ters) deep, as measured from the meanlow water.

Hazardous liquid means petroleum,petroleum products, or anhydrous am-monia.

Highly volatile liquid or HVL means ahazardous liquid which will form avapor cloud when released to the at-mosphere and which has a vapor pres-sure exceeding 276 kPa (40 psia) at 37.8°C (100° F).

In-plant piping system means pipingthat is located on the grounds of aplant and used to transfer hazardousliquid or carbon dioxide between plantfacilities or between plant facilitiesand a pipeline or other mode of trans-portation, not including any device andassociated piping that are necessary tocontrol pressure in the pipeline under§ 195.406(b).

Interstate pipeline means a pipeline orthat part of a pipeline that is used inthe transportation of hazardous liquidsor carbon dioxide in interstate or for-eign commerce.

Intrastate pipeline means a pipeline orthat part of a pipeline to which thispart applies that is not an interstatepipeline.

Line section means a continuous runof pipe between adjacent pressure pumpstations, between a pressure pump sta-

tion and terminal or breakout tanks,between a pressure pump station and ablock valve, or between adjacent blockvalves.

Low-stress pipeline means a hazardousliquid pipeline that is operated in itsentirety at a stress level of 20 percentor less of the specified minimum yieldstrength of the line pipe.

Nominal wall thickness means the wallthickness listed in the pipe specifica-tions.

Offshore means beyond the line of or-dinary low water along that portion ofthe coast of the United States that isin direct contact with the open seasand beyond the line marking the sea-ward limit of inland waters.

Operator means a person who owns oroperates pipeline facilities.

Outer Continental Shelf means all sub-merged lands lying seaward and out-side the area of lands beneath navi-gable waters as defined in Section 2 ofthe Submerged Lands Act (43 U.S.C.1301) and of which the subsoil and sea-bed appertain to the United States andare subject to its jurisdiction and con-trol.

Person means any individual, firm,joint venture, partnership, corporation,association, State, municipality, coop-erative association, or joint stock asso-ciation, and includes any trustee, re-ceiver, assignee, or personal represent-ative thereof.

Petroleum means crude oil, conden-sate, natural gasoline, natural gas liq-uids, and liquefied petroleum gas.

Petroleum product means flammable,toxic, or corrosive products obtainedfrom distilling and processing of crudeoil, unfinished oils, natural gas liquids,blend stocks and other miscellaneoushydrocarbon compounds.

Pipe or line pipe means a tube, usu-ally cylindrical, through which a haz-ardous liquid or carbon dioxide flowsfrom one point to another.

Pipeline or pipeline system means allparts of a pipeline facility throughwhich a hazardous liquid or carbon di-oxide moves in transportation, includ-ing, but not limited to, line pipe,valves, and other appurtenances con-nected to line pipe, pumping units, fab-ricated assemblies associated withpumping units, metering and delivery


124

49 CFR Ch. I (10–1–01 Edition)§ 195.3

stations and fabricated assembliestherein, and breakout tanks.

Pipeline facility means new and exist-ing pipe, rights-of-way and any equip-ment, facility, or building used in thetransportation of hazardous liquids orcarbon dioxide.

Production facility means piping orequipment used in the production, ex-traction, recovery, lifting, stabiliza-tion, separation or treating of petro-leum or carbon dioxide, or associatedstorage or measurement. (To be a pro-duction facility under this definition,piping or equipment must be used inthe process of extracting petroleum orcarbon dioxide from the ground or fromfacilities where CO2 is produced, andpreparing it for transportation by pipe-line. This includes piping betweentreatment plants which extract carbondioxide, and facilities utilized for theinjection of carbon dioxide for recoveryoperations.)

Rural area means outside the limitsof any incorporated or unincorpatedcity, town, village, or any other des-ignated residential or commercial areasuch as a subdivision, a business orshopping center, or community devel-opment.

Specified minimum yield strengthmeans the minimum yield strength, ex-pressed in p.s.i. (kPa) gage, prescribedby the specification under which thematerial is purchased from the manu-facturer.

Stress level means the level of tangen-tial or hoop stress, usually expressed asa percentage of specified minimumyield strength.

Surge pressure means pressure pro-duced by a change in velocity of themoving stream that results from shut-ting down a pump station or pumpingunit, closure of a valve, or any otherblockage of the moving stream.

Toxic product means ‘‘poisonous ma-terial’’ as defined by § 173.132 Class 6,Division 6.1–Definitions of this chapter.

Unusually Sensitive Area (USA) meansa drinking water or ecological resourcearea that is unusually sensitive to en-vironmental damage from a hazardous

liquid pipeline release, as identifiedunder § 195.6.

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47FR 32721, July 29, 1982, as amended by Amdt.195–33, 50 FR 15898, Apr. 23, 1985; 50 FR 38660,Sept. 24, 1985; Amdt. 195–36, 51 FR 15007, Apr.22, 1986; Amdt. 195–45, 56 FR 26925, June 12,1991; Amdt. 195–47, 56 FR 63771, Dec. 5, 1991;Amdt. 195–50, 59 FR 17281, Apr. 12, 1994; Amdt.195–52, 59 FR 33395, 33396, June 28, 1994; Amdt.195–53, 59 FR 35471, July 12, 1994; Amdt. 195–59, 62 FR 61695, Nov. 19, 1997; Amdt. 195–62, 63FR 36376, July 6, 1998; Amdt. 195–63, 63 FR37506, July 13, 1998; Amdt. 195–69, 65 FR 54444,Sept. 8, 2000; Amdt. 195–71, 65 FR 80544, Dec.21, 2000]

§ 195.3 Matter incorporated by ref-erence.

(a) Any document or portion thereofincorporated by reference in this partis included in this part as though itwere printed in full. When only a por-tion of a document is referenced, thenthis part incorporates only that ref-erenced portion of the document andthe remainder is not incorporated. Ap-plicable editions are listed in para-graph (c) of this section in parenthesesfollowing the title of the referencedmaterial. Earlier editions listed in pre-vious editions of this section may beused for components manufactured, de-signed, or installed in accordance withthose earlier editions at the time theywere listed. The user must refer to theappropriate previous edition of 49 CFRfor a listing of the earlier editions.

(b) All incorporated materials areavailable for inspection in the Re-search and Special Programs Adminis-tration, 400 Seventh Street, SW., Wash-ington, DC, and at the Office of theFederal Register, 800 North CapitolStreet, NW., suite 700, Washington, DC.These materials have been approved forincorporation by reference by the Di-rector of the Federal Register in ac-cordance with 5 U.S.C. 552(a) and 1 CFRpart 51. In addition, materials incor-porated by reference are available asfollows:

(1) American Gas Association (AGA),1515 Wilson Boulevard, Arlington, VA22209.

(2) American Petroleum Institute(API), 1220 L Street, NW., Washington,DC 20005.


125


(3) The American Society of Mechan-ical Engineers (ASME), United Engi-neering Center, 345 East 47th Street,New York, NY 10017.

(4) Manufacturers StandardizationSociety of the Valve and Fittings In-dustry, Inc. (MSS), 127 Park Street,NE., Vienna, VA 22180.

(5) American National Standards In-stitute (ANSI), 11 West 42nd Street,New York, NY 10036.

(6) American Society for Testing andMaterials (ASTM), 100 Barr HarborDrive, West Conshohocken, PA 19428.

(7) National Fire Protection Associa-tion (NFPA), 11 Tracy Drive, Avon, MA02322.

(c) The full titles of publications in-corporated by reference wholly or par-tially in this part are as follows. Num-bers in parentheses indicate applicableeditions:

(1) American Gas Association (AGA):AGA Pipeline Research Committee,Project PR–3–805, ‘‘A Modified Cri-terion for Evaluating the RemainingStrength of Corroded Pipe’’ (December1989). The RSTRENG program may beused for calculating remainingstrength.

(2) American Petroleum Institute(API):

(i) API 510 ‘‘Pressure Vessel Inspec-tion Code: Maintenance Inspection,Rating, Repair, and Alteration’’ (8thedition, June 1997).

(ii) API 1130 ‘‘Computational PipelineMonitoring’’ (1st Edition, 1995).

(iii) API Publication 2026 ‘‘Safe Ac-cess/Egress Involving Floating Roofs ofStorage Tanks in Petroleum Service’’(2nd edition, April 1998).

(iv) API Recommended Practice 651‘‘Cathodic Protection of AbovegroundPetroleum Storage Tanks’’ (2nd edi-tion, December 1997).

(v) API Recommended Practice 652‘‘Lining of Aboveground PetroleumStorage Tank Bottoms’’ (2nd edition,December 1997).

(vi) API Recommended Practice 2003‘‘Protection Against Ignitions Arisingout of Static, Lightning, and StrayCurrents’’ (6th edition, December 1998).

(vii) API Recommended Practice 2350‘‘Overfill Protection for Storage TanksIn Petroleum Facilities’’ (2nd edition,January 1996).

(viii) API Specification 5L ‘‘Speci-fication for Line Pipe’’ (41st edition,1995).

(ix) API Specification 6D ‘‘Specifica-tion for Pipeline Valves (Gate, Plug,Ball, and Check Valves)’’ (21st edition,1994).

(x) API Specification 12F ‘‘Specifica-tion for Shop Welded Tanks for Storageof Production Liquids’’ (11th edition,November 1994).

(xi) API Standard 1104 ‘‘WeldingPipelines and Related Facilities’’ (18thedition, 1994).

(xii) API Standard 620 ‘‘Design andConstruction of Large, Welded, Low-Pressure Storage Tanks’’ (9th edition,February 1996, Including Addenda 1 and2).

(xiii) API Standard 650 ‘‘Welded SteelTanks for Oil Storage’’ (9th edition,July 1993 (Including Addenda 1 through4).

(xiv) API Standard 653 ‘‘Tank Inspec-tion, Repair, Alteration, and Recon-struction’’ (2nd edition, December 1995,including Addenda 1 & 2).

(xv) API Standard 2000 ‘‘Venting At-mospheric and Low-Pressure StorageTanks’’ (4th edition, September 1992).

(xvi) API Standard 2510 ‘‘Design andConstruction of LPG Installations’’(7th edition, May 1995).

(3) American Society of MechanicalEngineers (ASME):

(i) ASME/ANSI B16.9 ‘‘Factory-MadeWrought Steel Buttwelding Fittings’’(1993).

(ii) ASME/ANSI B31.4 ‘‘Liquid Trans-portation Systems for Hydrocarbons,Liquid Petroleum Gas, Anhydrous Am-monia, and Alcohols’’ (1992 edition withASME B31.4a–1994 Addenda).

(iii) ASME/ANSI B31.8 ‘‘Gas Trans-mission and Distribution Piping Sys-tems’’ (1995)

(iv) ASME/ANSI B31G ‘‘Manual forDetermining the Remaining Strengthof Corroded Pipelines’’ (1991).

(v) ASME Boiler and Pressure VesselCode, Section VIII ‘‘Pressure Vessels,’’Divisions 1 and 2 (1995 edition with 1995Addenda).

(vi) ASME Boiler and Pressure VesselCode, Section IX ‘‘Welding and BrazingQualifications’’ (1995 edition with 1995Addenda).


126

49 CFR Ch. I (10–1–01 Edition)§ 195.4

(4) Manufacturers StandardizationSociety of the Valve and Fittings In-dustry, Inc. (MSS):

(i) MSS SP–75 ‘‘Specification forHigh Test Wrought Butt Welding Fit-tings’’ (1993).

(ii) [Reserved](5) American Society for Testing and

Materials (ASTM):(i) ASTM Designation A 53 ‘‘Standard

specification for Pipe, Steel, Black andHot-Dipped, Zinc-Coated Welded andSeamless’’ (A 53–96).

(ii) ASTM Designation: A 106 ‘‘Stand-ard Specification for Seamless CarbonSteel Pipe for High-Temperature Serv-ice’’ (A 106–95).

(iii) ASTM Designation: A 333/A 333M‘‘Standard Specification for Seamlessand Welded Steel Pipe for Low-Tem-perature Service’’(A 333/A 333M–94).

(iv) ASTM Designation: A 381‘‘Standard Specification for Metal-Arc-Welded Steel Pipe for Use With High-Pressure Transmission Systems’’ (A381–93).

(v) ASTM Designation: A 671 ‘‘Stand-ard Specification for Electric-Fusion-Welded Steel Pipe for Atmospheric andLower Temperatures’’ (A 671–94).

(vi) ASTM Designation: A 672‘‘Standard Specification for Electric-Fusion-Welded Steel Pipe for High-Pressure Service at Moderate Tempera-tures’’ (A 672–94).

(vii) ASTM Designation: A 691‘‘Standard Specification for Carbon andAlloy Steel Pipe Electric-Fusion-Weld-ed for High- Pressure Service at HighTemperatures’’ (A 691–93).

(6) National Fire Protection Associa-tion (NFPA):

(i) ANSI/NFPA 30 ‘‘Flammable andCombustible Liquids Code,’’ (1996).

(ii) [Reserved]

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47FR 32721, July 29, 1982, as amended by Amdt.195–32, 49 FR 36860, Sept. 20, 1984; 58 FR 14523,Mar. 18, 1993; Amdt. 195–52, 59 FR 33396, June28, 1994; Amdt. 195–56, 61 FR 26123, May 24,1996; 61 FR 36826, July 15, 1996; Amdt. 195–61,63 FR 7723, Feb. 17, 1998; Amdt. 195–62, 63 FR36376, July 6, 1998; Amdt. 195–66, 64 FR 15934,Apr. 2, 1999; 65 FR 4770, Feb. 1, 2000]

§ 195.4 Compatibility necessary fortransportation of hazardous liquidsor carbon dioxide.

No person may transport any haz-ardous liquid or carbon dioxide unless

the hazardous liquid or carbon dioxideis chemically compatible with both thepipeline, including all components, andany other commodity that it may comeinto contact with while in the pipeline.

[Amdt. 195–45, 56 FR 26925, June 12, 1991]

§ 195.5 Conversion to service subjectto this part.

(a) A steel pipeline previously used inservice not subject to this part quali-fies for use under this part if the oper-ator prepares and follows a writtenprocedure to accomplish the following:

(1) The design, construction, oper-ation, and maintenance history of thepipeline must be reviewed and, wheresufficient historical records are notavailable, appropriate tests must beperformed to determine if the pipelineis in satisfactory condition for safe op-eration. If one or more of the variablesnecessary to verify the design pressureunder § 195.106 or to perform the testingunder paragraph (a)(4) of this section isunknown, the design pressure may beverified and the maximum operatingpressure determined by—

(i) Testing the pipeline in accordancewith ASME B31.8, Appendix N, toproduce a stress equal to the yieldstrength; and

(ii) Applying, to not more than 80percent of the first pressure that pro-duces a yielding, the design factor F in§ 195.106(a) and the appropriate factorsin § 195.106(e).

(2) The pipeline right-of-way, allaboveground segments of the pipeline,and appropriately selected under-ground segments must be visually in-spected for physical defects and oper-ating conditions which reasonablycould be expected to impair thestrength or tightness of the pipeline.

(3) All known unsafe defects and con-ditions must be corrected in accord-ance with this part.

(4) The pipeline must be tested in ac-cordance with subpart E of this part tosubstantiate the maximum operatingpressure permitted by § 195.406.

(b) A pipeline which qualifies for useunder this section need not complywith the corrosion control require-ments of this part until 12 months


127


after it is placed in service, notwith-standing any earlier deadlines for com-pliance. In addition to the require-ments of subpart F of this part, thecorrosion control requirements of sub-part D apply to each pipeline whichsubstantially meets those require-ments before it is placed in service orwhich is a segment that is replaced, re-located, or substantially altered.

(c) Each operator must keep for thelife of the pipeline a record of the in-vestigations, tests, repairs, replace-ments, and alterations made under therequirements of paragraph (a) of thissection.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended by Amdt. 195–52, 59 FR 33396, June28, 1994]

§ 195.6 Unusually Sensitive Areas(USAs).

As used in this part, a USA means adrinking water or ecological resourcearea that is unusually sensitive to en-vironmental damage from a hazardousliquid pipeline release.

(a) An USA drinking water resourceis:

(1) The water intake for a Commu-nity Water System (CWS) or a Non-transient Non-community Water Sys-tem (NTNCWS) that obtains its watersupply primarily from a surface watersource and does not have an adequatealternative drinking water source;

(2) The Source Water Protection Area(SWPA) for a CWS or a NTNCWS thatobtains its water supply from a Class Ior Class IIA aquifer and does not havean adequate alternative drinking watersource. Where a state has not yet iden-tified the SWPA, the Wellhead Protec-tion Area (WHPA) will be used untilthe state has identified the SWPA; or

(3) The sole source aquifer rechargearea where the sole source aquifer is akarst aquifer in nature.

(b) An USA ecological resource is:(1) An area containing a critically

imperiled species or ecological commu-nity;

(2) A multi-species assemblage area;(3) A migratory waterbird concentra-

tion area;(4) An area containing an imperiled

species, threatened or endangered spe-cies, depleted marine mammal species,or an imperiled ecological community

where the species or community isaquatic, aquatic dependent, or terres-trial with a limited range; or

(5) An area containing an imperiledspecies, threatened or endangered spe-cies, depleted marine mammal species,or imperiled ecological communitywhere the species or community occur-rence is considered to be one of themost viable, highest quality, or in thebest condition, as identified by an ele-ment occurrence ranking (EORANK) ofA (excellent quality) or B (good qual-ity).

(c) As used in this part—Adequate Alternative Drinking Water

Source means a source of water thatcurrently exists, can be used almostimmediately with a minimal amount ofeffort and cost, involves no decline inwater quality, and will meet the con-sumptive, hygiene, and fire fighting re-quirements of the existing populationof impacted customers for at least onemonth for a surface water source ofwater and at least six months for agroundwater source.

Aquatic or Aquatic Dependent Speciesor Community means a species or com-munity that primarily occurs in aquat-ic, marine, or wetland habitats, as wellas species that may use terrestrialhabitats during all or some portion oftheir life cycle, but that are still close-ly associated with or dependent uponaquatic, marine, or wetland habitatsfor some critical component or portionof their life-history (i.e., reproduction,rearing and development, feeding, etc).

Class I Aquifer means an aquifer thatis surficial or shallow, permeable, andis highly vulnerable to contamination.Class I aquifers include:

(1) Unconsolidated Aquifers (Class Ia)that consist of surficial, unconsoli-dated, and permeable alluvial, terrace,outwash, beach, dune and other similardeposits. These aquifers generally con-tain layers of sand and gravel that,commonly, are interbedded to some de-gree with silt and clay. Not all Class Iaaquifers are important water-bearingunits, but they are likely to be bothpermeable and vulnerable. The onlynatural protection of these aquifers isthe thickness of the unsaturated zoneand the presence of fine-grained mate-rial;


128

49 CFR Ch. I (10–1–01 Edition)§ 195.6

(2) Soluble and Fractured BedrockAquifers (Class Ib). Lithologies in thisclass include limestone, dolomite, and,locally, evaporitic units that containdocumented karst features or solutionchannels, regardless of size. Generallythese aquifers have a wide range of per-meability. Also included in this classare sedimentary strata, and meta-morphic and igneous (intrusive and ex-trusive) rocks that are significantlyfaulted, fractured, or jointed. In allcases groundwater movement is largelycontrolled by secondary openings. Wellyields range widely, but the importantfeature is the potential for rapidvertical and lateral ground watermovement along preferred pathways,which result in a high degree of vulner-ability;

(3) Semiconsolidated Aquifers (ClassIc) that generally contain poorly tomoderately indurated sand and gravelthat is interbedded with clay and silt.This group is intermediate to the un-consolidated and consolidated endmembers. These systems are commonin the Tertiary age rocks that are ex-posed throughout the Gulf and Atlanticcoastal states. Semiconsolidated condi-tions also arise from the presence ofintercalated clay and caliche withinprimarily unconsolidated to poorlyconsolidated units, such as occurs inparts of the High Plains Aquifer; or

(4) Covered Aquifers (Class Id) thatare any Class I aquifer overlain by lessthan 50 feet of low permeability, un-consolidated material, such as glacialtill, lacustrian, and loess deposits.

Class IIa aquifer means a Higher YieldBedrock Aquifer that is consolidatedand is moderately vulnerable to con-tamination. These aquifers generallyconsist of fairly permeable sandstoneor conglomerate that contain lesseramounts of interbedded fine grainedclastics (shale, siltstone, mudstone)and occasionally carbonate units. Ingeneral, well yields must exceed 50 gal-lons per minute to be included in thisclass. Local fracturing may contributeto the dominant primary porosity andpermeability of these systems.

Community Water System (CWS) meansa public water system that serves atleast 15 service connections used byyear-round residents of the area or reg-

ularly serves at least 25 year-roundresidents.

Critically imperiled species or ecologicalcommunity (habitat) means an animal orplant species or an ecological commu-nity of extreme rarity, based on TheNature Conservancy’s Global Conserva-tion Status Rank. There are generally5 or fewer occurrences, or very few re-maining individuals (less than 1,000) oracres (less than 2,000). These speciesand ecological communities are ex-tremely vulnerable to extinction due tosome natural or man-made factor.

Depleted marine mammal species meansa species that has been identified and isprotected under the Marine MammalProtection Act of 1972, as amended(MMPA) (16 U.S.C. 1361 et seq.). Theterm ‘‘depleted’’ refers to marine mam-mal species that are listed as threat-ened or endangered, or are below theiroptimum sustainable populations (16U.S.C. 1362). The term ‘‘marine mam-mal’’ means ‘‘any mammal which ismorphologically adapted to the marineenvironment (including sea otters andmembers of the orders Sirenia,Pinnipedia, and Cetacea), or primarilyinhabits the marine environment (suchas the polar bear)’’ (16 U.S.C. 1362). Theorder Sirenia includes manatees, theorder Pinnipedia includes seals, sealions, and walruses, and the order Ceta-cea includes dolphins, porpoises, andwhales.

Ecological community means an inter-acting assemblage of plants and ani-mals that recur under similar environ-mental conditions across the land-scape.

Element occurrence rank (EORANK)means the condition or viability of aspecies or ecological community occur-rence, based on a population’s size,condition, and landscape context.EORANKs are assigned by the NaturalHeritage Programs. An EORANK of Ameans an excellent quality and anEORANK of B means good quality.

Imperiled species or ecological commu-nity (habitat) means a rare species orecological community, based on TheNature Conservancy’s Global Conserva-tion Status Rank. There are generally6 to 20 occurrences, or few remainingindividuals (1,000 to 3,000) or acres(2,000 to 10,000). These species and eco-logical communities are vulnerable to


129


extinction due to some natural or man-made factor.

Karst aquifer means an aquifer that iscomposed of limestone or dolomitewhere the porosity is derived from con-nected solution cavities. Karst aquifersare often cavernous with high rates offlow.

Migratory waterbird concentration areameans a designated Ramsar site or aWestern Hemisphere Shorebird ReserveNetwork site.

Multi-species assemblage area meansan area where three or more differentcritically imperiled or imperiled spe-cies or ecological communities, threat-ened or endangered species, depletedmarine mammals, or migratorywaterbird concentrations co-occur.

Non-transient Non-community WaterSystem (NTNCWS) means a public watersystem that regularly serves at least 25of the same persons over six monthsper year. Examples of these systems in-clude schools, factories, and hospitalsthat have their own water supplies.

Public Water System (PWS) means asystem that provides the public waterfor human consumption through pipesor other constructed conveyances, ifsuch system has at least 15 service con-nections or regularly serves an averageof at least 25 individuals daily at least60 days out of the year. These systemsinclude the sources of the water sup-plies—i.e., surface or ground. PWS canbe community, non-transient non-com-munity, or transient non-communitysystems.

Ramsar site means a site that hasbeen designated under The Conventionon Wetlands of International Impor-tance Especially as Waterfowl Habitatprogram. Ramsar sites are globallycritical wetland areas that support mi-gratory waterfowl. These include wet-land areas that regularly support 20,000waterfowl; wetland areas that regu-larly support substantial numbers ofindividuals from particular groups ofwaterfowl, indicative of wetland val-ues, productivity, or diversity; andwetland areas that regularly support1% of the individuals in a population ofone species or subspecies of waterfowl.

Sole source aquifer (SSA) means anarea designated by the U.S. Environ-mental Protection Agency under theSole Source Aquifer program as the

‘‘sole or principal’’ source of drinkingwater for an area. Such designationsare made if the aquifer’s ground watersupplies 50% or more of the drinkingwater for an area, and if that aquiferwere to become contaminated, it wouldpose a public health hazard. A solesource aquifer that is karst in nature isone composed of limestone where theporosity is derived from connected so-lution cavities. They are often cav-ernous, with high rates of flow.

Source Water Protection Area (SWPA)means the area delineated by the statefor a public water supply system (PWS)or including numerous PWSs, whetherthe source is ground water or surfacewater or both, as part of the statesource water assessment program(SWAP) approved by EPA under sec-tion 1453 of the Safe Drinking WaterAct.

Species means species, subspecies,population stocks, or distinctvertebrate populations.

Terrestrial ecological community with alimited range means a non-aquatic ornon-aquatic dependent ecological com-munity that covers less than five (5)acres.

Terrestrial species with a limited rangemeans a non-aquatic or non-aquatic de-pendent animal or plant species thathas a range of no more than five (5)acres.

Threatened and endangered species(T&E) means an animal or plant spe-cies that has been listed and is pro-tected under the Endangered SpeciesAct of 1973, as amended (ESA73) (16U.S.C. 1531 et seq.). ‘‘Endangered spe-cies’’ is defined as ‘‘any species whichis in danger of extinction throughoutall or a significant portion of itsrange’’ (16 U.S.C. 1532). ‘‘Threatenedspecies’’ is defined as ‘‘any specieswhich is likely to become an endan-gered species within the foreseeable fu-ture throughout all or a significantportion of its range’’ (16 U.S.C. 1532).

Transient Non-community Water System(TNCWS) means a public water systemthat does not regularly serve at least25 of the same persons over six monthsper year. This type of water systemserves a transient population found atrest stops, campgrounds, restaurants,and parks with their own source ofwater.


130

49 CFR Ch. I (10–1–01 Edition)§ 195.8

Wellhead Protection Area (WHPA)means the surface and subsurface areasurrounding a well or well field thatsupplies a public water system throughwhich contaminants are likely to passand eventually reach the water well orwell field.

Western Hemisphere Shorebird ReserveNetwork (WHSRN) site means an areathat contains migratory shorebird con-centrations and has been designated asa hemispheric reserve, internationalreserve, regional reserve, or endan-gered species reserve. Hemispheric re-serves host at least 500,000 shorebirdsannually or 30% of a species flywaypopulation. International reserves host100,000 shorebirds annually or 15% of aspecies flyway population. Regional re-serves host 20,000 shorebirds annuallyor 5% of a species flyway population.Endangered species reserves are crit-ical to the survival of endangered spe-cies and no minimum number of birdsis required.

[Amdt. 195–71, 65 FR 80544, Dec. 21, 2000]

§ 195.8 Transportation of hazardousliquid or carbon dioxide in pipe-lines constructed with other thansteel pipe.

No person may transport any haz-ardous liquid or carbon dioxide througha pipe that is constructed after October1, 1970, for hazardous liquids or afterJuly 12, 1991 for carbon dioxide of ma-terial other than steel unless the per-son has notified the Administrator inwriting at least 90 days before thetransportation is to begin. The noticemust state whether carbon dioxide or ahazardous liquid is to be transportedand the chemical name, common name,properties and characteristics of thehazardous liquid to be transported andthe material used in construction ofthe pipeline. If the Administrator de-termines that the transportation of thehazardous liquid or carbon dioxide inthe manner proposed would be undulyhazardous, he will, within 90 days afterreceipt of the notice, order the personthat gave the notice, in writing, not totransport the hazardous liquid or car-bon dioxide in the proposed manneruntil further notice.

[Amdt. 195–45, 56 FR 26925, June 12, 1991, asamended by Amdt. 195–50, 59 FR 17281, Apr.12, 1994]

§ 195.9 Outer continental shelf pipe-lines.

Operators of transportation pipelineson the Outer Continental Shelf mustidentify on all their respective pipe-lines the specific points at which oper-ating responsibility transfers to a pro-ducing operator. For those instances inwhich the transfer points are not iden-tifiable by a durable marking, each op-erator will have until September 15,1998 to identify the transfer points. If itis not practicable to durably mark atransfer point and the transfer point islocated above water, the operator mustdepict the transfer point on a sche-matic maintained near the transferpoint. If a transfer point is locatedsubsea, the operator must identify thetransfer point on a schematic whichmust be maintained at the nearest up-stream facility and provided to RSPAupon request. For those cases in whichadjoining operators have not agreed ona transfer point by September 15, 1998the Regional Director and the MMSRegional Supervisor will make a jointdetermination of the transfer point.

[Amdt. 195–59, 62 FR 61695, Nov. 19, 1997]

§ 195.10 Responsibility of operator forcompliance with this part.

An operator may make arrangementswith another person for the perform-ance of any action required by thispart. However, the operator is notthereby relieved from the responsi-bility for compliance with any require-ment of this part.

Subpart B—Reporting Accidentsand Safety-Related Conditions

§ 195.50 Reporting accidents.An accident report is required for

each failure in a pipeline system sub-ject to this part in which there is a re-lease of the hazardous liquid or carbondioxide transported resulting in any ofthe following:

(a) Explosion or fire not inten-tionally set by the operator.

(b) Loss of 50 or more barrels (8 ormore cubic meters) of hazardous liquidor carbon dioxide.

(c) Escape to the atmosphere of morethan 5 barrels (0.8 cubic meters) a dayof highly volatile liquids.


131


(d) Death of any person.(e) Bodily harm to any person result-

ing in one or more of the following:(1) Loss of consciousness.(2) Necessity to carry the person

from the scene.(3) Necessity for medical treatment.(4) Disability which prevents the dis-

charge of normal duties or the pursuitof normal activities beyond the day ofthe accident.

(f) Estimated property damage, in-cluding cost of clean-up and recovery,value of lost product, and damage tothe property of the operator or others,or both, exceeding $50,000.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended by Amdt. 195–39, 53 FR 24950, July 1,1988; Amdt. 195–45, 56 FR 26925, June 12, 1991;Amdt. 195–52, 59 FR 33396, June 28, 1994;Amdt. 195–63, 63 FR 37506, July 13, 1998]

§ 195.52 Telephonic notice of certainaccidents.

(a) At the earliest practicable mo-ment following discovery of a releaseof the hazardous liquid or carbon diox-ide transported resulting in an eventdescribed in § 195.50, the operator of thesystem shall give notice, in accordancewith paragraph (b) of this section, ofany failure that:

(1) Caused a death or a personal in-jury requiring hospitalization;

(2) Resulted in either a fire or explo-sion not intentionally set by the oper-ator;

(3) Caused estimated property dam-age, including cost of cleanup and re-covery, value of lost product, and dam-age to the property of the operator orothers, or both, exceeding $50,000;

(4) Resulted in pollution of anystream, river, lake, reservoir, or othersimilar body of water that violated ap-plicable water quality standards,caused a discoloration of the surface ofthe water or adjoining shoreline, or de-posited a sludge or emulsion beneaththe surface of the water or upon adjoin-ing shorelines; or

(5) In the judgment of the operatorwas significant even though it did notmeet the criteria of any other para-graph of this section.

(b) Reports made under paragraph (a)of this section are made by telephoneto 800–424–8802 (in Washington, DC 267–

2675) and must include the following in-formation:

(1) Name and address of the operator.(2) Name and telephone number of

the reporter.(3) The location of the failure.(4) The time of the failure.(5) The fatalities and personal inju-

ries, if any.(6) All other significant facts known

by the operator that are relevant tothe cause of the failure or extent of thedamages.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended by Amdt. 195–23, 47 FR 32720, July29, 1982; Amdt. 195–44, 54 FR 40878, Oct. 4,1989; Amdt. 195–45, 56 FR 26925, June 12, 1991;Amdt. 195–52, 59 FR 33396, June 28, 1994]

§ 195.54 Accident reports.(a) Each operator that experiences an

accident that is required to be reportedunder § 195.50 shall as soon as prac-ticable, but not later than 30 days afterdiscovery of the accident, prepare andfile an accident report on DOT Form7000–1, or a facsimile.

(b) Whenever an operator receivesany changes in the information re-ported or additions to the original re-port on DOT Form 7000–1, it shall file asupplemental report within 30 days.

[Amdt. 195–39, 53 FR 24950, July 1, 1988]

§ 195.55 Reporting safety-related con-ditions.

(a) Except as provided in paragraph(b) of this section, each operator shallreport in accordance with § 195.56 theexistence of any of the following safe-ty-related conditions involving pipe-lines in service:

(1) General corrosion that has re-duced the wall thickness to less thanthat required for the maximum oper-ating pressure, and localized corrosionpitting to a degree where leakagemight result.

(2) Unintended movement or abnor-mal loading of a pipeline by environ-mental causes, such as an earthquake,landslide, or flood, that impairs itsserviceability.

(3) Any material defect or physicaldamage that impairs the serviceabilityof a pipeline.

(4) Any malfunction or operatingerror that causes the pressure of a


132

49 CFR Ch. I (10–1–01 Edition)§ 195.56

pipeline to rise above 110 percent of itsmaximum operating pressure.

(5) A leak in a pipeline that con-stitutes an emergency.

(6) Any safety-related condition thatcould lead to an imminent hazard andcauses (either directly or indirectly byremedial action of the operator), forpurposes other than abandonment, a 20percent or more reduction in operatingpressure or shutdown of operation of apipeline.

(b) A report is not required for anysafety-related condition that—

(1) Exists on a pipeline that is morethan 220 yards (200 meters) from anybuilding intended for human occupancyor outdoor place of assembly, exceptthat reports are required for conditionswithin the right-of-way of an activerailroad, paved road, street, or high-way, or that occur offshore or at on-shore locations where a loss of haz-ardous liquid could reasonably be ex-pected to pollute any stream, river,lake, reservoir, or other body of water;

(2) Is an accident that is required tobe reported under § 195.50 or results insuch an accident before the deadlinefor filing the safety-related conditionreport; or

(3) Is corrected by repair or replace-ment in accordance with applicablesafety standards before the deadline forfiling the safety-related condition re-port, except that reports are requiredfor all conditions under paragraph(a)(1) of this section other than local-ized corrosion pitting on an effectivelycoated and cathodically protected pipe-line.

[Amdt. 195–39, 53 FR 24950, July 1, 1988; 53 FR29800, Aug. 8, 1988, as amended by Amdt. 195–63, 63 FR 37506, July 13, 1998]

§ 195.56 Filing safety-related conditionreports.

(a) Each report of a safety-relatedcondition under § 195.55(a) must be filed(received by the Administrator) inwriting within 5 working days (not in-cluding Saturdays, Sundays, or Federalholidays) after the day a representativeof the operator first determines thatthe condition exists, but not later than10 working days after the day a rep-resentative of the operator discoversthe condition. Separate conditions maybe described in a single report if they

are closely related. To file a report byfacsimile (fax), dial (202) 366–7128.

(b) The report must be headed ‘‘Safe-ty-Related Condition Report’’ and pro-vide the following information:

(1) Name and principal address of op-erator.

(2) Date of report.(3) Name, job title, and business tele-

phone number of person submitting thereport.

(4) Name, job title, and business tele-phone number of person who deter-mined that the condition exists.

(5) Date condition was discovered anddate condition was first determined toexist.

(6) Location of condition, with ref-erence to the State (and town, city, orcounty) or offshore site, and as appro-priate nearest street address, offshoreplatform, survey station number, mile-post, landmark, or name of pipeline.

(7) Description of the condition, in-cluding circumstances leading to itsdiscovery, any significant effects of thecondition on safety, and the name ofthe commodity transported or stored.

(8) The corrective action taken (in-cluding reduction of pressure or shut-down) before the report is submittedand the planned follow-up or futurecorrective action, including the antici-pated schedule for starting and con-cluding such action.

[Amdt. 195–39, 53 FR 24950, July 1, 1988; 53 FR29800, Aug. 8, 1988, as amended by Amdt. 195–42, 54 FR 32344, Aug. 7, 1989; Amdt. 195–44, 54FR 40878, Oct. 4, 1989; Amdt. 195–50, 59 FR17281, Apr. 12, 1994; Amdt. 195–61, 63 FR 7723,Feb. 17, 1998]

§ 195.57 Filing offshore pipeline condi-tion reports.

(a) Each operator shall, within 60days after completion of the inspectionof all its underwater pipelines subjectto § 195.413(a), report the following in-formation:

(1) Name and principal address of op-erator.

(2) Date of report.(3) Name, job title, and business tele-

phone number of person submitting thereport.

(4) Total number of miles (kilo-meters) of pipeline inspected.


133


(5) Length and date of installation ofeach exposed pipeline segment, and lo-cation; including, if available, the loca-tion according to the Minerals Manage-ment Service or state offshore area andblock number tract.

(6) Length and date of installation ofeach pipeline segment, if different froma pipeline segment identified underparagraph (a)(5) of this section, that isa hazard to navigation, and the loca-tion; including, if available, the loca-tion according to the Minerals Manage-ment Service or state offshore area andblock number tract.

(b) The report shall be mailed to theInformation Officer, Research and Spe-cial Programs Administration, Depart-ment of Transportation, 400 SeventhStreet, SW., Washington, DC 20590.

[Amdt. 195–47, 56 FR 63771, Dec. 5, 1991, asamended by Amdt. 195–63, 63 FR 37506, July13, 1998]

§ 195.58 Address for written reports.Each written report required by this

subpart must be made to the Informa-tion Resources Manager, Office of Pipe-line Safety, Research and Special Pro-grams Administration, U.S. Depart-ment of Transportation, Room 2335, 400Seventh Street SW., Washington DC20590. However, accident reports forintrastate pipelines subject to the ju-risdiction of a State agency pursuantto a certification under the pipelinesafety laws (49 U.S.C. 60101 et seq.) maybe submitted in duplicate to that Stateagency if the regulations of that agen-cy require submission of these reportsand provide for further transmittal ofone copy within 10 days of receipt tothe Information Resources Manager.Safety-related condition reports re-quired by § 195.55 for intrastate pipe-lines must be submitted concurrentlyto the State agency, and if that agencyacts as an agent of the Secretary withrespect to interstate pipelines, safety-related condition reports for thesepipelines must be submitted concur-rently to that agency.

[Amdt. 195–55, 61 FR 18518, Apr. 26, 1996]

§ 195.59 Abandoned underwater facili-ties report.

For each abandoned offshore pipelinefacility or each abandoned onshore

pipeline facility that crosses over,under or through a commercially navi-gable waterway, the last operator ofthat facility must file a report uponabandonment of that facility.

(a) The preferred method to submitdata on pipeline facilities abandonedafter October 10, 2000 is to the NationalPipeline Mapping System (NPMS) inaccordance with the NPMS ‘‘Standardsfor Pipeline and Liquefied Natural GasOperator Submissions.’’ To obtain acopy of the NPMS Standards, pleaserefer to the NPMS homepage atwww.npms.rspa.dot.gov or contact theNPMS National Repository at 703–317–3073. A digital data format is preferred,but hard copy submissions are accept-able if they comply with the NPMSStandards. In addition to the NPMS-re-quired attributes, operators must sub-mit the date of abandonment, diame-ter, method of abandonment, and cer-tification that, to the best of the oper-ator’s knowledge, all of the reasonablyavailable information requested wasprovided and, to the best of the opera-tor’s knowledge, the abandonment wascompleted in accordance with applica-ble laws. Refer to the NPMS Standardsfor details in preparing your data forsubmission. The NPMS Standards alsoinclude details of how to submit data.Alternatively, operators may submitreports by mail, fax or e-mail to the In-formation Officer, Research and Spe-cial Programs Administration, Depart-ment of Transportation, Room 7128, 400Seventh Street, SW, Washington DC20590; fax (202) 366–4566; e-mail,[email protected]. The informa-tion in the report must contain all rea-sonably available information relatedto the facility, including informationin the possession of a third party. Thereport must contain the location, size,date, method of abandonment, and acertification that the facility has beenabandoned in accordance with all ap-plicable laws.

(b) Data on pipeline facilities aban-doned before October 10, 2000 must befiled by before April 10, 2001. Operatorsmay submit reports by mail, fax or e-mail to the Information Officer, Re-search and Special Programs Adminis-tration, Department of Transportation,Room 7128, 400 Seventh Street, SW,Washington DC 20590; fax (202) 366–4566;


134

49 CFR Ch. I (10–1–01 Edition)§ 195.60

e-mail, [email protected]. Theinformation in the report must containall reasonably available informationrelated to the facility, including infor-mation in the possession of a thirdparty. The report must contain the lo-cation, size, date, method of abandon-ment, and a certification that the fa-cility has been abandoned in accord-ance with all applicable laws.

[Amdt. 195–69, 65 FR 54444, Sept. 8, 2000]

§ 195.60 Operator assistance in inves-tigation.

If the Department of Transportationinvestigates an accident, the operatorinvolved shall make available to therepresentative of the Department allrecords and information that in anyway pertain to the accident, and shallafford all reasonable assistance in theinvestigation of the accident.

§ 195.62 Supplies of accident reportDOT Form 7000–1.

Each operator shall maintain an ade-quate supply of forms that are a fac-simile of DOT Form 7000–1 to enable itto promptly report accidents. The De-partment will, upon request, furnishspecimen copies of the form. Requestsshould be addressed to the InformationResources Manager, Office of PipelineSafety, Department of Transportation,Washington, DC 20590.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended at 47 FR 32720, July 29, 1982]

§ 195.63 OMB control number assignedto information collection.

The control number assigned by theOffice of Management and Budget tothe hazardous liquid pipeline informa-tion collection requirements of thispart pursuant to the Paperwork Reduc-tion Act of 1980 is 2137–0047.

[Amdt. 195–34, 50 FR 34474, Aug. 26, 1985]

Subpart C—Design Requirements

§ 195.100 Scope.This subpart prescribes minimum de-

sign requirements for new pipeline sys-tems constructed with steel pipe andfor relocating, replacing, or otherwisechanging existing systems constructedwith steel pipe. However, it does not

apply to the movement of line pipecovered by § 195.424.

§ 195.101 Qualifying metallic compo-nents other than pipe.

Notwithstanding any requirement ofthe subpart which incorporates by ref-erence an edition of a document listedin § 195.3, a metallic component otherthan pipe manufactured in accordancewith any other edition of that docu-ment is qualified for use if—

(a) It can be shown through visual in-spection of the cleaned component thatno defect exists which might impairthe strength or tightness of the compo-nent: and

(b) The edition of the documentunder which the component was manu-factured has equal or more stringentrequirements for the following as anedition of that document currently orpreviously listed in § 195.3:

(1) Pressure testing;(2) Materials; and(3) Pressure and temperature ratings.

[Amdt. 195–28, 48 FR 30639, July 5, 1983]

§ 195.102 Design temperature.

(a) Material for components of thesystem must be chosen for the tem-perature environment in which thecomponents will be used so that thepipeline will maintain its structuralintegrity.

(b) Components of carbon dioxidepipelines that are subject to low tem-peratures during normal operation be-cause of rapid pressure reduction orduring the initial fill of the line mustbe made of materials that are suitablefor those low temperatures.

[Admt. 195–45, 56 FR 26925, June 12, 1991]

§ 195.104 Variations in pressure.

If, within a pipeline system, two ormore components are to be connectedat a place where one will operate at ahigher pressure than another, the sys-tem must be designed so that any com-ponent operating at the lower pressurewill not be overstressed.

§ 195.106 Internal design pressure.

(a) Internal design pressure for thepipe in a pipeline is determined in ac-cordance with the following formula:


135


P=(2 St/D)×E×F

P=Internal design pressure in p.s.i.(kPa) gage.

S=Yield strength in pounds persquare inch (kPa) determined in ac-cordance with paragraph (b) of thissection.

t=Nominal wall thickness of the pipein inches (millimeters). If this isunknown, it is determined in ac-cordance with paragraph (c) of thissection.

D=Nominal outside diameter of thepipe in inches (millimeters).

E=Seam joint factor determined inaccordance with paragraph (e) ofthis section.

F=A design factor of 0.72, except thata design factor of 0.60 is used forpipe, including risers, on a platformlocated offshore or on a platform ininland navigable waters, and 0.54 isused for pipe that has been sub-jected to cold expansion to meetthe specified minimum yieldstrength and is subsequently heat-ed, other than by welding or stressrelieving as a part of welding, to atemperature higher than 900° F(482° C) for any period of time orover 600° F (316° C) for more than 1hour.

(b) The yield strength to be used indetermining the internal design pres-sure under paragraph (a) of this sectionis the specified minimum yieldstrength. If the specified minimumyield strength is not known, the yieldstrength to be used in the design for-mula is one of the following:

(1)(i) The yield strength determinedby performing all of the tensile tests ofAPI Specification 5L on randomly se-lected specimens with the followingnumber of tests:

Pipe size No. of tests

Less than 65⁄8 in (168 mm) nomi-nal outside diameter.

One test for each 200lengths.

6 5⁄8 in through 123⁄4 in (168 mmthrough 324 mm) nominal out-side diameter.


Larger than 123⁄4 in (324 mm)nominal outside diameter.


(ii) If the average yield-tensile ratioexceeds 0.85, the yield strength shall betaken as 24,000 p.s.i. (165,474 kPa). If theaverage yield-tensile ratio is 0.85 or

less, the yield strength of the pipe istaken as the lower of the following:

(A) Eighty percent of the averageyield strength determined by the ten-sile tests.

(B) The lowest yield strength deter-mined by the tensile tests.

(2) If the pipe is not tensile tested asprovided in paragraph (b) of this sec-tion, the yield strength shall be takenas 24,000 p.s.i. (165,474 kPa).

(c) If the nominal wall thickness tobe used in determining internal designpressure under paragraph (a) of thissection is not known, it is determinedby measuring the thickness of eachpiece of pipe at quarter points on oneend. However, if the pipe is of uniformgrade, size, and thickness, only 10 indi-vidual lengths or 5 percent of alllengths, whichever is greater, need bemeasured. The thickness of the lengthsthat are not measured must be verifiedby applying a gage set to the minimumthickness found by the measurement.The nominal wall thickness to be usedis the next wall thickness found incommercial specifications that isbelow the average of all the measure-ments taken. However, the nominalwall thickness may not be more than1.14 times the smallest measurementtaken on pipe that is less than 20inches (508 mm) nominal outside di-ameter, nor more than 1.11 times thesmallest measurement taken on pipethat is 20 inches (508 mm) or more innominal outside diameter.

(d) The minimum wall thickness ofthe pipe may not be less than 87.5 per-cent of the value used for nominal wallthickness in determining the internaldesign pressure under paragraph (a) ofthis section. In addition, the antici-pated external loads and external pres-sures that are concurrent with internalpressure must be considered in accord-ance with §§ 195.108 and 195.110 and,after determining the internal designpressure, the nominal wall thicknessmust be increased as necessary to com-pensate for these concurrent loads andpressures.

(e) The seam joint factor used inparagraph (a) of this section is deter-mined in accordance with the followingtable:


136

49 CFR Ch. I (10–1–01 Edition)§ 195.108

Specification Pipe classSeamjoint

factor

ASTM A53 .... Seamless .......................................... 1.00Electric resistance welded ................ 1.00Furnace lap welded .......................... 0.80Furnace butt welded ......................... 0.60

ASTM A106 .. Seamless .......................................... 1.00ASTM A 333/

A 333M.Seamless .......................................... 1.00

Welded .............................................. 1.00ASTM A381 .. Double submerged arc welded ......... 1.00ASTM A671 .. Electric-fusion-welded ....................... 1.00ASTM A672 .. Electric-fusion-welded ....................... 1.00ASTM A691 .. Electric-fusion-welded ....................... 1.00API 5L ........... Seamless .......................................... 1.00

Electric resistance welded ................ 1.00Electric flash welded ......................... 1.00Submerged arc welded ..................... 1.00Furnace lap welded .......................... 0.80Furnace butt welded ......................... 0.60

The seam joint factor for pipe which isnot covered by this paragraph must beapproved by the Administrator.

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47FR 32721, July 29, 1982, as amended by Amdt.195–30, 49 FR 7569, Mar. 1, 1984; Amdt 195–37,51 FR 15335, Apr. 23, 1986; Amdt 195–40, 54 FR5628, Feb. 6, 1989; 58 FR 14524, Mar. 18, 1993;Amdt. 195–50, 59 FR 17281, Apr. 12, 1994; Amdt.195–52, 59 FR 33396, 33397, June 28, 1994; Amdt.195–63, 63 FR 37506, July 13, 1998]

§ 195.108 External pressure.Any external pressure that will be

exerted on the pipe must be providedfor in designing a pipeline system.

§ 195.110 External loads.(a) Anticipated external loads (e.g.),

earthquakes, vibration, thermal expan-sion, and contraction must be providedfor in designing a pipeline system. Inproviding for expansion and flexibility,section 419 of ASME/ANSI B31.4 mustbe followed.

(b) The pipe and other componentsmust be supported in such a way thatthe support does not cause excess local-ized stresses. In designing attachmentsto pipe, the added stress to the wall ofthe pipe must be computed and com-pensated for.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended at 58 FR 14524, Mar. 18, 1993]

§ 195.111 Fracture propagation.A carbon dioxide pipeline system

must be designed to mitigate the ef-fects of fracture propagation.

[Amdt. 195–45, 56 FR 26926, June 12, 1991]

§ 195.112 New pipe.Any new pipe installed in a pipeline

system must comply with the fol-lowing:

(a) The pipe must be made of steel ofthe carbon, low alloy-high strength, oralloy type that is able to withstand theinternal pressures and external loadsand pressures anticipated for the pipe-line system.

(b) The pipe must be made in accord-ance with a written pipe specificationthat sets forth the chemical require-ments for the pipe steel and mechan-ical tests for the pipe to provide pipesuitable for the use intended.

(c) Each length of pipe with a nomi-nal outside diameter of 4 1⁄2 in (114.3mm) or more must be marked on thepipe or pipe coating with the specifica-tion to which it was made, the speci-fied minimum yield strength or grade,and the pipe size. The marking must beapplied in a manner that does not dam-age the pipe or pipe coating and mustremain visible until the pipe is in-stalled.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended by Amdt. 195–52, 59 FR 33396, June28, 1994; Amdt. 195–63, 63 FR 37506, July 13,1998]

§ 195.114 Used pipe.Any used pipe installed in a pipeline

system must comply with § 195.112 (a)and (b) and the following:

(a) The pipe must be of a known spec-ification and the seam joint factormust be determined in accordance with§ 195.106(e). If the specified minimumyield strength or the wall thickness isnot known, it is determined in accord-ance with § 195.106 (b) or (c) as appro-priate.

(b) There may not be any:(1) Buckles;(2) Cracks, grooves, gouges, dents, or

other surface defects that exceed themaximum depth of such a defect per-mitted by the specification to whichthe pipe was manufactured; or

(3) Corroded areas where the remain-ing wall thickness is less than the min-imum thickness required by the toler-ances in the specification to which thepipe was manufactured.However, pipe that does not meet therequirements of paragraph (b)(3) of this


137


section may be used if the operatingpressure is reduced to be commensu-rate with the remaining wall thick-ness.

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47FR 32721, July 29, 1982]

§ 195.116 Valves.Each valve installed in a pipeline

system must comply with the fol-lowing:

(a) The valve must be of a sound en-gineering design.

(b) Materials subject to the internalpressure of the pipeline system, includ-ing welded and flanged ends, must becompatible with the pipe or fittings towhich the valve is attached.

(c) Each part of the valve that will bein contact with the carbon dioxide orhazardous liquid stream must be madeof materials that are compatible withcarbon dioxide or each hazardous liquidthat it is anticipated will flow throughthe pipeline system.

(d) Each valve must be bothhydrostatically shell tested andhydrostatically seat tested withoutleakage to at least the requirementsset forth in section 5 of API Standard6D.

(e) Each valve other than a checkvalve must be equipped with a meansfor clearly indicating the position ofthe valve (open, closed, etc.).

(f) Each valve must be marked on thebody or the nameplate, with at leastthe following:

(1) Manufacturer’s name or trade-mark.

(2) Class designation or the maximumworking pressure to which the valvemay be subjected.

(3) Body material designation (theend connection material, if more thanone type is used).

(4) Nominal valve size.

[Amdt. 195–22, 46 FR 38360, July 27, 1981 asamended by Amdt. 195–45, 56 FR 26926, June12, 1991]

§ 195.118 Fittings.(a) Butt-welding type fittings must

meet the marking, end preparation,and the bursting strength requirementsof ASME/ANSI B16.9 or MSS StandardPractice SP–75.

(b) There may not be any buckles,dents, cracks, gouges, or other defects

in the fitting that might reduce thestrength of the fitting.

(c) The fitting must be suitable forthe intended service and be at least asstrong as the pipe and other fittings inthe pipeline system to which it is at-tached.

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47FR 32721, July 29, 1982, as amended at 58 FR14524, Mar. 18, 1993]

§ 195.120 Passage of internal inspec-tion devices.

(a) Except as provided in paragraphs(b) and (c) of this section, each newpipeline and each line section of a pipe-line where the line pipe, valve, fittingor other line component is replaced;must be designed and constructed toaccommodate the passage of instru-mented internal inspection devices.

(b) This section does not apply to:(1) Manifolds;(2) Station piping such as at pump

stations, meter stations, or pressurereducing stations;

(3) Piping associated with tank farmsand other storage facilities;

(4) Cross-overs;(5) Sizes of pipe for which an instru-

mented internal inspection device isnot commercially available;

(6) Offshore pipelines, other thanmain lines 10 inches (254 millimeters)or greater in nominal diameter, thattransport liquids to onshore facilities;and

(7) Other piping that the Adminis-trator under § 190.9 of this chapter,finds in a particular case would be im-practicable to design and construct toaccommodate the passage of instru-mented internal inspection devices.

(c) An operator encountering emer-gencies, construction time constraintsand other unforeseen constructionproblems need not construct a new orreplacement segment of a pipeline tomeet paragraph (a) of this section, ifthe operator determines and docu-ments why an impracticability pro-hibits compliance with paragraph (a) ofthis section. Within 30 days after dis-covering the emergency or construc-tion problem the operator must peti-tion, under § 190.9 of this chapter, forapproval that design and constructionto accommodate passage of instru-mented internal inspection devices


138

49 CFR Ch. I (10–1–01 Edition)§ 195.122

would be impracticable. If the petitionis denied, within 1 year after the dateof the notice of the denial, the operatormust modify that segment to allowpassage of instrumented internal in-spection devices.

[Amdt. 195–50, 59 FR 17281, Apr. 12, 1994, asamended by Amdt. 195–63, 63 FR 37506, July13, 1998]

§ 195.122 Fabricated branch connec-tions.

Each pipeline system must be de-signed so that the addition of any fab-ricated branch connections will not re-duce the strength of the pipeline sys-tem.

§ 195.124 Closures.

Each closure to be installed in a pipe-line system must comply with theASME Boiler and Pressure Vessel Code,section VIII, Pressure Vessels, Division1, and must have pressure and tempera-ture ratings at least equal to those ofthe pipe to which the closure is at-tached.

§ 195.126 Flange connection.

Each component of a flange connec-tion must be compatible with eachother component and the connection asa unit must be suitable for the servicein which it is to be used.

§ 195.128 Station piping.

Any pipe to be installed in a stationthat is subject to system pressure mustmeet the applicable requirements ofthis subpart.

§ 195.130 Fabricated assemblies.

Each fabricated assembly to be in-stalled in a pipeline system must meetthe applicable requirements of thissubpart.

195.132 Design and construction ofaboveground breakout tanks.

(a) Each aboveground breakout tankmust be designed and constructed towithstand the internal pressure pro-duced by the hazardous liquid to bestored therein and any anticipated ex-ternal loads.

(b) For aboveground breakout tanksfirst placed in service after October 2,2000, compliance with paragraph (a) ofthis section requires one of the fol-lowing:

(1) Shop-fabricated, vertical, cylin-drical, closed top, welded steel tankswith nominal capacities of 90 to 750barrels (14.3 to 119.2 m 3) and with inter-nal vapor space pressures that are ap-proximately atmospheric must be de-signed and constructed in accordancewith API Specification 12F.

(2) Welded, low-pressure (i.e., inter-nal vapor space pressure not greaterthan 15 psig (103.4 kPa)), carbon steeltanks that have wall shapes that canbe generated by a single vertical axis ofrevolution must be designed and con-structed in accordance with API Stand-ard 620.

(3) Vertical, cylindrical, welded steeltanks with internal pressures at thetank top approximating atmosphericpressures (i.e., internal vapor spacepressures not greater than 2.5 psig (17.2kPa), or not greater than the pressuredeveloped by the weight of the tankroof) must be designed and constructedin accordance with API Standard 650.

(4) High pressure steel tanks (i.e., in-ternal gas or vapor space pressuresgreater than 15 psig (103.4 kPa)) with anominal capacity of 2000 gallons (7571liters) or more of liquefied petroleumgas (LPG) must be designed and con-structed in accordance with API Stand-ard 2510.

[Amdt. 195–66, 64 FR 15935, Apr. 2, 1999]

§ 195.134 CPM leak detection.

This section applies to each haz-ardous liquid pipeline transporting liq-uid in single phase (without gas in theliquid). On such systems, each newcomputational pipeline monitoring(CPM) leak detection system and eachreplaced component of an existing CPMsystem must comply with section 4.2 ofAPI 1130 in its design and with anyother design criteria addressed in API1130 for components of the CPM leakdetection system.

[Amdt. 195–62, 63 FR 36376, July 6, 1998]


139


Subpart D—Construction§ 195.200 Scope.

This subpart prescribes minimum re-quirements for constructing new pipe-line systems with steel pipe, and for re-locating, replacing, or otherwisechanging existing pipeline systemsthat are constructed with steel pipe.However, this subpart does not applyto the movement of pipe covered by§ 195.424.

§ 195.202 Compliance with specifica-tions or standards.

Each pipeline system must be con-structed in accordance with com-prehensive written specifications orstandards that are consistent with therequirements of this part.

§ 195.204 Inspection—general.Inspection must be provided to en-

sure the installation of pipe or pipelinesystems in accordance with the re-quirements of this subpart. No personmay be used to perform inspections un-less that person has been trained and isqualified in the phase of constructionto be inspected.


§ 195.205 Repair, alteration and recon-struction of aboveground breakouttanks that have been in service.

(a) Aboveground breakout tanks thathave been repaired, altered, or recon-structed and returned to service mustbe capable of withstanding the internalpressure produced by the hazardous liq-uid to be stored therein and any antici-pated external loads.

(b) After October 2, 2000, compliancewith paragraph (a) of this section re-quires the following for the tanks spec-ified:

(1) For tanks designed for approxi-mately atmospheric pressure con-structed of carbon and low alloy steel,welded or riveted, and non-refrigeratedand tanks built to API Standard 650 orits predecessor Standard 12C, repair, al-teration, and reconstruction must be inaccordance with API Standard 653.

(2) For tanks built to API Specifica-tion 12F or API Standard 620, the re-pair, alteration, and reconstruction

must be in accordance with the design,welding, examination, and material re-quirements of those respective stand-ards.

(3) For high pressure tanks built toAPI Standard 2510, repairs, alterations,and reconstruction must be in accord-ance with API 510.

[Amdt. 195–66, 64 FR 15935, Apr. 2, 1999]

§ 195.206 Material inspection.No pipe or other component may be

installed in a pipeline system unless ithas been visually inspected at the siteof installation to ensure that it is notdamaged in a manner that could impairits strength or reduce its service-ability.

§ 195.208 Welding of supports andbraces.

Supports or braces may not be weld-ed directly to pipe that will be oper-ated at a pressure of more than 100p.s.i. (689 kPa) gage.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended by Amdt. 195–63, 63 FR 37506, July13, 1998]

§ 195.210 Pipeline location.(a) Pipeline right-of-way must be se-

lected to avoid, as far as practicable,areas containing private dwellings, in-dustrial buildings, and places of publicassembly.

(b) No pipeline may be located within50 feet (15 meters) of any private dwell-ing, or any industrial building or placeof public assembly in which personswork, congregate, or assemble, unlessit is provided with at least 12 inches(305 millimeters) of cover in addition tothat prescribed in § 195.248.


§ 195.212 Bending of pipe.(a) Pipe must not have a wrinkle

bend.(b) Each field bend must comply with

the following:(1) A bend must not impair the serv-

iceability of the pipe.(2) Each bend must have a smooth

contour and be free from buckling,cracks, or any other mechanical dam-age.


140

49 CFR Ch. I (10–1–01 Edition)§ 195.214

(3) On pipe containing a longitudinalweld, the longitudinal weld must be asnear as practicable to the neutral axisof the bend unless—

(i) The bend is made with an internalbending mandrel; or

(ii) The pipe is 123⁄4 in (324 mm) orless nominal outside diameter or has adiameter to wall thickness ratio lessthan 70.

(c) Each circumferential weld whichis located where the stress during bend-ing causes a permanent deformation inthe pipe must be nondestructively test-ed either before or after the bendingprocess.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended by Amdt. 195–52, 59 FR 33396, June28, 1994; Amdt. 195–63, 63 FR 37506, July 13,1998]

§ 195.214 Welding: General.

(a) Welding must be performed by aqualified welder in accordance withwelding procedures qualified toproduce welds meeting the require-ments of this subpart. The quality ofthe test welds used to qualify the pro-cedure shall be determined by destruc-tive testing.

(b) Each welding procedure must berecorded in detail, including the resultsof the qualifying tests. This recordmust be retained and followed when-ever the procedure is used.

[Amdt. 195–38, 51 FR 20297, June 4, 1986]

§ 195.216 Welding: Miter joints.

A miter joint is not permitted (notincluding deflections up to 3 degreesthat are caused by misalignment).

§ 195.222 Welders: Qualification ofwelders.

Each welder must be qualified in ac-cordance with section 3 of API Stand-ard 1104 or section IX of the ASMEBoiler and Pressure Vessel Code, exceptthat a welder qualified under an earlieredition than listed in § 195.3 may weldbut may not requalify under that ear-lier edition.

[Amdt. 195–32, 49 FR 36860, Sept. 20, 1984, asamended by Amdt. 195–38, 51 FR 20297, June4, 1986]

§ 195.224 Welding: Weather.

Welding must be protected fromweather conditions that would impairthe quality of the completed weld.

§ 195.226 Welding: Arc burns.

(a) Each arc burn must be repaired.(b) An arc burn may be repaired by

completely removing the notch bygrinding, if the grinding does not re-duce the remaining wall thickness toless than the minimum thickness re-quired by the tolerances in the speci-fication to which the pipe is manufac-tured. If a notch is not repairable bygrinding, a cylinder of the pipe con-taining the entire notch must be re-moved.

(c) A ground may not be welded tothe pipe or fitting that is being welded.

§ 195.228 Welds and welding inspec-tion: Standards of acceptability.

(a) Each weld and welding must beinspected to insure compliance withthe requirements of this subpart. Vis-ual inspection must be supplementedby nondestructive testing.

(b) The acceptability of a weld is de-termined according to the standards insection 6 of API Standard 1104. How-ever, if a girth weld is unacceptableunder those standards for a reasonother than a crack, and if the Appendixto API Standard 1104 applies to theweld, the acceptability of the weld maybe determined under that appendix.


§ 195.230 Welds: Repair or removal ofdefects.

(a) Each weld that is unacceptableunder § 195.228 must be removed or re-paired. Except for welds on an offshorepipeline being installed from a pipelayvessel, a weld must be removed if it hasa crack that is more than 8 percent ofthe weld length.

(b) Each weld that is repaired musthave the defect removed down to soundmetal and the segment to be repairedmust be preheated if conditions existwhich would adversely affect the qual-ity of the weld repair. After repair, thesegment of the weld that was repaired


141


must be inspected to ensure its accept-ability.

(c) Repair of a crack, or of any defectin a previously repaired area must bein accordance with written weld repairprocedures that have been qualifiedunder § 195.214. Repair procedures mustprovide that the minimum mechanicalproperties specified for the weldingprocedure used to make the originalweld are met upon completion of thefinal weld repair.

[Amdt. 195–29, 48 FR 48674, Oct. 20, 1983]

§ 195.234 Welds: Nondestructive test-ing.

(a) A weld may be nondestructivelytested by any process that will clearlyindicate any defects that may affectthe integrity of the weld.

(b) Any nondestructive testing ofwelds must be performed—

(1) In accordance with a written setof procedures for nondestructive test-ing; and

(2) With personnel that have beentrained in the established proceduresand in the use of the equipment em-ployed in the testing.

(c) Procedures for the proper inter-pretation of each weld inspection mustbe established to ensure the accept-ability of the weld under § 195.228.

(d) During construction, at least 10percent of the girth welds made byeach welder during each welding daymust be nondestructively tested overthe entire circumference of the weld.

(e) All girth welds installed each dayin the following locations must be non-destructively tested over their entirecircumference, except that when non-destructive testing is impracticable fora girth weld, it need not be tested ifthe number of girth welds for whichtesting is impracticable does not ex-ceed 10 percent of the girth welds in-stalled that day:

(1) At any onshore location where aloss of hazardous liquid could reason-ably be expected to pollute any stream,river, lake, reservoir, or other body ofwater, and any offshore area;

(2) Within railroad or public roadrights-of-way;

(3) At overhead road crossings andwithin tunnels;

(4) Within the limits of any incor-porated subdivision of a State govern-ment; and

(5) Within populated areas, including,but not limited to, residential subdivi-sions, shopping centers, schools, des-ignated commercial areas, industrialfacilities, public institutions, andplaces of public assembly.

(f) When installing used pipe, 100 per-cent of the old girth welds must benondestructively tested.

(g) At pipeline tie-ins, including tie-ins of replacement sections, 100 percentof the girth welds must be nondestruc-tively tested.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended by Amdt. 195–35, 50 FR 37192, Sept.21, 1985; Amdt. 195–52, 59 FR 33397, June 28,1994]

§ 195.236 External corrosion protec-tion.

Each component in the pipeline sys-tem must be provided with protectionagainst external corrosion.

§ 195.238 External coating.(a) No pipeline system component

may be buried or submerged unlessthat component has an external protec-tive coating that—

(1) Is designed to mitigate corrosionof the buried or submerged component;

(2) Has sufficient adhesion to themetal surface to prevent underfilm mi-gration of moisture;

(3) Is sufficiently ductile to resistcracking;

(4) Has enough strength to resistdamage due to handling and soil stress;and

(5) Supports any supplemental ca-thodic protection.In addition, if an insulating-type coat-ing is used it must have low moistureabsorption and provide high electricalresistance.

(b) All pipe coating must be inspectedjust prior to lowering the pipe into theditch or submerging the pipe, and anydamage discovered must be repaired.

§ 195.242 Cathodic protection system.(a) A cathodic protection system

must be installed for all buried or sub-merged facilities to mitigate corrosionthat might result in structural failure.A test procedure must be developed to


142

49 CFR Ch. I (10–1–01 Edition)§ 195.244

determine whether adequate cathodicprotection has been achieved.

(b) A cathodic protection systemmust be installed not later than 1 yearafter completing the construction.

(c) For the bottoms of abovegroundbreakout tanks with greater than 500barrels (79.5 m 3) capacity built to APISpecification 12F, API Standard 620, orAPI Standard 650 (or its predecessorStandard 12C), the installation of a ca-thodic protection system under para-graph (a) of this section after October2, 2000, must be in accordance with APIRecommended Practice 651, unless theoperator notes in the procedural man-ual (§ 195.402(c)) why compliance withall or certain provisions of API Rec-ommended Practice 651 is not nec-essary for the safety of a particularbreakout tank.

(d) For the internal bottom of above-ground breakout tanks built to APISpecification 12F, API Standard 620, orAPI Standard 650 (or its predecessorStandard 12C), the installation of atank bottom lining after October 2,2000, must be in accordance with APIRecommended Practice 652, unless theoperator notes in the procedural man-ual (§ 195.402(c)) why compliance withall or certain provisions of API Rec-ommended Practice 652 is not nec-essary for the safety of a particularbreakout tank.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended by Amdt. 195–66, 64 FR 15935, Apr. 2,1999]

§ 195.244 Test leads.(a) Except for offshore pipelines, elec-

trical test leads used for corrosion con-trol or electrolysis testing must be in-stalled at intervals frequent enough toobtain electrical measurements indi-cating the adequacy of the cathodicprotection.

(b) Test leads must be installed asfollows:

(1) Enough looping or slack must beprovided to prevent test leads frombeing unduly stressed or broken duringbackfilling.

(2) Each lead must be attached to thepipe so as to prevent stress concentra-tion on the pipe.

(3) Each lead installed in a conduitmust be suitably insulated from theconduit.

§ 195.246 Installation of pipe in aditch.

(a) All pipe installed in a ditch mustbe installed in a manner that mini-mizes the introduction of secondarystresses and the possibility of damageto the pipe.

(b) Except for pipe in the Gulf ofMexico and its inlets, all offshore pipein water at least 3.7 m (12 ft) deep butnot more than 61 m (200 ft) deep, asmeasured from the mean low tide,must be installed so that the top of thepipe is below the natural bottom unlessthe pipe is supported by stanchions,held in place by anchors or heavy con-crete coating, or protected by an equiv-alent means.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended by Amdt. 195–52, 59 FR 33397, June28, 1994; 59 FR 36256, July 15, 1994]

§ 195.248 Cover over buried pipeline.

(a) Unless specifically exempted inthis subpart, all pipe must be buried sothat it is below the level of cultivation.Except as provided in paragraph (b) ofthis section, the pipe must be installedso that the cover between the top ofthe pipe and the ground level, road bed,river bottom, or sea bottom, as appli-cable, complies with the followingtable:

Location

Cover inches (millime-ters)

For normalexcavation

For rockexca-

vation 1

Industrial, commercial, and residential areas ........................................................................................... 36 (914) 30 (762)Crossings of inland bodies of water with a width of at least 100 ft (30 mm) 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 zone ...................................................................................................................... 48 (1219) 24 (610)Gulf of Mexico and its inlets and other offshore areas under water less than 12 ft (3.7 m) deep as

measured from the mean low tide ......................................................................................................... 36 (914) 18 (457)


143


Location

Cover inches (millime-ters)

For normalexcavation

For rockexca-

vation 1

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 andits inlets, less cover than the minimumrequired by paragraph (a) of this sec-tion and § 195.210 may be used if—

(1) It is impracticable to comply withthe minimum cover requirements; and

(2) Additional protection is providedthat is equivalent to the minimum re-quired cover.

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47FR 32721, July 29, 1982 as amended by Amdt.195–52, 59 FR 33397, June 28, 1994; 59 FR 36256,July 15, 1994; Amdt. 195–63, 63 FR 37506, July13, 1998]

§ 195.250 Clearance between pipe andunderground structures.

Any pipe installed underground musthave at least 12 inches (305 millime-ters) of clearance between the outsideof the pipe and the extremity of anyother underground structure, exceptthat for drainage tile the minimumclearance may be less than 12 inches(305 millimeters) but not less than 2inches (51 millimeters). However,where 12 inches (305 millimeters) ofclearance is impracticable, the clear-ance may be reduced if adequate provi-sions are made for corrosion control.


§ 195.252 Backfilling.Backfilling must be performed in a

manner that protects any pipe coatingand provides firm support for the pipe.

§ 195.254 Above ground components.(a) Any component may be installed

above ground in the following situa-tions, if the other applicable require-ments of this part are complied with:

(1) Overhead crossings of highways,railroads, or a body of water.

(2) Spans over ditches and gullies.(3) Scraper traps or block valves.(4) Areas under the direct control of

the operator.

(5) In any area inaccessible to thepublic.

(b) Each component covered by thissection must be protected from theforces exerted by the anticipated loads.

§ 195.256 Crossing of railroads andhighways.

The pipe at each railroad or highwaycrossing must be installed so as to ade-quately withstand the dynamic forcesexerted by anticipated traffic loads.

§ 195.258 Valves: General.(a) Each valve must be installed in a

location that is accessible to author-ized employees and that is protectedfrom damage or tampering.

(b) Each submerged valve located off-shore or in inland navigable watersmust be marked, or located by conven-tional survey techniques, to facilitatequick location when operation of thevalve is required.

§ 195.260 Valves: Location.A valve must be installed at each of

the following locations:(a) On the suction end and the dis-

charge end of a pump station in a man-ner that permits isolation of the pumpstation equipment in the event of anemergency.

(b) On each line entering or leaving abreakout storage tank area in a man-ner that permits isolation of the tankarea from other facilities.

(c) On each mainline at locationsalong the pipeline system that willminimize damage or pollution from ac-cidental hazardous liquid discharge, asappropriate for the terrain in opencountry, for offshore areas, or for popu-lated areas.

(d) On each lateral takeoff from atrunk line in a manner that permitsshutting off the lateral without inter-rupting the flow in the trunk line.

(e) On each side of a water crossingthat is more than 100 feet (30 meters)


144

49 CFR Ch. I (10–1–01 Edition)§ 195.262

wide from high-water mark to high-water mark unless the Administratorfinds in a particular case that valvesare not justified.

(f) On each side of a reservoir holdingwater for human consumption.

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47FR 32721, July 29, 1982; Amdt. 195–50, 59 FR17281, Apr. 12, 1994; Amdt. 195–63, 63 FR 37506,July 13, 1998]

§ 195.262 Pumping equipment.

(a) Adequate ventilation must be pro-vided in pump station buildings to pre-vent the accumulation of hazardous va-pors. Warning devices must be installedto warn of the presence of hazardousvapors in the pumping station building.

(b) The following must be provided ineach pump station:

(1) Safety devices that prevent over-pressuring of pumping equipment, in-cluding the auxiliary pumping equip-ment within the pumping station.

(2) A device for the emergency shut-down of each pumping station.

(3) If power is necessary to actuatethe safety devices, an auxiliary powersupply.

(c) Each safety device must be testedunder conditions approximating actualoperations and found to function prop-erly before the pumping station may beused.

(d) Except for offshore pipelines,pumping equipment must be installedon property that is under the control ofthe operator and at least 15.2 m (50 ft)from the boundary of the pump station.

(e) Adequate fire protection must beinstalled at each pump station. If thefire protection system installed re-quires the use of pumps, motive powermust be provided for those pumps thatis separate from the power that oper-ates the station.


§ 195.264 Impoundment, protectionagainst entry, normal/emergencyventing or pressure/vacuum relieffor aboveground breakout tanks.

(a) A means must be provided forcontaining hazardous liquids in theevent of spillage or failure of an above-ground breakout tank.

(b) After October 2, 2000, compliancewith paragraph (a) of this section re-quires the following for the above-ground breakout tanks specified:

(1) For tanks built to API Specifica-tion 12F, API Standard 620, and others(such as API Standard 650 or its prede-cessor Standard 12C), the installationof impoundment must be in accordancewith the following sections of NFPA 30:

(i) Impoundment around a breakouttank must be installed in accordancewith Section 2–3.4.3; and

(ii) Impoundment by drainage to a re-mote impounding area must be in-stalled in accordance with Section 2–3.4.2.

(2) For tanks built to API Standard2510, the installation of impoundmentmust be in accordance with Section 3or 9 of API Standard 2510.

(c) Aboveground breakout tank areasmust be adequately protected againstunauthorized entry.

(d) Normal/emergency relief ventingmust be provided for each atmosphericpressure breakout tank. Pressure/vacu-um-relieving devices must be providedfor each low-pressure and high-pressurebreakout tank.

(e) For normal/emergency relief vent-ing and pressure/vacuum-relieving de-vices installed on aboveground break-out tanks after October 2, 2000, compli-ance with paragraph (d) of this sectionrequires the following for the tanksspecified:

(1) Normal/emergency relief ventinginstalled on atmospheric pressuretanks built to API Specification 12Fmust be in accordance with Section 4,and Appendices B and C, of API Speci-fication 12F.

(2) Normal/emergency relief ventinginstalled on atmospheric pressuretanks (such as those built to APIStandard 650 or its predecessor Stand-ard 12C) must be in accordance withAPI Standard 2000.

(3) Pressure-relieving and emergencyvacuum-relieving devices installed onlow pressure tanks built to API Stand-ard 620 must be in accordance with Sec-tion 7 of API Standard 620 and its ref-erences to the normal and emergencyventing requirements in API Standard2000.

(4) Pressure and vacuum-relieving de-vices installed on high pressure tanks


145


built to API Standard 2510 must be inaccordance with Sections 5 or 9 of APIStandard 2510.

[Amdt. 195–66, 64 FR 15935, Apr. 2, 1999]

§ 195.266 Construction records.A complete record that shows the fol-

lowing must be maintained by the op-erator involved for the life of eachpipeline facility:

(a) The total number of girth weldsand the number nondestructively test-ed, including the number rejected andthe disposition of each rejected weld.

(b) The amount, location; and coverof each size of pipe installed.

(c) The location of each crossing ofanother pipeline.

(d) The location of each buried util-ity crossing.

(e) The location of each overheadcrossing.

(f) The location of each valve andcorrosion test station.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended by Amdt. 195–34, 50 FR 34474, Aug.26, 1985]

Subpart E—Pressure Testing

§ 195.300 Scope.This subpart prescribes minimum re-

quirements for the pressure testing ofsteel pipelines. However, this subpartdoes not apply to the movement of pipeunder § 195.424.

[Amdt. 195–51, 59 FR 29384, June 7, 1994]

§ 195.302 General requirements.(a) Except as otherwise provided in

this section and in § 195.305(b), no oper-ator may operate a pipeline unless ithas been pressure tested under thissubpart without leakage. In addition,no operator may return to service asegment of pipeline that has been re-placed, relocated, or otherwise changeduntil it has been pressure tested underthis subpart without leakage.

(b) Except for pipelines convertedunder § 195.5, the following pipelinesmay be operated without pressure test-ing under this subpart:

(1) Any hazardous liquid pipelinewhose maximum operating pressure is

established under § 195.406(a)(5) thatis—

(i) An interstate pipeline constructedbefore January 8, 1971;

(ii) An interstate offshore gatheringline constructed before August 1, 1977;

(iii) An intrastate pipeline con-structed before October 21, 1985; or

(iv) A low-stress pipeline constructedbefore August 11, 1994 that transportsHVL.

(2) Any carbon dioxide pipeline con-structed before July 12, 1991, that—

(i) Has its maximum operating pres-sure established under § 195.406(a)(5); or

(ii) Is located in a rural area as partof a production field distribution sys-tem.

(3) Any low-stress pipeline con-structed before August 11, 1994 thatdoes not transport HVL.

(4) Those portions of older hazardousliquid and carbon dioxide pipelines forwhich an operator has elected the risk-based alternative under § 195.303 andwhich are not required to be testedbased on the risk-based criteria.

(c) Except for pipelines that trans-port HVL onshore, low-stress pipelines,and pipelines covered under § 195.303,the following compliance deadlinesapply to pipelines under paragraphs(b)(1) and (b)(2)(i) of this section thathave not been pressure tested underthis subpart:

(1) Before December 7, 1998, for eachpipeline each operator shall—

(i) Plan and schedule testing accord-ing to this paragraph; or

(ii) Establish the pipeline’s maximumoperating pressure under § 195.406(a)(5).

(2) For pipelines scheduled for test-ing, each operator shall—

(i) Before December 7, 2000, pressuretest—

(A) Each pipeline identified by name,symbol, or otherwise that existingrecords show contains more than 50percent by mileage (length) of electricresistance welded pipe manufacturedbefore 1970; and

(B) At least 50 percent of the mileage(length) of all other pipelines; and


146

49 CFR Ch. I (10–1–01 Edition)§ 195.303

1 (See Appendix B, Table C).

(ii) Before December 7, 2003, pressuretest the remainder of the pipeline mile-age (length).

[Amdt. 195–51, 59 FR 29384, June 7, 1994, asamended by Amdt. 195–53, 59 FR 35471, July12, 1994; Amdt. 195–51B, 61 FR 43027, Aug. 20,1996; Amdt. 195–58, 62 FR 54592, Oct. 21, 1997;Amdt. 195–63, 63 FR 37506, July 13, 1998;Amdt. 195–65, 63 FR 59479, Nov. 4, 1998]

§ 195.303 Risk-based alternative topressure testing older hazardousliquid and carbon dioxide pipelines.

(a) An operator may elect to follow aprogram for testing a pipeline on risk-based criteria as an alternative to thepressure testing in § 195.302(b)(1)(i)–(iii)and § 195.302(b)(2)(i) of this subpart. Ap-pendix B provides guidance on how thisprogram will work. An operator elect-ing such a program shall assign a riskclassification to each pipeline segmentaccording to the indicators described inparagraph (b) of this section as follows:

(1) Risk Classification A if the loca-tion indicator is ranked as low or me-dium risk, the product and volume in-dicators are ranked as low risk, andthe probability of failure indicator isranked as low risk;

(2) Risk Classification C if the loca-tion indicator is ranked as high risk; or

(3) Risk Classification B.(b) An operator shall evaluate each

pipeline segment in the program ac-cording to the following indicators ofrisk:

(1) The location indicator is—(i) High risk if an area is non-rural or

environmentally sensitive 1; or(ii) Medium risk; or(iii) Low risk if an area is not high or

medium risk.(2) The product indicator is 1

(i) High risk if the product trans-ported is highly toxic or is both highlyvolatile and flammable;

(ii) Medium risk if the product trans-ported is flammable with a flashpointof less than 100° F, but not highly vola-tile; or

(iii) Low risk if the product trans-ported is not high or medium risk.

(3) The volume indicator is—(i) High risk if the line is at least 18

inches in nominal diameter;

(ii) Medium risk if the line is at least10 inches, but less than 18 inches, innominal diameter; or

(iii) Low risk if the line is not high ormedium risk.

(4) The probability of failure indi-cator is—

(i) High risk if the segment has expe-rienced more than three failures in thelast 10 years due to time-dependent de-fects (e.g., corrosion, gouges, or prob-lems developed during manufacture,construction or operation, etc.); or

(ii) Low risk if the segment has expe-rienced three failures or less in the last10 years due to time-dependent defects.

(c) The program under paragraph (a)of this section shall provide for pres-sure testing for a segment constructedof electric resistance-welded (ERW)pipe and lapwelded pipe manufacturedprior to 1970 susceptible to longitudinalseam failures as determined throughparagraph (d) of this section. The tim-ing of such pressure test may be deter-mined based on risk classifications dis-cussed under paragraph (b) of this sec-tion. For other segments, the programmay provide for use of a magnetic fluxleakage or ultrasonic internal inspec-tion survey as an alternative to pres-sure testing and, in the case of suchsegments in Risk Classification A, mayprovide for no additional measuresunder this subpart.

(d) All pre-1970 ERW pipe andlapwelded pipe is deemed susceptible tolongitudinal seam failures unless anengineering analysis shows otherwise.In conducting an engineering analysisan operator must consider the seam-re-lated leak history of the pipe and pipemanufacturing information as avail-able, which may include the pipesteel’s mechanical properties, includ-ing fracture toughness; the manufac-turing process and controls related toseam properties, including whether theERW process was high-frequency orlow-frequency, whether the weld seamwas heat treated, whether the seamwas inspected, the test pressure andduration during mill hydrotest; thequality control of the steel-makingprocess; and other factors pertinent toseam properties and quality.


147


(e) Pressure testing done under thissection must be conducted in accord-ance with this subpart. Except for seg-ments in Risk Classification B whichare not constructed with pre-1970 ERWpipe, water must be the test medium.

(f) An operator electing to follow aprogram under paragraph (a) must de-velop plans that include the method oftesting and a schedule for the testingby December 7, 1998. The compliancedeadlines for completion of testing areas shown in the table below:

§ 195.303—TEST DEADLINES

Pipeline Segment Risk classification Test deadline

Pre-1970 Pipe sus-ceptible to longi-tudinal seam fail-ures [defined in§ 195.303(c) &(d)].

C or B ...................A ...........................

12/7/200012/7/2002

All Other PipelineSegments.

C ...........................B ...........................A ...........................

12/7/200212/7//2004Additional testing

not required

(g) An operator must review the riskclassifications for those pipeline seg-ments which have not yet been testedunder paragraph (a) of this section orotherwise inspected under paragraph(c) of this section at intervals not toexceed 15 months. If the risk classifica-tion of an untested or uninspected seg-ment changes, an operator must takeappropriate action within two years, orestablish the maximum operating pres-sure under § 195.406(a)(5).

(h) An operator must maintainrecords establishing compliance withthis section, including recordsverifying the risk classifications, theplans and schedule for testing, the con-duct of the testing, and the review ofthe risk classifications.

(i) An operator may discontinue aprogram under this section only afterwritten notification to the Adminis-trator and approval, if needed, of aschedule for pressure testing.

[Amdt. 195–65, 63 FR 59480, Nov. 4, 1998]

§ 195.304 Test pressure.The test pressure for each pressure

test conducted under this subpart mustbe maintained throughout the part ofthe system being tested for at least 4continuous hours at a pressure equal to125 percent, or more, of the maximum

operating pressure and, in the case of apipeline that is not visually inspectedfor leakage during the test, for at leastan additional 4 continuous hours at apressure equal to 110 percent, or more,of the maximum operating pressure.

[Amdt. 195–51, 59 FR 29384, June 7, 1994. Re-designated by Amdt. 195–65, 63 FR 59480, Nov.4, 1998]

§ 195.305 Testing of components.

(a) Each pressure test under § 195.302must test all pipe and attached fit-tings, including components, unlessotherwise permitted by paragraph (b)of this section.

(b) A component, other than pipe,that is the only item being replaced oradded to the pipeline system need notbe hydrostatically tested under para-graph (a) of this section if the manu-facturer certifies that either—

(1) The component washydrostatically tested at the factory;or

(2) The component was manufacturedunder a quality control system that en-sures each component is at least equalin strength to a prototype that washydrostatically tested at the factory.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended by Amdt. 195–51, 59 FR 29385, June7, 1994; Amdt. 195–52, 59 FR 33397, June 28,1994. Redesignated by Amdt. 195–65, 63 FR59480, Nov. 4, 1998]

§ 195.306 Test medium.(a) Except as provided in paragraphs

(b), (c), and (d) of this section, watermust be used as the test medium.

(b) Except for offshore pipelines, liq-uid petroleum that does not vaporizerapidly may be used as the test me-dium if—

(1) The entire pipeline section undertest is outside of cities and other popu-lated areas;

(2) Each building within 300 feet (91meters) of the test section is unoccu-pied while the test pressure is equal toor greater than a pressure which pro-duces a hoop stress of 50 percent ofspecified minimum yield strength;

(3) The test section is kept under sur-veillance by regular patrols during thetest; and

(4) Continuous communication ismaintained along entire test section.


148

49 CFR Ch. I (10–1–01 Edition)§ 195.307

(c) Carbon dioxide pipelines may useinert gas or carbon dioxide as the testmedium if—

(1) The entire pipeline section undertest is outside of cities and other popu-lated areas;

(2) Each building within 300 feet (91meters) of the test section is unoccu-pied while the test pressure is equal toor greater than a pressure that pro-duces a hoop stress of 50 percent ofspecified minimum yield strength;

(3) The maximum hoop stress duringthe test does not exceed 80 percent ofspecified minimum yield strength;

(4) Continuous communication ismaintained along entire test section;and

(5) The pipe involved is new pipe hav-ing a longitudinal joint factor of 1.00.

(d) Air or inert gas may be used asthe test medium in low-stress pipe-lines.

[Amdt. 195–22, 46 FR 38360, July 27, 1991, asamended by Amdt. 195–45, 56 FR 26926, June12, 1991; Amdt. 195–51, 59 FR 29385, June 7,1994; Amdt. 195–53, 59 FR 35471, July 12, 1994;Amdt. 195–51A, 59 FR 41260, Aug. 11, 1994;Amdt. 195–63, 63 FR 37506, July 13, 1998]

§ 195.307 Pressure testing above-ground breakout tanks.

(a) For aboveground breakout tanksbuilt to API Specification 12F and firstplaced in service after October 2, 2000,pneumatic testing must be in accord-ance with section 5.3 of API Specifica-tion 12F.

(b) For aboveground breakout tanksbuilt to API Standard 620 and firstplaced in service after October 2, 2000,hydrostatic and pneumatic testingmust be in accordance with section 5.18of API Standard 620.

(c) For aboveground breakout tanksbuilt to API Standard 650 and firstplaced in service after October 2, 2000,hydrostatic and pneumatic testingmust be in accordance with section 5.3of API Standard 650.

(d) For aboveground atmosphericpressure breakout tanks constructed ofcarbon and low alloy steel, welded orriveted, and non-refrigerated and tanksbuilt to API Standard 650 or its prede-cessor Standard 12C that are returnedto service after October 2, 2000, the ne-cessity for the hydrostatic testing ofrepair, alteration, and reconstruction

is covered in section 10.3 of API Stand-ard 653.

(e) For aboveground breakout tanksbuilt to API Standard 2510 and firstplaced in service after October 2, 2000,pressure testing must be in accordancewith ASME Boiler and Pressure VesselCode, Section VIII, Division 1 or 2.

[Amdt. 195–66, 64 FR 15936, Apr. 2, 1999]

§ 195.308 Testing of tie-ins.Pipe associated with tie-ins must be

pressure tested, either with the sectionto be tied in or separately.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended by 195–51, 59 FR 29385, June 7, 1994]

§ 195.310 Records.(a) A record must be made of each

pressure test required by this subpart,and the record of the latest test mustbe retained as long as the facility test-ed is in use.

(b) The record required by paragraph(a) of this section must include:

(1) The pressure recording charts;(2) Test instrument calibration data;(3) The name of the operator, the

name of the person responsible formaking the test, and the name of thetest company used, if any;

(4) The date and time of the test;(5) The minimum test pressure;(6) The test medium;(7) A description of the facility tested

and the test apparatus;(8) An explanation of any pressure

discontinuities, including test failures,that appear on the pressure recordingcharts; and

(9) Where elevation differences in thesection under test exceed 100 feet (30meters), a profile of the pipeline thatshows the elevation and test sites overthe entire length of the test section.

[Amdt. 195–34, 50 FR 34474, Aug. 26, 1985, asamended by Amdt. 195–51, 59 FR 29385, June7, 1994; Amdt. 195–63, 63 FR 37506, July 13,1998]

Subpart F—Operation andMaintenance

§ 195.400 Scope.This subpart prescribes minimum re-

quirements for operating and main-taining pipeline systems constructedwith steel pipe.


149


§ 195.401 General requirements.(a) No operator may operate or main-

tain its pipeline systems at a level ofsafety lower than that required by thissubpart and the procedures it is re-quired to establish under § 195.402(a) ofthis subpart.

(b) Whenever an operator discoversany condition that could adversely af-fect the safe operation of its pipelinesystem, it shall correct it within a rea-sonable time. However, if the conditionis of such a nature that it presents animmediate hazard to persons or prop-erty, the operator may not operate theaffected part of the system until it hascorrected the unsafe condition.

(c) Except as provided in § 195.5, nooperator may operate any part of anyof the following pipelines unless it wasdesigned and constructed as requiredby this part:

(1) An interstate pipeline, other thana low-stress pipeline, on which con-struction was begun after March 31,1970, that transports hazardous liquid.

(2) An interstate offshore gatheringline, other than a low-stress pipeline,on which construction was begun afterJuly 31, 1977, that transports hazardousliquid.

(3) An intrastate pipeline, other thana low-stress pipeline, on which con-struction was begun after October 20,1985, that transports hazardous liquid.

(4) A pipeline on which constructionwas begun after July 11, 1991, thattransports carbon dioxide.

(5) A low-stress pipeline on whichconstruction was begun after August10, 1994.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended by Amdt. 195–33, 50 FR 15899, Apr.23, 1985; Amdt. 195–33A, 50 FR 39008, Sept. 26,1985; Amdt. 195–36, 51 FR 15008, Apr. 22, 1986;Amdt. 195–45, 56 FR 26926, June 12, 1991;Amdt. 195–53, 59 FR 35471, July 12, 1994]

§ 195.402 Procedural manual for oper-ations, maintenance, and emer-gencies.

(a) General. Each operator shall pre-pare and follow for each pipeline sys-tem a manual of written procedures forconducting normal operations andmaintenance activities and handlingabnormal operations and emergencies.This manual shall be reviewed at inter-vals not exceeding 15 months, but at

least once each calendar year, and ap-propriate changes made as necessary toinsure that the manual is effective.This manual shall be prepared beforeinitial operations of a pipeline systemcommence, and appropriate parts shallbe kept at locations where operationsand maintenance activities are con-ducted.

(b) The Administrator or the StateAgency that has submitted a currentcertification under the pipeline safetylaws (49 U.S.C. 60101 et seq.) with re-spect to the pipeline facility governedby an operator’s plans and proceduresmay, after notice and opportunity forhearing as provided in 49 CFR 190.237 orthe relevant State procedures, requirethe operator to amend its plans andprocedures as necessary to provide areasonable level of safety.

(c) Maintenance and normal operations.The manual required by paragraph (a)of this section must include proceduresfor the following to provide safety dur-ing maintenance and normal oper-ations:

(1) Making construction records,maps, and operating history availableas necessary for safe operation andmaintenance.

(2) Gathering of data needed for re-porting accidents under subpart B ofthis part in a timely and effective man-ner.

(3) Operating, maintaining, and re-pairing the pipeline system in accord-ance with each of the requirements ofthis subpart.

(4) Determining which pipeline facili-ties are located in areas that would re-quire an immediate response by the op-erator to prevent hazards to the publicif the facilities failed or malfunctioned.

(5) Analyzing pipeline accidents todetermine their causes.

(6) Minimizing the potential for haz-ards identified under paragraph (c)(4)of this section and the possibility of re-currence of accidents analyzed underparagraph (c)(5) of this section.

(7) Starting up and shutting downany part of the pipeline system in amanner designed to assure operationwithin the limits prescribed by§ 195.406, consider the hazardous liquidor carbon dioxide in transportation,


150

49 CFR Ch. I (10–1–01 Edition)§ 195.402

variations in altitude along the pipe-line, and pressure monitoring and con-trol devices.

(8) In the case of a pipeline that isnot equipped to fail safe, monitoringfrom an attended location pipelinepressure during startup until steadystate pressure and flow conditions arereached and during shut-in to assureoperation within limits prescribed by§ 195.406.

(9) In the case of facilities notequipped to fail safe that are identifiedunder paragraph 195.402(c)(4) or thatcontrol receipt and delivery of the haz-ardous liquid or carbon dioxide, detect-ing abnormal operating conditions bymonitoring pressure, temperature, flowor other appropriate operational dataand transmitting this data to an at-tended location.

(10) Abandoning pipeline facilities,including safe disconnection from anoperating pipeline system, purging ofcombustibles, and sealing abandonedfacilities left in place to minimize safe-ty and environmental hazards. Foreach abandoned offshore pipeline facil-ity or each abandoned onshore pipelinefacility that crosses over, under orthrough commercially navigable wa-terways the last operator of that facil-ity must file a report upon abandon-ment of that facility in accordancewith § 195.59 of this part.

(11) Minimizing the likelihood of ac-cidental ignition of vapors in areasnear facilities identified under para-graph (c)(4) of this section where thepotential exists for the presence offlammable liquids or gases.

(12) Establishing and maintaining li-aison with fire, police, and other appro-priate public officials to learn the re-sponsibility and resources of each gov-ernment organization that may re-spond to a hazardous liquid or carbondioxide pipeline emergency and ac-quaint the officials with the operator’sability in respondinq to a hazardousliquid or carbon dioxide pipeline emer-gency and means of communication.

(13) Periodically reviewing the workdone by operator personnel to deter-mine the effectiveness of the proce-dures used in normal operation andmaintenance and taking corrective ac-tion where deficiencies are found.

(14) Taking adequate precautions inexcavated trenches to protect per-sonnel from the hazards of unsafe accu-mulations of vapor or gas, and makingavailable when needed at the exca-vation, emergency rescue equipment,including a breathing apparatus and, arescue harness and line.

(d) Abnormal operation. The manualrequired by paragraph (a) of this sec-tion must include procedures for thefollowing to provide safety when oper-ating design limits have been exceeded:

(1) Responding to, investigating, andcorrecting the cause of:

(i) Unintended closure of valves orshutdowns;

(ii) Increase or decrease in pressureor flow rate outside normal operatinglimits;

(iii) Loss of communications;(iv) Operation of any safety device;(v) Any other malfunction of a com-

ponent, deviation from normal oper-ation, or personnel error which couldcause a hazard to persons or property.

(2) Checking variations from normaloperation after abnormal operation hasended at sufficient critical locations inthe system to determine continued in-tegrity and safe operation.

(3) Correcting variations from normaloperation of pressure and flow equip-ment and controls.

(4) Notifying responsible operatorpersonnel when notice of an abnormaloperation is received.

(5) Periodically reviewing the re-sponse of operator personnel to deter-mine the effectiveness of the proce-dures controlling abnormal operationand taking corrective action where de-ficiencies are found.

(e) Emergencies. The manual requiredby paragraph (a) of this section mustinclude procedures for the following toprovide safety when an emergency con-dition occurs:

(1) Receiving, identifying, andclassifying notices of events whichneed immediate response by the oper-ator or notice to fire, police, or otherappropriate public officials and com-municating this information to appro-priate operator personnel for correc-tive action.

(2) Prompt and effective response to anotice of each type emergency, includ-ing fire or explosion occurring near or


151


directly involving a pipeline facility,accidental release of hazardous liquidor carbon dioxide from a pipeline facil-ity, operational failure causing a haz-ardous condition, and natural disasteraffecting pipeline facilities.

(3) Having personnel, equipment, in-struments, tools, and material avail-able as needed at the scene of an emer-gency.

(4) Taking necessary action, such asemergency shutdown or pressure reduc-tion, to minimize the volume of haz-ardous liquid or carbon dioxide that isreleased from any section of a pipelinesystem in the event of a failure.

(5) Control of released hazardous liq-uid or carbon dioxide at an accidentscene to minimize the hazards, includ-ing possible intentional ignition in thecases of flammable highly volatile liq-uid.

(6) Minimization of public exposureto injury and probability of accidentalignition by assisting with evacuationof residents and assisting with haltingtraffic on roads and railroads in the af-fected area, or taking other appro-priate action.

(7) Notifying fire, police, and otherappropriate public officials of haz-ardous liquid or carbon dioxide pipelineemergencies and coordinating withthem preplanned and actual responsesduring an emergency, including addi-tional precautions necessary for anemergency involving a pipeline systemtransporting a highly volatile liquid.

(8) In the case of failure of a pipelinesystem transporting a highly volatileliquid, use of appropriate instrumentsto assess the extent and coverage ofthe vapor cloud and determine the haz-ardous areas.

(9) Providing for a post accident re-view of employee activities to deter-mine whether the procedures were ef-fective in each emergency and takingcorrective action where deficienciesare found.

(f) Safety-related condition reports. Themanual required by paragraph (a) ofthis section must include instructionsenabling personnel who perform oper-ation and maintenance activities torecognize conditions that potentiallymay be safety-related conditions that

are subject to the reporting require-ments of § 195.55.

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47FR 32721, July 29, 1982, as amended by Amdt.195–24, 47 FR 46852, Oct. 21, 1982; Amdt. 195–39,53 FR 24951, July 1, 1988; Amdt. 195–45, 56 FR26926, June 12, 1991; Amdt. 195–46, 56 FR 31090,July 9, 1991; Amdt. 195–49, 59 FR 6585, Feb. 11,1994; Amdt. 195–55, 61 FR 18518, Apr. 26, 1996;Amdt. 195–69, 65 FR 54444, Sept. 8, 2000]

§ 195.403 Training.(a) Each operator shall establish and

conduct a continuing training programto instruct operating and maintenancepersonnel to:

(1) Carry out the operating and main-tenance, and emergency procedures es-tablished under § 195.402 that relate totheir assignments;

(2) Know the characteristics and haz-ards of the hazardous liquids or carbondioxide transported, including, in thecase of flammable HVL, flammabilityof mixtures with air, odorless vapors,and water reactions;

(3) Recognize conditions that arelikely to cause emergencies, predictthe consequences of facility malfunc-tions or failures and hazardous liquidor carbon dioxide spills, and to take ap-propriate corrective action;

(4) Take steps necessary to controlany accidental release of hazardous liq-uid or carbon dioxide and to minimizethe potential for fire, explosion, tox-icity, or environmental damage;

(5) Learn the proper use of fire-fighting procedures and equipment, firesuits, and breathing apparatus by uti-lizing, where feasible, a simulated pipe-line emergency condition; and

(6) In the case of maintenance per-sonnel, to safely repair facilities usingappropriate special precautions, suchas isolation and purging, when highlyvolatile liquids are involved.

(b) At intervals not exceeding 15months, but at least once each cal-endar year, each operator shall:

(1) Review with personnel their per-formance in meeting the objectives ofthe training program set forth in para-graph (a) of this section; and

(2) Make appropriate changes to thetraining program as necessary to in-sure that it is effective.

(c) Each operator shall require andverify that its supervisors maintain athorough knowledge of that portion of


152

49 CFR Ch. I (10–1–01 Edition)§ 195.404

the procedures established under§ 195.402 for which they are responsibleto insure compliance.

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47FR 32721, July 29, 1982, as amended by Amdt.195–24, 47 FR 46852, Oct. 21, 1982; Amdt. 195–45,56 FR 26926, June 12, 1991]

EFFECTIVE DATE NOTE: By Amdt. 195–67, 64FR 46866, Aug. 27, 1999, § 195.403 was revised,effective Oct. 28, 2002. For the convenience ofthe user, the revised text follows:

§ 195.403 Emergency response training.(a) Each operator shall establish and con-

duct a continuing training program to in-struct emergency response personnel to:

(1) Carry out the emergency procedures es-tablished under 195.402 that relate to theirassignments;

(2) Know the characteristics and hazards ofthe hazardous liquids or carbon dioxidetransported, including, in case of flammableHVL, flammability of mixtures with air,odorless vapors, and water reactions;

(3) Recognize conditions that are likely tocause emergencies, predict the consequencesof facility malfunctions or failures and haz-ardous liquids or carbon dioxide spills, andtake appropriate corrective action;

(4) Take steps necessary to control any ac-cidental release of hazardous liquid or car-bon dioxide and to minimize the potentialfor fire, explosion, toxicity, or environ-mental damage; and

(5) Learn the proper use of firefighting pro-cedures and equipment, fire suits, andbreathing apparatus by utilizing, where fea-sible, a simulated pipeline emergency condi-tion.

(b) At the intervals not exceeding 15months, but at least once each calendaryear, each operator shall:

(1) Review with personnel their perform-ance in meeting the objectives of the emer-gency response training program set forth inparagraph (a) of this section; and

(2) Make appropriate changes to the emer-gency response training program as nec-essary to ensure that it is effective.

(c) Each operator shall require and verifythat its supervisors maintain a thoroughknowledge of that portion of the emergencyresponse procedures established under 195.402for which they are responsible to ensurecompliance.

[Amdt. 195–67, 64 FR 46866, Aug. 27, 1999]

§ 195.404 Maps and records.(a) Each operator shall maintain cur-

rent maps and records of its pipelinesystems that include at least the fol-lowing information:

(1) Location and identification of thefollowing pipeline facilities:

(i) Breakout tanks;(ii) Pump stations;(iii) Scraper and sphere facilities;(iv) Pipeline valves;(v) Cathodically protected facilities;(vi) Facilities to which § 195.402(c)(9)

applies;(vii) Rights-of-way; and(viii) Safety devices to which § 195.428

applies.(2) All crossings of public roads, rail-

roads, rivers, buried utilities, and for-eign pipelines.

(3) The maximum operating pressureof each pipeline.

(4) The diameter, grade, type, andnominal wall thickness of all pipe.

(b) Each operator shall maintain forat least 3 years daily operating recordsthat indicate—

(1) The discharge pressure at eachpump station; and

(2) Any emergency or abnormal oper-ation to which the procedures under§ 195.402 apply.

(c) Each operator shall maintain thefollowing records for the periods speci-fied:

(1) The date, location, and descrip-tion of each repair made to pipe shallbe maintained for the useful life of thepipe.

(2) The date, location, and descrip-tion of each repair made to parts of thepipeline system other than pipe shallbe maintained for at least 1 year.

(3) A record of each inspection andtest required by this subpart shall bemaintained for at least 2 years or untilthe next inspection or test is per-formed, whichever is longer.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended by Amdt. 195–34, 50 FR 34474, Aug.26, 1985]

§ 195.405 Protection against ignitionsand safe access/egress involvingfloating roofs.

(a) After October 2, 2000, protectionprovided against ignitions arising outof static electricity, lightning, andstray currents during operation andmaintenance activities involvingaboveground breakout tanks must bein accordance with API RecommendedPractice 2003, unless the operator notesin the procedural manual (§ 195.402(c))why compliance with all or certain pro-visions of API Recommended Practice


153


2003 is not necessary for the safety of aparticular breakout tank.

(b) The hazards associated with ac-cess/egress onto floating roofs of in-service aboveground breakout tanks toperform inspection, service, mainte-nance or repair activities (other thanspecified general considerations, speci-fied routine tasks or entering tanks re-moved from service for cleaning) areaddressed in API Publication 2026.After October 2, 2000, the operator mustreview and consider the potentiallyhazardous conditions, safety practicesand procedures in API Publication 2026for inclusion in the procedure manual(§ 195.402(c)).

[Amdt. 195–66, 64 FR 15936, Apr. 2, 1999]

§ 195.406 Maximum operating pres-sure.

(a) Except for surge pressures andother variations from normal oper-ations, no operator may operate a pipe-line at a pressure that exceeds any ofthe following:

(1) The internal design pressure ofthe pipe determined in accordance with§ 195.106. However, for steel pipe in pipe-lines being converted under § 195.5, ifone or more factors of the design for-mula (§ 195.106) are unknown, one of thefollowing pressures is to be used as de-sign pressure:

(i) Eighty percent of the first testpressure that produces yield under sec-tion N5.0 of appendix N of ASME B31.8,reduced by the appropriate factors in§§ 195.106 (a) and (e); or

(ii) If the pipe is 12 3⁄4 inch (324 mm)or less outside diameter and is nottested to yield under this paragraph,200 p.s.i. (1379 kPa) gage.

(2) The design pressure of any othercomponent of the pipeline.

(3) Eighty percent of the test pres-sure for any part of the pipeline whichhas been pressure tested under subpartE of this part.

(4) Eighty percent of the factory testpressure or of the prototype test pres-sure for any individually installedcomponent which is excepted fromtesting under § 195.305.

(5) For pipelines under §§ 195.302(b)(1)and (b)(2)(i) that have not been pres-sure tested under subpart E of thispart, 80 percent of the test pressure orhighest operating pressure to which

the pipeline was subjected for 4 or morecontinuous hours that can be dem-onstrated by recording charts or logsmade at the time the test or operationswere conducted.

(b) No operator may permit the pres-sure in a pipeline during surges orother variations from normal oper-ations to exceed 110 percent of the op-erating pressure limit establishedunder paragraph (a) of this section.Each operator must provide adequatecontrols and protective equipment tocontrol the pressure within this limit.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended by Amdt. 195–33, 50 FR 15899, Apr.23, 1985; 50 FR 38660, Sept. 24, 1985; Amdt. 195–51, 59 FR 29385, June 7, 1994; Amdt. 195–52, 59FR 33397, June 28, 1994; Amdt. 195–63, 63 FR37506, July 13, 1998; Amdt. 195–65, 63 FR 59480,Nov. 4, 1998]

§ 195.408 Communications.(a) Each operator must have a com-

munication system to provide for thetransmission of information needed forthe safe operation of its pipeline sys-tem.

(b) The communication system re-quired by paragraph (a) of this sectionmust, as a minimum, include meansfor:

(1) Monitoring operational data as re-quired by § 195.402(c)(9);

(2) Receiving notices from operatorpersonnel, the public, and public au-thorities of abnormal or emergencyconditions and sending this informa-tion to appropriate personnel or gov-ernment agencies for corrective action;

(3) Conducting two-way vocal com-munication between a control centerand the scene of abnormal operationsand emergencies; and

(4) Providing communication withfire, police, and other appropriate pub-lic officials during emergency condi-tions, including a natural disaster.

§ 195.410 Line markers.(a) Except as provided in paragraph

(b) of this section, each operator shallplace and maintain line markers overeach buried pipeline in accordance withthe following:

(1) Markers must be located at eachpublic road crossing, at each railroadcrossing, and in sufficient numberalong the remainder of each buried line


154

49 CFR Ch. I (10–1–01 Edition)§ 195.412

so that its location is accuratelyknown.

(2) The marker must state at leastthe following on a background ofsharply contrasting color:

(i) The word ‘‘Warning,’’ ‘‘Caution,’’or ‘‘Danger’’ followed by the words‘‘Petroleum (or the name of the haz-ardous liquid transported) Pipeline’’, or‘‘Carbon Dioxide Pipeline,’’ all ofwhich, except for markers in heavilydeveloped urban areas, must be in let-ters at least 1 inch (25 millimeters)high with an approximate stroke of 1⁄4inch (6.4 millimeters).

(ii) The name of the operator and atelephone number (including area code)where the operator can be reached atall times.

(b) Line markers are not required forburied pipelines located—

(1) Offshore or at crossings of orunder waterways and other bodies ofwater; or

(2) In heavily developed urban areassuch as downtown business centerswhere—

(i) The placement of markers is im-practical and would not serve the pur-pose for which markers are intended;and

(ii) The local government maintainscurrent substructure records.

(c) Each operator shall provide linemarking at locations where the line isabove ground in areas that are acces-sible to the public.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended by Amdt. 195–27, 48 FR 25208, June6, 1983; Amdt. 195–54, 60 FR 14650, Mar. 20,1995; Amdt. 195–63, 63 FR 37506, July 13, 1998]

§ 195.412 Inspection of rights-of-wayand crossings under navigable wa-ters.

(a) Each operator shall, at intervalsnot exceeding 3 weeks, but at least 26times each calendar year, inspect thesurface conditions on or adjacent toeach pipeline right-of-way. Methods ofinspection include walking, driving,flying or other appropriate means oftraversing the right-of-way.

(b) Except for offshore pipelines, eachoperator shall, at intervals not exceed-ing 5 years, inspect each crossing under

a navigable waterway to determine thecondition of the crossing.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended by Amdt. 195–24, 47 FR 46852, Oct.21, 1982; Amdt. 195–52, 59 FR 33397, June 28,1994]

§ 195.413 Underwater inspection andreburial of pipelines in the Gulf ofMexico and its inlets.

(a) Except for gathering lines of 4 1⁄2inches (114 mm) nominal outside di-ameter or smaller, each operator shall,in accordance with this section, con-duct an underwater inspection of itspipelines in the Gulf of Mexico and itsinlets. The inspection must be con-ducted after October 3, 1989 and beforeNovember 16, 1992.

(b) If, as a result of an inspectionunder paragraph (a) of this section, orupon notification by any person, an op-erator discovers that a pipeline it oper-ates is exposed on the seabed or con-stitutes a hazard to navigation, the op-erator shall—

(1) Promptly, but not later than 24hours after discovery, notify the Na-tional Response Center, telephone: 1–800–424–8802 of the location, and, ifavailable, the geographic coordinatesof that pipeline;

(2) Promptly, but not later than 7days after discovery, mark the locationof the pipeline in accordance with 33CFR part 64 at the ends of the pipelinesegment and at intervals of not over500 yards (457 meters) long, except thata pipeline segment less than 200 yards(183 meters) long need only be markedat the center; and

(3) Within 6 months after discovery,or not later than November 1 of the fol-lowing year if the 6 month period isafter November 1 of the year that thediscovery is made, place the pipeline sothat the top of the pipe is 36 inches (914millimeters) below the seabed for nor-mal excavation or 18 inches (457 milli-meters) for rock excavation.

[Amdt. 195–47, 56 FR 63771, Dec. 5, 1991, asamended by Amdt. 195–52, 59 FR 33396, June28, 1994; Amdt. 195–63, 63 FR 37506, July 13,1998]

§ 195.414 Cathodic protection.(a) No operator may operate a haz-

ardous liquid interstate pipeline afterMarch 31, 1973, a hazardous liquid


155


intrastate pipeline after October 19,1988, or a carbon dioxide pipeline afterJuly 12, 1993 that has an effective ex-ternal surface coating material, unlessthat pipeline is cathodically protected.This paragraph does not apply tobreakout tank areas and buried pump-ing station piping. For the purposes ofthis subpart, a pipeline does not havean effective external coating, and shallbe considered bare, if its cathodic pro-tection current requirements are sub-stantially the same as if it were bare.

(b) Each operator shall electricallyinspect each bare hazardous liquidinterstate pipeline, other than a low-stress pipeline, before April 1, 1975;each bare hazardous liquid intrastatepipeline, other than a low-stress pipe-line, before October 20, 1990; each barecarbon dioxide pipeline before July 12,1994; and each bare low-stress pipelinebefore July 12, 1996 to determine anyareas in which active corrosion is tak-ing place. The operator may not in-crease its established operating pres-sure on a section of bare pipeline untilthe section has been so electrically in-spected. In any areas where active cor-rosion is found, the operator shall pro-vide cathodic protection. Section195.416(f) and (g) apply to all corrodedpipe that is found.

(c) Each operator shall electricallyinspect all breakout tank areas andburied pumping station piping on haz-ardous liquid interstate pipelines,other than low-stress pipelines, beforeApril 1, 1973; on hazardous liquid intra-state pipelines, other than low-stresspipelines, before October 20, 1988; oncarbon dioxide pipelines before July 12,1994; and on low-stress pipelines beforeJuly 12, 1996 as to the need for cathodicprotection, and cathodic protectionshall be provided where necessary.

[Amdt. 195–45, 56 FR 26926, June 12, 1991, asamended by Amdt. 195–53, 59 FR 35471, July12, 1994]

§ 195.416 External corrosion control.(a) Each operator shall, at intervals

not exceeding 15 months, but at leastonce each calendar year, conduct testson each buried, in contact with theground, or submerged pipeline facilityin its pipeline system that is under ca-thodic protection to determine whetherthe protection is adequate.

(b) Each operator shall maintain thetest leads required for cathodic protec-tion in such a condition that electricalmeasurements can be obtained to en-sure adequate protection.

(c) Each operator shall, at intervalsnot exceeding 21⁄2 months, but at leastsix times each calendar year, inspecteach of its cathodic protection recti-fiers.

(d) Each operator shall, at intervalsnot exceeding 5 years, electrically in-spect the bare pipe in its pipeline sys-tem that is not cathodically protectedand must study leak records for thatpipe to determine if additional protec-tion is needed.

(e) Whenever any buried pipe is ex-posed for any reason, the operator shallexamine the pipe for evidence of exter-nal corrosion. If the operator finds thatthere is active corrosion, that the sur-face of the pipe is generally pitted, orthat corrosion has caused a leak, itshall investigate further to determinethe extent of the corrosion.

(f) Any pipe that is found to be gen-erally corroded so that the remainingwall thickness is less than the min-imum thickness required by the pipespecification tolerances must be re-placed with coated pipe that meets therequirements of this part. However,generally corroded pipe need not be re-placed if—

(1) The operating pressure is reducedto be commensurate with the limits onoperating pressure specified in thissubpart, based on the actual remainingwall thickness; or

(2) The pipe is repaired by a methodthat reliable engineering tests andanalyses show can permanently restorethe serviceability of the pipe.

(g) If localized corrosion pitting isfound to exist to a degree whereleakagemight result, the pipe must be replacedor repaired, or the operating pressuremust be reduced commensurate withthe strength of the pipe based on theactual remaining wall thickness in thepits.

(h) The strength of the pipe, based onactual remaining wall thickness, forparagraphs (f) and (g) of this sectionmay be determined by the procedure inASME B31G manual for Determiningthe Remaining Strength of Corroded


156

49 CFR Ch. I (10–1–01 Edition)§ 195.418

Pipelines or by the procedure devel-oped by AGA/Battelle—A Modified Cri-terion for Evaluating the RemainingStrength of Corroded Pipe (withRSTRENG disk). Application of theprocedure in the ASME B31G manualor the AGA/Battelle Modified Criterionis applicable to corroded regions (notpenetrating the pipe wall) in existingsteel pipelines in accordance with limi-tations set out in the respective proce-dures.

(i) Each operator shall clean, coatwith material suitable for the preven-tion of atmospheric corrosion, and,maintain this protection for, each com-ponent in its pipeline system that isexposed to the atmosphere.

(j) For aboveground breakout tankswhere corrosion of the tank bottom iscontrolled by a cathodic protectionsystem, the cathodic protection systemmust be inspected to ensure it is oper-ated and maintained in accordancewith API Recommended Practice 651,unless the operator notes in the proce-dure manual (§ 195.402(c)) why compli-ance with all or certain provisions ofAPI Recommended Practice 651 is notnecessary for the safety of a particularbreakout tank.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended by Amdt. 195–24, 47 FR 46852, Oct.21, 1982; Amdt. 195–31, 49 FR 36384, Sept. 17,1984; Amdt. 195–52, 59 FR 33397, June 28, 1994;Amdt. 195–66, 64 FR 15936, Apr. 2, 1999; Amdt.195–68, 64 FR 69665, Dec. 14, 1999]

§ 195.418 Internal corrosion control.(a) No operator may transport any

hazardous liquid or carbon dioxide thatwould corrode the pipe or other compo-nents of its pipeline system, unless ithas investigated the corrosive effect ofthe hazardous liquid or carbon dioxideon the system and has taken adequatesteps to mitigate corrosion.

(b) If corrosion inhibitors are used tomitigate internal corrosion the oper-ator shall use inhibitors in sufficientquantity to protect the entire part ofthe system that the inhibitors are de-signed to protect and shall also usecoupons or other monitoring equip-ment to determine their effectiveness.

(c) The operator shall, at intervalsnot exceeding 71⁄2 months, but at leasttwice each calendar year, examine cou-pons or other types of monitoring

equipment to determine the effective-ness of the inhibitors or the extent ofany corrosion.

(d) Whenever any pipe is removedfrom the pipeline for any reason, theoperator must inspect the internal sur-face for evidence of corrosion. If thepipe is generally corroded such thatthe remaining wall thickness is lessthan the minimum thickness requiredby the pipe specification tolerances,the operator shall investigate adjacentpipe to determine the extent of the cor-rosion. The corroded pipe must be re-placed with pipe that meets the re-quirements of this part or, based on theactual remaining wall thickness, theoperating pressure must be reduced tobe commensurate with the limits onoperating pressure specified in thissubpart.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended by Amdt. 195–20B, 46 FR 38922, July30, 1981; Amdt. 195–24, 47 FR 46852, Oct. 21,1982; Amdt. 195–45, 56 FR 26927, June 12, 1991]

§ 195.420 Valve maintenance.(a) Each operator shall maintain

each valve that is necessary for thesafe operation of its pipeline systemsin good working order at all times.

(b) Each operator shall, at intervalsnot exceeding 71⁄2 months, but at leasttwice each calendar year, inspect eachmainline valve to determine that it isfunctioning properly.

(c) Each operator shall provide pro-tection for each valve from unauthor-ized operation and from vandalism.

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47FR 32721, July 29, 1982, as amended by Amdt.195–24, 47 FR 46852, Oct. 21, 1982]

§ 195.422 Pipeline repairs.(a) Each operator shall, in repairing

its pipeline systems, insure that the re-pairs are made in a safe manner andare made so as to prevent damage topersons or property.

(b) No operator may use any pipe,valve, or fitting, for replacement in re-pairing pipeline facilities, unless it isdesigned and constructed as requiredby this part.

§ 195.424 Pipe movement.(a) No operator may move any line

pipe, unless the pressure in the linesection involved is reduced to not more


157


than 50 percent of the maximum oper-ating pressure.

(b) No operator may move any pipe-line containing highly volatile liquidswhere materials in the line section in-volved are joined by welding unless—

(1) Movement when the pipeline doesnot contain highly volatile liquids isimpractical;

(2) The procedures of the operatorunder § 195.402 contain precautions toprotect the public against the hazardin moving pipelines containing highlyvolatile liquids, including the use ofwarnings, where necessary, to evacuatethe area close to the pipeline; and

(3) The pressure in that line sectionis reduced to the lower of the fol-lowing:

(i) Fifty percent or less of the max-imum operating pressure; or

(ii) The lowest practical level thatwill maintain the highly volatile liquidin a liquid state with continuous flow,but not less than 50 p.s.i. (345 kPa) gageabove the vapor pressure of the com-modity.

(c) No operator may move any pipe-line containing highly volatile liquidswhere materials in the line section in-volved are not joined by welding un-less—

(1) The operator complies with para-graphs (b) (1) and (2) of this section;and

(2) That line section is isolated toprevent the flow of highly volatile liq-uid.

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 46FR 38922, July 30, 1981, as amended by Amdt.195–63, 63 FR 37506, July 13, 1998]

§ 195.426 Scraper and sphere facilities.

No operator may use a launcher orreceiver that is not equipped with a re-lief device capable of safely relievingpressure in the barrel before insertionor removal of scrapers or spheres. Theoperator must use a suitable device toindicate that pressure has been re-lieved in the barrel or must provide ameans to prevent insertion or removalof scrapers or spheres if pressure hasnot been relieved in the barrel.

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47FR 32721, July 29, 1982]

§ 195.428 Overpressure safety devicesand overfill protection systems.

(a) Except as provided in paragraph(b) of this section, each operator shall,at intervals not exceeding 15 months,but at least once each calendar year, orin the case of pipelines used to carryhighly volatile liquids, at intervals notto exceed 71⁄2 months, but at least twiceeach calendar year, inspect and testeach pressure limiting device, reliefvalve, pressure regulator, or other itemof pressure control equipment to deter-mine that it is functioning properly, isin good mechanical condition, and isadequate from the standpoint of capac-ity and reliability of operation for theservice in which it is used.

(b) In the case of relief valves onpressure breakout tanks containinghighly volatile liquids, each operatorshall test each valve at intervals notexceeding 5 years.

(c) Aboveground breakout tanks thatare constructed or significantly alteredaccording to API Standard 2510 afterOctober 2, 2000, must have an overfillprotection system installed accordingto section 5.1.2 of API Standard 2510.Other aboveground breakout tankswith 600 gallons (2271 liters) or more ofstorage capacity that are constructedor significantly altered after October 2,2000, must have an overfill protectionsystem installed according to API Rec-ommended Practice 2350. However, op-erators need not comply with any partof API Recommended Practice 2350 fora particular breakout tank if the oper-ator notes in the manual required by§ 195.402 why compliance with that partis not necessary for safety of the tank.

(d) After October 2, 2000, the require-ments of paragraphs (a) and (b) of thissection for inspection and testing ofpressure control equipment apply tothe inspection and testing of overfillprotection systems.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, asamended by Amdt. 195–24, 47 FR 46852, Oct.21, 1982; Amdt. 195–66, 64 FR 15936, Apr. 2,1999]

§ 195.430 Firefighting equipment.

Each operator shall maintain ade-quate firefighting equipment at eachpump station and breakout tank area.The equipment must be—


158

49 CFR Ch. I (10–1–01 Edition)§ 195.432

(a) In proper operating condition atall times;

(b) Plainly marked so that its iden-tity as firefighting equipment is clear;and

(c) Located so that it is easily acces-sible during a fire.

§ 195.432 Inspection of in-servicebreakout tanks.

(a) Except for breakout tanks in-spected under paragraphs (b) and (c) ofthis section, each operator shall, at in-tervals not exceeding 15 months, but atleast once each calendar year, inspecteach in-service breakout tank.

(b) Each operator shall inspect thephysical integrity of in-service atmos-pheric and low-pressure steel above-ground breakout tanks according tosection 4 of API Standard 653. However,if structural conditions prevent accessto the tank bottom, the bottom integ-rity may be assessed according to aplan included in the operations andmaintenance manual under§ 195.402(c)(3).

(c) Each operator shall inspect thephysical integrity of in-service steelaboveground breakout tanks built toAPI Standard 2510 according to section6 of API 510.

(d) The intervals of inspection speci-fied by documents referenced in para-graphs (b) and (c) of this section beginon May 3, 1999, or on the operator’s lastrecorded date of the inspection, which-ever is earlier.

[Amdt. 195–66, 64 FR 15936, Apr. 2, 1999]

§ 195.434 Signs.Each operator shall maintain signs

visible to the public around each pump-ing station and breakout tank area.Each sign must contain the name ofthe operator and an emergency tele-phone number to contact.

§ 195.436 Security of facilities.Each operator shall provide protec-

tion for each pumping station andbreakout tank area and other exposedfacility (such as scraper traps) fromvandalism and unauthorized entry.

§ 195.438 Smoking or open flames.Each operator shall prohibit smoking

and open flames in each pump station

area and each breakout tank areawhere there is a possibility of the leak-age of a flammable hazardous liquid orof the presence of flammable vapors.

§ 195.440 Public education.Each operator shall establish a con-

tinuing educational program to enablethe public, appropriate government or-ganizations and persons engaged in ex-cavation-related activities to recognizea hazardous liquid or a carbon dioxidepipeline emergency and to report it tothe operator or the fire, police, orother appropriate public officials. Theprogram must be conducted in Englishand in other languages commonly un-derstood by a significant number andconcentration of non-English speakingpopulation in the operator’s operatingareas.

[Amdt. 195–45, 56 FR 26927, June 12, 1991]

§ 195.442 Damage prevention program.(a) Except as provided in paragraph

(d) of this section, each operator of aburied pipeline must carry out, in ac-cordance with this section, a writtenprogram to prevent damage to thatpipeline from excavation activities.For the purpose of this section, theterm ‘‘excavation activities’’ includesexcavation, blasting, boring, tunneling,backfilling, the removal of above-ground structures by either explosiveor mechanical means, and otherearthmoving operations.

(b) An operator may comply with anyof the requirements of paragraph (c) ofthis section through participation in apublic service program, such as a one-call system, but such participationdoes not relieve the operator of the re-sponsibility for compliance with thissection. However, an operator mustperform the duties of paragraph (c)(3)of this section through participation ina one-call system, if that one-call sys-tem is a qualified one-call system. Inareas that are covered by more thanone qualified one-call system, an oper-ator need only join one of the qualifiedone-call systems if there is a centraltelephone number for excavators tocall for excavation activities, or if theone-call systems in those areas com-municate with one another. An opera-tor’s pipeline system must be coveredby a qualified one-call system where


159


there is one in place. For the purposeof this section, a one-call system isconsidered a ‘‘qualified one-call sys-tem’’ if it meets the requirements ofsection (b)(1) or (b)(2) or this section.

(1) The state has adopted a one-calldamage prevention program under§ 198.37 of this chapter; or

(2) The one-call system:(i) Is operated in accordance with

§ 198.39 of this chapter;(ii) Provides a pipeline operator an

opportunity similar to a voluntary par-ticipant to have a part in managementresponsibilities; and

(iii) Assesses a participating pipelineoperator a fee that is proportionate tothe costs of the one-call system’s cov-erage of the operator’s pipeline.

(c) The damage prevention programrequired by paragraph (a) of this sec-tion must, at a minimum:

(1) Include the identity, on a currentbasis, of persons who normally engagein excavation activities in the area inwhich the pipeline is located.

(2) Provides for notification of thepublic in the vicinity of the pipelineand actual notification of persons iden-tified in paragraph (c)(1) of this sectionof the following as often as needed tomake them aware of the damage pre-vention program:

(i) The program’s existence and pur-pose; and

(ii) How to learn the location of un-derground pipelines before excavationactivities are begun.

(3) Provide a means of receiving andrecording notification of planned exca-vation activities.

(4) If the operator has buried pipe-lines in the area of excavation activity,provide for actual notification of per-sons who give notice of their intent toexcavate of the type of temporarymarking to be provided and how toidentify the markings.

(5) Provide for temporary marking ofburied pipelines in the area of exca-vation activity before, as far as prac-tical, the activity begins.

(6) Provide as follows for inspectionof pipelines that an operator has rea-son to believe could be damaged by ex-cavation activities:

(i) The inspection must be done asfrequently as necessary during and

after the activities to verify the integ-rity of the pipeline; and

(ii) In the case of blasting, any in-spection must include leakage surveys.

(d) A damage prevention programunder this section is not required forthe following pipelines:

(1) Pipelines located offshore.(2) Pipelines to which access is phys-

ically controlled by the operator.

[Amdt. 195–54, 60 FR 14651, Mar. 20, 1995, asamended by Amdt. 195–60, 62 FR 61699, Nov.19, 1997]

§ 195.444 CPM leak detection.Each computational pipeline moni-

toring (CPM) leak detection system in-stalled on a hazardous liquid pipelinetransporting liquid in single phase(without gas in the liquid) must com-ply with API 1130 in operating, main-taining, testing, record keeping, anddispatcher training of the system.

[Amdt. 195–62, 63 FR 36376, July 6, 1998]

HIGH CONSEQUENCE AREAS

§ 195.450 Definitions.The following definitions apply to

this section and § 195.452:Emergency flow restricting device or

EFRD means a check valve or remotecontrol valve as follows:

(1) Check valve means a valve thatpermits fluid to flow freely in one di-rection and contains a mechanism toautomatically prevent flow in theother direction.

(2) Remote control valve or RCV meansany valve that is operated from a loca-tion remote from where the valve is in-stalled. The RCV is usually operated bythe supervisory control and data acqui-sition (SCADA) system. The linkagebetween the pipeline control center andthe RCV may be by fiber optics, micro-wave, telephone lines, or satellite.

High consequence area means:(1) A commercially navigable waterway,

which means a waterway where a sub-stantial likelihood of commercial navi-gation exists;

(2) A high population area, whichmeans an urbanized area, as definedand delineated by the Census Bureau,that contains 50,000 or more people andhas a population density of at least1,000 people per square mile;


160

49 CFR Ch. I (10–1–01 Edition)§ 195.452

(3) An other populated area, whichmeans a place, as defined and delin-eated by the Census Bureau, that con-tains a concentrated population, suchas an incorporated or unincorporatedcity, town, village, or other designatedresidential or commercial area;

(4) An unusually sensitive area, as de-fined in § 195.6.

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

PIPELINE INTEGRITY MANAGEMENT

§ 195.452 Pipeline integrity manage-ment in high consequence areas.

(a) Which operators must comply? Thissection applies to each operator whoowns or operates a total of 500 or moremiles of hazardous liquid pipeline sub-ject to this part.

(b) What must an operator do? (1) Nolater than March 31, 2002, an operatormust develop a written integrity man-agement program that addresses therisks on each pipeline segment thatcould affect a high consequence area.An operator must include in the pro-gram:

(i) An identification of all pipelinesegments that could affect a high con-sequence area. A pipeline segment in ahigh consequence area is presumed toaffect that area unless the operator’srisk assessment effectively dem-onstrates otherwise. (See Appendix C ofthis part for guidance on identifyingpipeline segments.) An operator mustcomplete this identification no laterthan December 31, 2001;

(ii) A plan for baseline assessment ofthe line pipe (see paragraph (c) of thissection);

(iii) A framework addressing eachelement of the integrity managementprogram, including continual integrityassessment and evaluation (see para-graphs (f) and (j) of this section). Theframework must initially indicate howdecisions will be made to implementeach element.

(2) An operator must implement andfollow the program it develops.

(3) In carrying out this section, anoperator must follow recognized indus-try practices unless the section speci-fies otherwise or the operator dem-onstrates that an alternative practiceis supported by a reliable engineeringevaluation and provides an equivalent

level of public safety and environ-mental protection.

(c) What must be in the baseline assess-ment plan? (1) An operator must includeeach of the following elements in itswritten baseline assessment plan:

(i) The methods selected to assess theintegrity of the line pipe. For low fre-quency electric resistance welded pipeor lap welded pipe susceptible to longi-tudinal seam failure, an operator mustselect integrity assessment methodscapable of assessing seam integrity andof detecting corrosion and deformationanomalies. An operator must assess theintegrity of the line pipe by:

(A) Internal inspection tool or toolscapable of detecting corrosion and de-formation anomalies including dents,gouges and grooves;

(B) Pressure test conducted in ac-cordance with subpart E of this part; or

(C) Other technology that the oper-ator demonstrates can provide anequivalent understanding of the condi-tion of the line pipe. An operatorchoosing this option must notify theOffice of Pipeline Safety (OPS) 90 daysbefore conducting the assessment, bysending a notice to the address speci-fied in § 195.58 or to the facsimile num-ber specified in § 195.56;

(ii) A schedule for completing the in-tegrity assessment;

(iii) An explanation of the assess-ment methods selected and evaluationof risk factors considered in estab-lishing the assessment schedule.

(2) An operator must document, priorto implementing any changes to theplan, any modification to the plan, andreasons for the modification.

(d) When must the baseline assessmentbe completed? (1) Time period. An oper-ator must establish a baseline assess-ment schedule to determine the pri-ority for assessing the pipeline seg-ments. An operator must complete thebaseline assessment by March 31, 2008.An operator must assess at least 50% ofthe line pipe subject to the require-ments of this section, beginning withthe highest risk pipe, by September 30,2004.

(2) Prior assessment. To satisfy the re-quirements of paragraph (c)(1)(i) of thissection, an operator may use an integ-rity assessment conducted after Janu-ary 1, 1996, if the integrity assessment


161


method meets the requirements of thissection. However, if an operator usesthis prior assessment as its baseline as-sessment, the operator must re-assessthe line pipe according to the require-ments of paragraph (j)(3) of this sec-tion.

(3) Newly-identified areas. (i) When in-formation is available from the infor-mation analysis (see paragraph (g) ofthis section), or from Census Bureaumaps, that the population densityaround a pipeline segment has changedso as to fall within the definition in§ 195.450 of a high population area orother populated area, the operatormust incorporate the area into itsbaseline assessment plan as a high con-sequence area within one year from thedate the area is identified. An operatormust complete the baseline assessmentof any line pipe that could affect thenewly-identified high consequence areawithin five years from the date thearea is identified.

(ii) An operator must incorporate anew unusually sensitive area into itsbaseline assessment plan within oneyear from the date the area is identi-fied. An operator must complete thebaseline assessment of any line pipethat could affect the newly-identifiedhigh consequence area within fiveyears from the date the area is identi-fied.

(e) What are the risk factors for estab-lishing an assessment schedule (for boththe baseline and continual integrity as-sessments)? (1) An operator must estab-lish an integrity assessment schedulethat prioritizes pipeline segments forassessment (see paragraphs (d)(1) and(j)(3) of this section). An operator mustbase the assessment schedule on allrisk factors that reflect the risk condi-tions on the pipeline segment. The fac-tors an operator must consider include,but are not limited to:

(i) Results of the previous integrityassessment, defect type and size thatthe assessment method can detect, anddefect growth rate;

(ii) Pipe size, material, manufac-turing information, coating type andcondition, and seam type;

(iii) Leak history, repair history andcathodic protection history;

(iv) Product transported;(v) Operating stress level;

(vi) Existing or projected activitiesin the area;

(vii) Local environmental factorsthat could affect the pipeline (e.g.,corrosivity of soil, subsidence, cli-matic);

(viii) geo-technical hazards; and(ix) Physical support of the segment

such as by a cable suspension bridge.(2) Appendix C of this part provides

further guidance on risk factors.(f) What are the elements of an integrity

management program? An integritymanagement program begins with theinitial framework. An operator mustcontinually change the program to re-flect operating experience, conclusionsdrawn from results of the integrity as-sessments, and other maintenance andsurveillance data, and evaluation ofconsequences of a failure on the highconsequence area. An operator must in-clude, at minimum, each of the fol-lowing elements in its written integ-rity management program:

(1) A process for identifying whichpipeline segments could affect a highconsequence area;

(2) A baseline assessment plan meet-ing the requirements of paragraph (c)of this section;

(3) An analysis that integrates allavailable information about the integ-rity of the entire pipeline and the con-sequences of a failure (see paragraph(g) of this section);

(4) Criteria for repair actions to ad-dress integrity issues raised by the as-sessment methods and informationanalysis (see paragraph (h) of this sec-tion);

(5) A continual process of assessmentand evaluation to maintain a pipeline’sintegrity (see paragraph (j) of this sec-tion);

(6) Identification of preventive andmitigative measures to protect thehigh consequence area (see paragraph(i) of this section);

(7) Methods to measure the program’seffectiveness (see paragraph (k) of thissection);

(8) A process for review of integrityassessment results and informationanalysis by a person qualified to evalu-ate the results and information (seeparagraph (h)(2) of this section).

(g) What is an information analysis? Inperiodically evaluating the integrity of


162

49 CFR Ch. I (10–1–01 Edition)§ 195.452

each pipeline segment (paragraph (j) ofthis section), an operator must analyzeall available information about the in-tegrity of the entire pipeline and theconsequences of a failure. This infor-mation includes:

(1) Information critical to deter-mining the potential for, and pre-venting, damage due to excavation, in-cluding current and planned damageprevention activities, and developmentor planned development along the pipe-line segment;

(2) Data gathered through the integ-rity assessment required under thissection;

(3) Data gathered in conjunction withother inspections, tests, surveillanceand patrols required by this Part, in-cluding, corrosion control monitoringand cathodic protection surveys; and

(4) Information about how a failurewould affect the high consequencearea, such as location of the water in-take.

(h) What actions must be taken to ad-dress integrity issues? (1) General require-ments. An operator must take promptaction to address all pipeline integrityissues raised by the assessment and in-formation analysis. An operator mustevaluate all anomalies and repair thoseanomalies that could reduce a pipe-line’s integrity. An operator must com-ply with § 195.422 in making a repair.

(2) Discovery of a condition. Discoveryof a condition occurs when an operatorhas adequate information about thecondition to determine the need for re-pair. Depending on circumstances, anoperator may have adequate informa-tion when the operator receives thepreliminary internal inspection report,gathers and integrates informationfrom other inspections or the periodicevaluation, excavates the anomaly, orwhen an operator receives the final in-ternal inspection report. The date ofdiscovery can be no later than the dateof the integrity assessment results orthe final report.

(3) Review of integrity assessment. Anoperator must include in its schedulefor evaluation and repair (as requiredby paragraph (h)(4) of this section), aschedule for promptly reviewing andanalyzing the integrity assessment re-sults. After March 31, 2004, an opera-tor’s schedule must provide for review

of the integrity assessment resultswithin 120 days of conducting each as-sessment. The operator must obtainand assess a final report within an ad-ditional 90 days.

(4) Schedule for repairs. An operatormust complete repairs according to aschedule that prioritizes the conditionsfor evaluation and repair. An operatormust base the schedule on the risk fac-tors listed in paragraph (e)(1) of thissection and any pipeline-specific riskfactors the operator develops. If an op-erator cannot meet the schedule forany of the conditions addressed inparagraphs (h)(5)(i) through (iv) of thissection, the operator must justify thereasons why the schedule cannot bemet and that the changed schedule willnot jeopardize public safety or environ-mental protection. An operator mustnotify OPS if the operator cannot meetthe schedule and cannot provide safetythrough a temporary reduction in oper-ating pressure until a permanent repairis made. An operator must send a no-tice to the address specified in § 195.58or to the facsimile number specified in§ 195.56.

(5) Special requirements for schedulingrepairs—(i) Immediate repair conditions.An operator’s evaluation and repairschedule must provide for immediaterepair conditions. To maintain safety,an operator will need to temporarilyreduce operating pressure or shut downthe pipeline until the operator cancomplete the repair of these condi-tions. An operator must base the tem-porary operating pressure reduction onremaining wall thickness. An operatormust treat the following conditions asimmediate repair conditions:

(A) Metal loss greater than 80% ofnominal wall regardless of dimensions.

(B) Predicted burst pressure less thanthe maximum operating pressure atthe location of the anomaly. Burstpressure has been calculated from theremaining strength of the pipe, using asuitable metal loss strength calcula-tion, e.g., ASME/ANSI B31G (‘‘Manualfor Determining the RemainingStrength of Corroded Pipelines’’ (1991))or AGA Pipeline Research CommitteeProject PR–3–805 (‘‘A Modified Cri-terion for Evaluating the RemainingStrength of Corroded Pipe’’ (December


163


1989)). These documents are availableat the addresses listed at § 195.3.

(C) Dents on the top of the pipeline(above 4 and 8 o’clock position) withany indicated metal loss.

(D) Significant anomaly that in thejudgment of the person evaluating theassessment results requires immediateaction.

(ii) 60-day conditions. Except for con-ditions listed in paragraph (h)(5)(i) ofthis section, an operator must schedulefor evaluation and repair all dents, re-gardless of size, located on the top ofthe pipeline (above 4 and 8 o’clock posi-tion) within 60 days of discovery of thecondition.

(iii) Six-month conditions. Except forconditions listed in paragraph (h)(5)(i)or (ii) of this section, an operator mustschedule evaluation and repair of thefollowing within six months of dis-covery of the condition:

(A) Dents with metal loss or dentsthat affect pipe curvature at a girth orseam weld.

(B) Dents with reported depths great-er than 6% of the pipe diameter.

(C) Remaining strength of the piperesults in a safe operating pressurethat is less than the current estab-lished MOP at the location of theanomaly using a suitable safe oper-ating pressure calculation method(e.g., ASME/ANSI B31G (‘‘Manual forDetermining the Remaining Strengthof Corroded Pipelines’’ (1991)) or AGAPipeline Research Committee ProjectPR–3–805 (‘‘A Modified Criterion forEvaluating the Remaining Strength ofCorroded Pipe’’ (December 1989)). Thesedocuments are available at the address-es listed at § 195.3.

(D) Areas of general corrosion with apredicted metal loss of >50% of nomi-nal wall.

(E) Predicted metal loss of >50% ofnominal wall at crossings of anotherpipeline.

(F) Weld anomalies with a predictedmetal loss >50% of nominal wall.

(G) Potential crack indications thatwhen excavated are determined to becracks.

(H) Corrosion of or along seam welds.(I) Gouges or grooves greater than

12.5% of nominal wall.

(iv) Other conditions. An operatormust schedule evaluation and repair ofthe following conditions:

(A) Data that reflect a change sincelast assessed.

(B) Data that indicate mechanicaldamage that is located on the top halfof the pipe.

(C) Data that indicate anomalies ab-rupt in nature.

(D) Data that indicate anomalies lon-gitudinal in orientation.

(E) Data that indicate anomaliesover a large area.

(F) Anomalies located in or near cas-ings, crossings of another pipeline, andareas with suspect cathodic protection.

(i) What preventive and mitigativemeasures must an operator take to protectthe high consequence area? (1) General re-quirements. An operator must takemeasures to prevent and mitigate theconsequences of a pipeline failure thatcould affect a high consequence area.These measures include conducting arisk analysis of the pipeline segment toidentify additional actions to enhancepublic safety or environmental protec-tion. Such actions may include, but arenot limited to, implementing damageprevention best practices, better moni-toring of cathodic protection wherecorrosion is a concern, establishingshorter inspection intervals, installingEFRDs on the pipeline segment, modi-fying the systems that monitor pres-sure and detect leaks, providing addi-tional training to personnel on re-sponse procedures, conducting drillswith local emergency responders andadopting other management controls.

(2) Risk analysis criteria. In identi-fying the need for additional preven-tive and mitigative measures, an oper-ator must evaluate the likelihood of apipeline release occurring and how arelease could affect the high con-sequence area. This determinationmust consider all relevant risk factors,including, but not limited to:

(i) Terrain surrounding the pipelinesegment, including drainage systemssuch as small streams and other small-er waterways that could act as a con-duit to the high consequence area;

(ii) Elevation profile;(iii) Characteristics of the product

transported;


164

49 CFR Ch. I (10–1–01 Edition)§ 195.452

(iv) Amount of product that could bereleased;

(v) Possibility of a spillage in a farmfield following the drain tile into a wa-terway;

(vi) Ditches along side a roadway thepipeline crosses;

(vii) Physical support of the pipelinesegment such as by a cable suspensionbridge;

(viii) Exposure of the pipeline to op-erating pressure exceeding establishedmaximum operating pressure.

(3) Leak detection. An operator musthave a means to detect leaks on itspipeline system. An operator mustevaluate the capability of its leak de-tection means and modify, as nec-essary, to protect the high consequencearea. An operator’s evaluation must, atleast, consider, the following factors—length and size of the pipeline, type ofproduct carried, the pipeline’s prox-imity to the high consequence area,the swiftness of leak detection, loca-tion of nearest response personnel, leakhistory, and risk assessment results.

(4) Emergency Flow Restricting Devices(EFRD). If an operator determines thatan EFRD is needed on a pipeline seg-ment to protect a high consequencearea in the event of a hazardous liquidpipeline release, an operator must in-stall the EFRD. In making this deter-mination, an operator must, at least,consider the following factors—theswiftness of leak detection and pipelineshutdown capabilities, the type of com-modity carried, the rate of potentialleakage, the volume that can be re-leased, topography or pipeline profile,the potential for ignition, proximity topower sources, location of nearest re-sponse personnel, specific terrain be-tween the pipeline segment and thehigh consequence area, and benefits ex-pected by reducing the spill size.

(j) What is a continual process of eval-uation and assessment to maintain a pipe-line’s integrity? (1) General. After com-pleting the baseline integrity assess-ment, an operator must continue to as-sess the line pipe at specified intervalsand periodically evaluate the integrityof each pipeline segment that could af-fect a high consequence area.

(2) Evaluation. An operator must con-duct a periodic evaluation as fre-quently as needed to assure pipeline in-

tegrity. An operator must base the fre-quency of evaluation on risk factorsspecific to its pipeline, including thefactors specified in paragraph (e) ofthis section. The evaluation must con-sider the past and present integrity as-sessment results, information analysis(paragraph (g) of this section), and de-cisions about repair, and preventiveand mitigative actions (paragraphs (h)and (i) of this section).

(3) Assessment intervals. An operatormust establish intervals not to exceedfive (5) years for continually assessingthe line pipe’s integrity. An operatormust base the assessment intervals onthe risk the line pipe poses to the highconsequence area to determine the pri-ority for assessing the pipeline seg-ments. An operator must establish theassessment intervals based on the fac-tors specified in paragraph (e) of thissection, the analysis of the resultsfrom the last integrity assessment, andthe information analysis required byparagraph (g) of this section.

(4) Variance from the 5-year intervals inlimited situations—(i) Engineering basis.An operator may be able to justify anengineering basis for a longer assess-ment interval on a segment of linepipe. The justification must be sup-ported by a reliable engineering eval-uation combined with the use of othertechnology, such as external moni-toring technology, that provides an un-derstanding of the condition of the linepipe equivalent to that which is obtain-able under paragraph (j)(2) of this sec-tion. An operator must notify OPSnine months before the end of the in-tervals of five years or less of the rea-son why the operator intends to justifya longer interval. An operator mustsend a notice to the address specified in§ 195.58 or to the facsimile number spec-ified in § 195.56. The notice must state aproposed alternative interval.

(ii) Unavailable technology. An oper-ator may require a longer assessmentperiod for a segment of line pipe (forexample, because sophisticated inter-nal inspection technology is not avail-able). An operator must justify the rea-sons why it cannot comply with the re-quired assessment period and must alsodemonstrate the actions it is taking toevaluate the integrity of the pipelinesegment in the interim. An operator


165


must notify OPS 180 days before theend of the intervals of five years or lessthat the operator may require a longerassessment interval. An operator mustsend a notice to the address specified in§ 195.58 or to the facsimile number spec-ified in § 195.56. The Operator may haveup to an additional 180 days to com-plete the assessment.

(5) Assessment methods. An operatormust assess the integrity of the linepipe by:

(i) Internal inspection tool or toolscapable of detecting corrosion and de-formation anomalies including dents,gouges and grooves;

(ii) Pressure test conducted in ac-cordance with subpart E of this part; or

(iii) Other technology that the oper-ator demonstrates can provide anequivalent understanding of the condi-tion of the line pipe. An operatorchoosing this option must notify OPS60 days before conducting the assess-ment, by sending a notice to the ad-dress specified in § 195.58 or to the fac-simile number specified in § 195.56.

(6) However, for low frequency elec-tric resistance welded pipe or lap weld-ed pipe susceptible to longitudinalseam failure, an operator must selectintegrity assessment methods capableof assessing seam integrity and of de-tecting corrosion and deformationanomalies.

(k) What methods to measure programeffectiveness must be used? An operator’sprogram must include methods tomeasure whether the program is effec-tive in assessing and evaluating the in-tegrity of each pipeline segment and inprotecting the high consequence areas.See Appendix C of this part for guid-ance on methods that can be used toevaluate a program’s effectiveness.

(1) What records must be kept? An oper-ator must maintain for review duringan inspection:

(i) A written integrity managementprogram in accordance with paragraph(b) of this section.

(ii) Documents to support the deci-sions and analyses, including anymodifications, justifications,variances, deviations and determina-tions made, and actions taken, to im-plement and evaluate each element ofthe integrity management programlisted in paragraph (f) of this section.

(2) See Appendix C of this part for ex-amples of records an operator would berequired to keep.

[Amdt. 195–70, 65 FR 75406, Dec. 1, 2000]

Subpart G—Qualification ofPipeline Personnel

SOURCE: Amdt. 195–67, 64 FR 46866, Aug. 27,1999, unless otherwise noted.

§ 195.501 Scope.

(a) This subpart prescribes the min-imum requirements for operator quali-fication of individuals performing cov-ered tasks on a pipeline facility.

(b) For the purpose of this subpart, acovered task is an activity, identifiedby the operator, that:

(1) Is performed on a pipeline facility;(2) Is an operations or maintenance

task;(3) Is performed as a requirement of

this part; and(4) Affects the operation or integrity

of the pipeline.

§ 195.503 Definitions.

Abnormal operating condition means acondition identified by the operatorthat may indicate a malfunction of acomponent or deviation from normaloperations that may:

(a) Indicate a condition exceeding de-sign limits; or

(b) Result in a hazard(s) to persons,property, or the environment.

Evaluation means a process, estab-lished and documented by the operator,to determine an individual’s ability toperform a covered task by any of thefollowing:

(a) Written examination;(b) Oral examination;(c) Work performance history review;(d) Observation during:(1) performance on the job,(2) on the job training, or(3) simulations;(e) Other forms of assessment.Qualified means that an individual

has been evaluated and can:(a) Perform assigned covered tasks

and


166

49 CFR Ch. I (10–1–01 Edition)§ 195.505

(b) Recognize and react to abnormaloperating conditions.

[Amdt. 195–67, 64 FR 46866, Aug. 27, 1999, asamended by Amdt. 195–72, 66 FR 43524, Aug.20, 2001]

§ 195.505 Qualification program.

Each operator shall have and follow awritten qualification program. Theprogram shall include provisions to:

(a) Identify covered tasks;(b) Ensure through evaluation that

individuals performing covered tasksare qualified;

(c) Allow individuals that are notqualified pursuant to this subpart toperform a covered task if directed andobserved by an individual that is quali-fied;

(d) Evaluate an individual if the oper-ator has reason to believe that the in-dividual’s performance of a coveredtask contributed to an accident as de-fined in Part 195;

(e) Evaluate an individual if the oper-ator has reason to believe that the in-dividual is no longer qualified to per-form a covered task;

(f) Communicate changes that affectcovered tasks to individuals per-forming those covered tasks; and

(g) Identify those covered tasks andthe intervals at which evaluation ofthe individual’s qualifications is need-ed.

§ 195.507 Recordkeeping.

Each operator shall maintain recordsthat demonstrate compliance with thissubpart.

(a) Qualification records shall in-clude:

(1) Identification of qualified indi-vidual(s);

(2) Identification of the covered tasksthe individual is qualified to perform;

(3) Date(s) of current qualification;and

(4) Qualification method(s).(b) Records supporting an individ-

ual’s current qualification shall bemaintained while the individual is per-forming the covered task. Records ofprior qualification and records of indi-viduals no longer performing coveredtasks shall be retained for a period offive years.

§ 195.509 General.(a) Operators must have a written

qualification program by April 27, 2001.(b) Operators must complete the

qualification of individuals performingcovered tasks by October 28, 2002.

(c) Work performance history reviewmay be used as a sole evaluation meth-od for individuals who were performinga covered task prior to October 26, 1999.

(d) After October 28, 2002, work per-formance history may not be used as asole evaluation method.

[Amdt. 195–67, 64 FR 46866, Aug. 27, 1999, asamended by Amdt. 195–72, 66 FR 43524, Aug.20, 2001]

APPENDIX A TO PART 195—DELINEATIONBETWEEN FEDERAL AND STATE JU-RISDICTION—STATEMENT OF AGENCYPOLICY AND INTERPRETATION

In 1979, Congress enacted comprehensivesafety legislation governing the transpor-tation of hazardous liquids by pipeline, theHazardous Liquids Pipeline Safety Act of1979, 49 U.S.C. 2001 et seq. (HLPSA). TheHLPSA expanded the existing statutory au-thority for safety regulation, which was lim-ited to transportation by common carriers ininterstate and foreign commerce, to trans-portation through facilities used in or affect-ing interstate or foreign commerce. It alsoadded civil penalty, compliance order, andinjunctive enforcement authorities to theexisting criminal sanctions. Modeled largelyon the Natural Gas Pipeline Safety Act of1968, 49 U.S.C. 1671 et seq. (NGPSA), theHLPSA provides for a national hazardousliquid pipeline safety program with nation-ally uniform minimal standards and with en-forcement administered through a Federal-State partnership. The HLPSA leaves to ex-clusive Federal regulation and enforcementthe ‘‘interstate pipeline facilities,’’ thoseused for the pipeline transportation of haz-ardous liquids in interstate or foreign com-merce. For the remainder of the pipeline fa-cilities, denominated ‘‘intrastate pipeline fa-cilities,’’ the HLPSA provides that the sameFederal regulation and enforcement willapply unless a State certifies that it will as-sume those responsibilities. A certified Statemust adopt the same minimal standards butmay adopt additional more stringent stand-ards so long as they are compatible. There-fore, in States which participate in the haz-ardous liquid pipeline safety programthrough certification, it is necessary to dis-tinguish the interstate from the intrastatepipeline facilities.

In deciding that an administratively prac-tical approach was necessary in distin-guishing between interstate and intrastate


167

Research and Special Programs Administration, DOT Pt. 195, App. A

liquid pipeline facilities and in determininghow best to accomplish this, DOT has logi-cally examined the approach used in theNGPSA. The NGPSA defines the interstategas pipeline facilities subject to exclusiveFederal jurisdiction as those subject to theeconomic regulatory jurisdiction of the Fed-eral Energy Regulatory Commission (FERC).Experience has proven this approach prac-tical. Unlike the NGPSA however, theHLPSA has no specific reference to FERC ju-risdiction, but instead defines interstate liq-uid pipeline facilities by the more commonlyused means of specifying the end points ofthe transportation involved. For example,the economic regulatory jurisdiction ofFERC over the transportation of both gasand liquids by pipeline is defined in much thesame way. In implementing the HLPSA DOThas sought a practicable means of distin-guishing between interstate and intrastatepipeline facilities that provide the requisitedegree of certainty to Federal and State en-forcement personnel and to the regulated en-tities. DOT intends that this statement ofagency policy and interpretation providethat certainty.

In 1981, DOT decided that the inventory ofliquid pipeline facilities identified as subjectto the jurisdiction of FERC approximatesthe HLPSA category of ‘‘interstate pipelinefacilities.’’ Administrative use of the FERCinventory has the added benefit of avoidingthe creation of a separate Federal scheme fordetermination of jurisdiction over the sameregulated entities. DOT recognizes that theFERC inventory is only an approximationand may not be totally satisfactory withoutsome modification. The difficulties stemfrom some significant differences in the eco-nomic regulation of liquid and of natural gaspipelines. There is an affirmative assertionof jurisdiction by FERC over natural gaspipelines through the issuance of certificatesof public convenience and necessity prior tocommencing operations. With liquid pipe-lines, there is only a rebuttable presumptionof jurisdiction created by the filing by pipe-line operators of tariffs (or concurrences) formovement of liquids through existing facili-ties. Although FERC does police the filingsfor such matters as compliance with the gen-eral duties of common carriers, the questionof jurisdiction is normally only aired uponcomplaint. While any person, includingState or Federal agencies, can avail them-selves of the FERC forum by use of the com-plaint process, that process has only beenrarely used to review jurisdictional matters(probably because of the infrequency of realdisputes on the issue). Where the issue hasarisen, the reviewing body has noted theneed to examine various criteria primarily ofan economic nature. DOT believes that, inmost cases, the formal FERC forum can bet-ter receive and evaluate the type of informa-

tion that is needed to make decisions of thisnature than can DOT.

In delineating which liquid pipeline facili-ties are interstate pipeline facilities withinthe meaning of the HLPSA, DOT will gen-erally rely on the FERC filings; that is, ifthere is a tariff or concurrence filed withFERC governing the transportation of haz-ardous liquids over a pipeline facility or ifthere has been an exemption from the obliga-tion to file tariffs obtained from FERC, thenDOT will, as a general rule, consider the fa-cility to be an interstate pipeline facilitywithin the meaning of the HLPSA. The typesof situations in which DOT will ignore theexistence or non-existence of a filing withFERC will be limited to those cases in whichit appears obvious that a complaint filedwith FERC would be successful or in whichblind reliance on a FERC filing would resultin a situation clearly not intended by theHLPSA such as a pipeline facility not beingsubject to either State or Federal safety reg-ulation. DOT anticipates that the situationsin which there is any question about the va-lidity of the FERC filings as a ready ref-erence will be few and that the actual vari-ations from reliance on those filings will berare. The following examples indicate thetypes of facilities which DOT believes areinterstate pipeline facilities subject to theHLPSA despite the lack of a filing withFERC and the types of facilities over whichDOT will generally defer to the jurisdictionof a certifying state despite the existence ofa filing with FERC.

Example 1. Pipeline company P operates apipeline from ‘‘Point A’’ located in State Xto ‘‘Point B’’ (also in X). The physical facili-ties never cross a state line and do not con-nect with any other pipeline which doescross a state line. Pipeline company P alsooperates another pipeline between ‘‘Point C’’in State X and ‘‘Point D’’ in an adjoiningState Y. Pipeline company P files a tariffwith FERC for transportation from ‘‘PointA’’ to ‘‘Point B’’ as well as for transpor-tation from ‘‘Point C’’ to ‘‘Point D.’’ DOTwill ignore filing for the line from ‘‘Point A’’to ‘‘Point B’’ and consider the line to beintrastate.

Example 2. Same as in example 1 exceptthat P does not file any tariffs with FERC.DOT will assume jurisdiction of the line be-tween ‘‘Point C’’ and ‘‘Point D.’’

Example 3. Same as in example 1 exceptthat P files its tariff for the line between‘‘Point C’’ and ‘‘Point D’’ not only withFERC but also with State X. DOT will relyon the FERC filing as indication of inter-state commerce.

Example 4. Same as in example 1 exceptthat the pipeline from ‘‘Point A’’ to ‘‘PointB’’ (in State X) connects with a pipeline op-erated by another company transports liquidbetween ‘‘Point B’’ (in State X) and ‘‘Point


168

49 CFR Ch. I (10–1–01 Edition)Pt. 195, App. B

D’’ (in State Y). DOT will rely on the FERCfiling as indication of interstate commerce.

Example 5. Same as in example 1 exceptthat the line between ‘‘Point C’’ and ‘‘PointD’’ has a lateral line connected to it. Thelateral is located entirely with State X. DOTwill rely on the existence or non-existence ofa FERC filing covering transportation overthat lateral as determinative of interstatecommerce.

Example 6. Same as in example 1 exceptthat the certified agency in State X hasbrought an enforcement action (under thepipeline safety laws) against P because of itsoperation of the line between ‘‘Point A’’ and‘‘Point B’’. P has successfully defendedagainst the action on jurisdictional grounds.DOT will assume jurisdiction if necessary toavoid the anomaly of a pipeline subject toneither State or Federal safety enforcement.DOT’s assertion of jurisdiction in such a casewould be based on the gap in the state’s en-forcement authority rather than a DOT deci-sion that the pipeline is an interstate pipe-line facility.

Example 7. Pipeline Company P operates apipeline that originates on the Outer Conti-nental Shelf. P does not file any tariff forthat line with FERC. DOT will consider thepipeline to be an interstate pipeline facility.

Example 8. Pipeline Company P is con-structing a pipeline from ‘‘Point C’’ (in StateX) to ‘‘Point D’’ (in State Y). DOT will con-sider the pipeline to be an interstate pipelinefacility.

Example 9. Pipeline company P is con-structing a pipeline from ‘‘Point C’’ to‘‘Point E’’ (both in State X) but intends tofile tariffs with FERC in the transportationof hazardous liquid in interstate commerce.Assuming there is some connection to aninterstate pipeline facility, DOT will con-sider this line to be an interstate pipeline fa-cility.

Example 10. Pipeline Company P has oper-ated a pipeline subject to FERC economicregulation. Solely because of some statutoryeconomic deregulation, that pipeline is nolonger regulated by FERC. DOT will con-tinue to consider that pipeline to be aninterstate pipeline facility.

As seen from the examples, the types ofsituations in which DOT will not defer to theFERC regulatory scheme are generally clear-cut cases. For the remainder of the situa-tions where variation from the FERC schemewould require DOT to replicate the forum al-ready provided by FERC and to consider eco-

nomic factors better left to that agency,DOT will decline to vary its reliance on theFERC filings unless, of course, not doing sowould result in situations clearly not in-tended by the HLPSA.

[Amdt. 195–33, 50 FR 15899, Apr. 23, 1985]

APPENDIX B TO PART 195—RISK-BASEDALTERNATIVE TO PRESSURE TESTINGOLDER HAZARDOUS LIQUID AND CAR-BON DIOXIDE PIPELINES

RISK-BASED ALTERNATIVE

This Appendix provides guidance on how arisk-based alternative to pressure testingolder hazardous liquid and carbon dioxidepipelines rule allowed by § 195.303 will work.This risk-based alternative establishes testpriorities for older pipelines, not previouslypressure tested, based on the inherent risk ofa given pipeline segment. The first step is todetermine the classification based on thetype of pipe or on the pipeline segment’sproximity to populated or environmentallysensitive area. Secondly, the classificationsmust be adjusted based on the pipeline fail-ure history, product transported, and the re-lease volume potential.

Tables 2–6 give definitions of risk classi-fication A, B, and C facilities. For the pur-poses of this rule, pipeline segments con-taining high risk electric resistance-weldedpipe (ERW pipe) and lapwelded pipe manufac-tured prior to 1970 and considered a risk clas-sification C or B facility shall be treated asthe top priority for testing because of thehigher risk associated with the suscepti-bility of this pipe to longitudinal seam fail-ures.

In all cases, operators shall annually, atintervals not to exceed 15 months, reviewtheir facilities to reassess the classificationand shall take appropriate action within twoyears or operate the pipeline system at alower pressure. Pipeline failures, changes inthe characteristics of the pipeline route, orchanges in service should all trigger a reas-sessment of the originally classification.

Table 1 explains different levels of test re-quirements depending on the inherent risk ofa given pipeline segment. The overall riskclassification is determined based on thetype of pipe involved, the facility’s location,the product transported, the relative volumeof flow and pipeline failure history as deter-mined from Tables 2–6.

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

Pipeline segment Risk classification Test deadline 1 Test medium

Pre-1970 Pipeline Segments susceptible to longitu-dinal seam failures 2.

C or BA

12/7/2000 3 ...............................12/7/2002 3 ...............................

Water only.Water only.

All Other Pipeline Segments ......................................... C 12/7/2002 4 ............................... Water only.B 12/7/2004 4 ............................... Water/Liq.5


169

Research and Special Programs Administration, DOT Pt. 195, App. B

TABLE 1. TEST REQUIREMENTS—MAINLINE SEGMENTS OUTSIDE OF TERMINALS, STATIONS, AND TANKFARMS—Continued

Pipeline segment Risk classification Test deadline 1 Test medium

A Additional pressure testing notrequired.

1 If operational experience indicates a history of past failures for a particular pipeline segment, failure causes (time-dependentdefects 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 informationas available, which may include the pipe steel’s mechanical properties, including fracture toughness; the manufacturing processand controls related to seam properties, including whether the ERW process was high-frequency or low-frequency, whether theweld seam was heat treated, whether the seam was inspected, the test pressure and duration during mill hydrotest; the qualitycontrol 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 besupported by an assessment of hazards in accordance with location, product, volume, and probability of failure considerationsconsistent 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 whereleak 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,and FAILURE HISTORY ‘‘Indicators’’ fromTables 3, 4, 5, and 6 respectively, the overallrisk classification of a given pipeline or pipe-line segment can be established from Table2. The LOCATION Indicator is the primary

factor which determines overall risk, withthe PRODUCT, VOLUME, and PROB-ABILITY OF FAILURE Indicators used toadjust to a higher or lower overall risk clas-sification per the following table.

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 ClassificationC .............................................. 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 LOCATIONIndicator used in Table 2. Based on the popu-lation and environment characteristics asso-

ciated with a pipeline facility’s location, aLOCATION Indicator of H, M or L is se-lected.

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 thePRODUCT, VOLUME, and PROBABILITYOF FAILURE Indicators respectively, inTable 2. The PRODUCT Indicator is selectedfrom Table 4 as H, M, or L based on the acuteand chronic hazards associated with the

product transported. The VOLUME Indicatoris selected from Table 5 as H, M, or L basedon the nominal diameter of the pipeline. TheProbability of Failure Indicator is selectedfrom Table 6.

TABLE 4—PRODUCT INDICATORS

Indicator Considerations Product examples

H ................................................................ (Highly volatile and flammable) ............... (Propane, butane, Natural Gas Liquid(NGL), ammonia)


170

49 CFR Ch. I (10–1–01 Edition)Pt. 195, App. C

TABLE 4—PRODUCT INDICATORS—Continued

Indicator Considerations Product examples

Highly toxic .............................................. (Benzene, high Hydrogen Sulfide con-tent crude oils).

M ................................................................ Flammable—flashpoint <100F ................ (Gasoline, JP4, low flashpoint crudeoils).

L ................................................................. Non-flammable—flashpoint 100+F .......... (Diesel, fuel oil, kerosene, JP5, mostcrude oils).

Highly volatile and non-flammable/non-toxic.

Carbon Dioxide.

Considerations: The degree of acute andchronic toxicity to humans, wildlife, andaquatic life; reactivity; and, volatility, flam-mability, and water solubility determine theProduct Indicator. Comprehensive Environ-mental Response, Compensation and Liabil-ity Act Reportable Quantity values can beused as an indication of chronic toxicity. Na-tional Fire Protection Association healthfactors can be used for rating acute hazards.

TABLE 5—VOLUME INDICATORS

Indicator Line size

H .................. ≥18″.M ................. 10″–16″ nominal diameters.L .................. ≤8″ nominal diameter.

H=High M=Moderate L=Low.

Table 6 is used to establish the PROB-ABILITY OF FAILURE Indicator used inTable 2. The ‘‘Probability of Failure’’ Indi-cator is selected from Table 6 as H or L.

TABLE 6—PROBABILITY OF FAILURE INDICATORS[in each haz. location]

Indicator Failure history (time-dependent defects) 2

H 1 ................ >Three spills in last 10 years.L .................. ≤Three spills in last 10 years.

H=High L=Low.1 Pipeline segments with greater than three product spills in

the last 10 years should be reviewed for failure causes as de-scribed in subnote 2. The pipeline operator should make anappropriate investigation and reach a decision based onsound engineering judgment, and be able to demonstrate thebasis of the decision.

2 Time-Dependent Defects are defects that result in spillsdue to corrosion, gouges, or problems developed during man-ufacture, construction or operation, etc.

[Amdt. 195–65, 63 FR 59480, Nov. 4, 1998; 64 FR6815, Feb. 11, 1999]

APPENDIX C TO PART 195—GUIDANCE FORIMPLEMENTATION OF INTEGRITYMANAGEMENT PROGRAM

This Appendix gives guidance to help anoperator implement the requirements of theintegrity management program rule in§§ 195.450 and 195.452. Guidance is provided on:

(1) Information an operator may use toidentify a high consequence area and factors

an operator can use to consider the potentialimpacts of a release on an area;

(2) Risk factors an operator can use to de-termine an integrity assessment schedule;

(3) Safety risk indicator tables for leakhistory, volume or line size, age of pipeline,and product transported, an operator mayuse to determine if a pipeline segment fallsinto a high, medium or low risk category;

(4) Types of internal inspection tools anoperator could use to find pipeline anoma-lies;

(5) Measures an operator could use tomeasure an integrity management program’sperformance; and

(6) Types of records an operator will haveto maintain.

I. Identifying a high consequence area andfactors for considering a pipeline segment’spotential impact on a high consequence area.

A. The rule defines a High ConsequenceArea as a high population area, an other pop-ulated area, an unusually sensitive area, or acommercially navigable waterway. The Of-fice of Pipeline Safety (OPS) will map theseareas on the National Pipeline Mapping Sys-tem (NPMS). An operator, member of thepublic, or other government agency mayview and download the data from the NPMShome page http://www.npms.rspa.dot.gov.OPS will maintain the NPMS and update itperiodically. However, it is an operator’s re-sponsibility to ensure that it has identifiedall high consequence areas that could be af-fected by a pipeline segment. An operator isalso responsible for periodically evaluatingits pipeline segments to look for populationor environmental changes that may have oc-curred around the pipeline and to keep itsprogram current with this information.(Refer to § 195.452(d)(3).) For more informa-tion to help in identifying high consequenceareas, an operator may refer to:

(1) Digital Data on populated areas avail-able on U.S. Census Bureau maps.

(2) Geographic Database on the commer-cial navigable waterways available on http://www.bts.gov/gis/ntatlas/networks.html.

(3) The Bureau of Transportation Statis-tics database that includes commerciallynavigable waterways and non-commerciallynavigable waterways. The database can be


171

Research and Special Programs Administration, DOT Pt. 195, App. C

downloaded from the BTS website at http://www.bts.gov/gis/ntatlas/networks.html.

B. The rule requires an operator to includea process in its program for identifyingwhich pipeline segments could affect a highconsequence area and to take measures toprevent and mitigate the consequences of apipeline failure that could affect a high con-sequence area. (See §§ 195.452 (f) and (i).)Thus, an operator will need to consider howeach pipeline segment could affect a highconsequence area. The primary source forthe listed risk factors is a US DOT study oninstrumented Internal Inspection devices(November 1992). Other sources include theNational Transportation Safety Board, theEnvironmental Protection Agency and theTechnical Hazardous Liquid Pipeline SafetyStandards Committee. The following listprovides guidance to an operator on both themandatory and additional factors:

(1) Terrain surrounding the pipeline. Anoperator should consider the contour of theland profile and if it could allow the liquidfrom a release to enter a high consequencearea. An operator can get this informationfrom topographical maps such as U.S. Geo-logical Survey quadrangle maps.

(2) Drainage systems such as small streamsand other smaller waterways that couldserve as a conduit to a high consequencearea.

(3) Crossing of farm tile fields. An operatorshould consider the possibility of a spillagein the field following the drain tile into awaterway.

(4) Crossing of roadways with ditches alongthe side. The ditches could carry a spillageto a waterway.

(5) The nature and characteristics of theproduct the pipeline is transporting (refinedproducts, crude oils, highly volatile liquids,etc.) Highly volatile liquids becomes gaseouswhen exposed to the atmosphere. A spillagecould create a vapor cloud that could settleinto the lower elevation of the ground pro-file.

(6) Physical support of the pipeline seg-ment such as by a cable suspension bridge.An operator should look for stress indicatorson the pipeline (strained supports, inad-equate support at towers), atmospheric cor-rosion, vandalism, and other obvious signs ofimproper maintenance.

(7) Operating condition of pipeline (pres-sure, flow rate, etc.) Exposure of the pipelineto operating pressure exceeding establishedmaximum operating pressure.

(8) The hydraulic gradient of pipeline.(9) The diameter of pipeline, the potential

release volume, and the distance between theisolation points.

(10) Potential physical pathways betweenthe pipeline and the high consequence area.

(11) Response capability (time to respond,nature of response).

(12) Potential natural forces inherent inthe area (flood zones, earthquakes, subsid-ence areas, etc.)

II. Risk factors for establishing frequencyof assessment.

A. By assigning weights or values to therisk factors, and using the risk indicator ta-bles, an operator can determine the priorityfor assessing pipeline segments, beginningwith those segments that are of highest risk,that have not previously been assessed. Thislist provides some guidance on some of therisk factors to consider (see § 195.452(e)). Anoperator should also develop factors specificto each pipeline segment it is assessing, in-cluding:

(1) Populated areas, unusually sensitive en-vironmental areas, National Fish Hatcheries,commercially navigable waters, areas wherepeople congregate.

(2) Results from previous testing/inspec-tion. (See § 195.452(h).)

(3) Leak History. (See leak history risktable.)

(4) Known corrosion or condition of pipe-line. (See § 195.452(g).)

(5) Cathodic protection history.(6) Type and quality of pipe coating

(disbonded coating results in corrosion).(7) Age of pipe (older pipe shows more cor-

rosion—may be uncoated or have an ineffec-tive coating) and type of pipe seam. (See Ageof Pipe risk table.)

(8) Product transported (highly volatile,highly flammable and toxic liquids present agreater threat for both people and the envi-ronment) (see Product transported risktable.)

(9) Pipe wall thickness (thicker walls givea better safety margin)

(10) Size of pipe (higher volume release ifthe pipe ruptures).

(11) Location related to potential groundmovement (e.g., seismic faults, rock quar-ries, and coal mines); climatic (permafrostcauses settlement—Alaska); geologic (land-slides or subsidence).

(12) Security of throughput (effects on cus-tomers if there is failure requiring shut-down).

(13) Time since the last internal inspection/pressure testing.

(14) With respect to previously discovereddefects/anomalies, the type, growth rate, andsize.

(15) Operating stress levels in the pipeline.(16) Location of the pipeline segment as it

relates to the ability of the operator to de-tect and respond to a leak. (e.g., pipelinesdeep underground, or in locations that makeleak detection difficult without specific sec-tional monitoring and/or significantly im-pede access for spill response or any otherpurpose).

(17) Physical support of the segment suchas by a cable suspension bridge.


172


(18) Non-standard or other than recognizedindustry practice on pipeline installation(e.g., horizontal directional drilling).

B. Example: This example illustrates a hy-pothetical model used to establish an integ-rity assessment schedule for a hypotheticalpipeline segment. After we determine therisk factors applicable to the pipeline seg-ment, we then assign values or numbers toeach factor, such as, high (5), moderate (3),or low (1). We can determine an overall riskclassification (A, B, C) for the segment usingthe risk tables and a sliding scale (values 5to 1) for risk factors for which tables are notprovided. We would classify a segment as C ifit fell above 2⁄3 of maximum value (highestoverall risk value for any one segment whencompared with other segments of a pipeline),a segment as B if it fell between 1⁄3 to 2⁄3 ofmaximum value, and the remaining seg-ments as A.

i. For the baseline assessment schedule, wewould plan to assess 50% of all pipeline seg-ments covered by the rule, beginning withthe highest risk segments, within the first31⁄2 years and the remaining segments withinthe seven-year period. For the continuing in-tegrity assessments, we would plan to assessthe C segments within the first two (2) yearsof the schedule, the segments classified asmoderate risk no later than year three orfour and the remaining lowest risk segmentsno later than year five (5).

ii. For our hypothetical pipeline segment,we have chosen the following risk factorsand obtained risk factor values from the ap-propriate table. The values assigned to therisk factors are for illustration only.Age of pipeline: assume 30 years old (refer to

‘‘Age of Pipeline’’ risk table)—Risk Value=5Pressure tested: tested once during construc-

tion—Risk Value=5Coated: (yes/no)—yesCoating Condition: Recent excavation of sus-

pected areas showed holidays in coating(potential corrosion risk)—

Risk Value=5Cathodically Protected: (yes/no)—yes—Risk

Value=1Date cathodic protection installed: five years

after pipeline was constructed (Cathodicprotection installed within one year ofthe pipeline’s construction is generallyconsidered low risk.)—Risk Value=3

Close interval survey: (yes/no)—no—RiskValue =5

Internal Inspection tool used: (yes/no)—yes.Date of pig run? In last five years—RiskValue=1

Anomalies found: (yes/no)—yes, but do notpose an immediate safety risk or envi-ronmental hazard—Risk Value=3

Leak History: yes, one spill in last 10 years.(refer to ‘‘Leak History’’ risk table)—Risk Value=2

Product transported: Diesel fuel. Product lowrisk. (refer to ‘‘Product’’ risk table)—Risk Value=1

Pipe size: 16 inches. Size presents moderaterisk (refer to ‘‘Line Size’’ risk table)—Risk Value=3

iii. Overall risk value for this hypotheticalsegment of pipe is 34. Assume we have twoother pipeline segments for which we con-duct similar risk rankings. The second pipe-line segment has an overall risk value of 20,and the third segment, 11. For the baselineassessment we would establish a schedulewhere we assess the first segment (highestrisk segment) within two years, the secondsegment within five years and the third seg-ment within seven years. Similarly, for thecontinuing integrity assessment, we couldestablish an assessment schedule where weassess the highest risk segment no later thanthe second year, the second segment no laterthan the third year, and the third segmentno later than the fifth year.

III. Safety risk indicator tables for leakhistory, volume or line size, age of pipeline,and product transported.

LEAK HISTORY

Safety riskindicator

Leak history(Time-dependent defects) 1

High .......................... > 3 Spills in last 10 yearsLow ........................... < 3 Spills in last 10 years

1 Time-dependent defects are those that result in spills dueto corrosion, gouges, or problems developed during manufac-ture, construction or operation, etc.

LINE SIZE OR VOLUME TRANSPORTED

Safety riskindicator Line size

High .......................... ≥ 18′Moderate .................. 10′—16′ nominal diametersLow ........................... ≤ 8′ nominal diameter

AGE OF PIPELINE

Safety riskindicator

Age Pipeline conditiondependent) 1

High .......................... > 25 yearsLow ........................... < 25 years

1 Depends on pipeline’s coating & corrosion condition, andsteel quality, toughness, welding.


173

Rese

arc

h and

Spe

cia

l Prog

ram

s Ad

ministra

tion, D

OT

Pt. 195, Ap

p. C

PRODUCT TRANSPORTED

Safety riskindicator Considerations 1 Product examples

High ......................... (Highly volatile and flammable) ................................................................................. (Propane, butane, Natural Gas Liquid (NGL), ammonia).Highly toxic ................................................................................................................ (Benzene, high Hydrogen Sulfide content crude oils).

Medium ................... Flammable—flashpoint <100F .................................................................................. (Gasoline, JP4, low flashpoint crude oils).Low ......................... Non-flammable—flashpoint 100+F ............................................................................ (Diesel, fuel oil, kerosene, JP5, most crude oils).

1 The degree of acute and chronic toxicity to humans, wildlife, and aquatic life; reactivity; and, volatility, flammability, and water solubility determine the Product Indicator. ComprehensiveEnvironmental Response, Compensation and Liability Act Reportable Quantity values may be used as an indication of chronic toxicity. National Fire Protection Association health factorsmay be used for rating acute hazards.

VerD

ate 11<M

AY

>2000

12:25 Nov 06, 2001

Jkt 194202P

O 00000

Frm

00173F

mt 8010

Sfm

t 8002Y

:\SG

ML\194202T

.XX

Xpfrm

01P

sN: 194202T

174


IV. Types of internal inspection tools touse.

An operator should consider at least twotypes of internal inspection tools for the in-tegrity assessment from the following list.The type of tool or tools an operator selectswill depend on the results from previous in-ternal inspection runs, information analysisand risk factors specific to the pipeline seg-ment:

(1) Geometry Internal inspection tools fordetecting changes to ovality, e.g., bends,dents, buckles or wrinkles, due to construc-tion flaws or soil movement, or other outsideforce damage;

(2) Metal Loss Tools (Ultrasonic and Mag-netic Flux Leakage) for determining pipewall anomalies, e.g., wall loss due to corro-sion.

(3) Crack Detection Tools for detectingcracks and crack-like features, e.g., stresscorrosion cracking (SCC), fatigue cracks,narrow axial corrosion, toe cracks, hookcracks, etc.

V. Methods to measure performance.A. General. (1) This guidance is to help an

operator establish measures to evaluate theeffectiveness of its integrity managementprogram. The performance measures re-quired will depend on the details of each in-tegrity management program and will bebased on an understanding and analysis ofthe failure mechanisms or threats to integ-rity of each pipeline segment.

(2) An operator should select a set of meas-urements to judge how well its program isperforming. An operator’s objectives for itsprogram are to ensure public safety, preventor minimize leaks and spills and preventproperty and environmental damage. A typ-ical integrity management program will bean ongoing program and it may containmany elements. Therefore, several perform-ance measure are likely to be needed tomeasure the effectiveness of an ongoing pro-gram.

B. Performance measures. These measuresshow how a program to control risk on pipe-line segments that could affect a high con-sequence area is progressing under the integ-rity management requirements. Perform-ance measures generally fall into three cat-egories:

(1) Selected Activity Measures—Measuresthat monitor the surveillance and preventiveactivities the operator has implemented.These measure indicate how well an operatoris implementing the various elements of itsintegrity management program.

(2) Deterioration Measures—Operation andmaintenance trends that indicate when theintegrity of the system is weakening despitepreventive measures. This category of per-formance measure may indicate that the sys-tem condition is deteriorating despite wellexecuted preventive activities.

(3) Failure Measures—Leak History, inci-dent response, product loss, etc. These meas-ures will indicate progress towards fewerspills and less damage.

C. Internal vs. External Comparisons. Thesecomparisons show how a pipeline segmentthat could affect a high consequence area isprogressing in comparison to the operator’sother pipeline segments that are not coveredby the integrity management requirementsand how that pipeline segment compares toother operators’ pipeline segments.

(1) Internal—Comparing data from thepipeline segment that could affect the highconsequence area with data from pipelinesegments in other areas of the system mayindicate the effects from the attention givento the high consequence area.

(2) External—Comparing data external tothe pipeline segment (e.g., OPS incidentdata) may provide measures on the fre-quency and size of leaks in relation to othercompanies.

D. Examples. Some examples of perform-ance measures an operator could use in-clude—

(1) A performance measurement goal to re-duce the total volume from unintended re-leases by -% (percent to be determined by op-erator) with an ultimate goal of zero.

(2) A performance measurement goal to re-duce the total number of unintended releases(based on a threshold of 5 gallons) by ll-%(percent to be determined by operator) withan ultimate goal of zero.

(3) A performance measurement goal todocument the percentage of integrity man-agement activities completed during the cal-endar year.

(4) A performance measurement goal totrack and evaluate the effectiveness of theoperator’s community outreach activities.

(5) A narrative description of pipeline sys-tem integrity, including a summary of per-formance improvements, both qualitativeand quantitative, to an operator’s integritymanagement program prepared periodically.

(6) A performance measure based on inter-nal audits of the operator’s pipeline systemper 49 CFR Part 195.

(7) A performance measure based on exter-nal audits of the operator’s pipeline systemper 49 CFR Part 195.

(8) A performance measure based on oper-ational events (for example: relief occur-rences, unplanned valve closure, SCADA out-ages, etc.) that have the potential to ad-versely affect pipeline integrity.

(9) A performance measure to demonstratethat the operator’s integrity managementprogram reduces risk over time with a focuson high risk items.

(10) A performance measure to dem-onstrate that the operator’s integrity man-agement program for pipeline stations andterminals reduces risk over time with afocus on high risk items.


175


VI. Examples of types of records an oper-ator must maintain.

The rule requires an operator to maintaincertain records. (See § 195.452(l)). This sectionprovides examples of some records that anoperator would have to maintain for inspec-tion to comply with the requirement. This isnot an exhaustive list.

(1) a process for identifying which pipelinescould affect a high consequence area and adocument identifying all pipeline segmentsthat could affect a high consequence area;

(2) a plan for baseline assessment of theline pipe that includes each required planelement;

(3) modifications to the baseline plan andreasons for the modification;

(4) use of and support for an alternativepractice;

(5) a framework addressing each requiredelement of the integrity management pro-gram, updates and changes to the initialframework and eventual program;

(6) a process for identifying a new highconsequence area and incorporating it intothe baseline plan, particularly, a process foridentifying population changes around apipeline segment;

(7) an explanation of methods selected toassess the integrity of line pipe;

(8) a process for review of integrity assess-ment results and data analysis by a personqualified to evaluate the results and data;

(9) the process and risk factors for deter-mining the baseline assessment interval;

(10) results of the baseline integrity assess-ment;

(11) the process used for continual evalua-tion, and risk factors used for determiningthe frequency of evaluation;

(12) process for integrating and analyzinginformation about the integrity of a pipe-line, information and data used for the infor-mation analysis;

(13) results of the information analyses andperiodic evaluations;

(14) the process and risk factors for estab-lishing continual re-assessment intervals;

(15) justification to support any variancefrom the required re-assessment intervals;

(16) integrity assessment results and anom-alies found, process for evaluating and re-pairing anomalies, criteria for repair actionsand actions taken to evaluate and repair theanomalies;

(17) other remedial actions planned ortaken;

(18) schedule for reviewing and analyzingintegrity assessment results;

(19) schedule for evaluation and repair ofanomalies, justification to support deviationfrom required repair times;

(20) risk analysis used to identify addi-tional preventive or mitigative measures,records of preventive and mitigative actionsplanned or taken;

(21) criteria for determining EFRD instal-lation;

(22) criteria for evaluating and modifyingleak detection capability;

(23) methods used to measure the pro-gram’s effectiveness.

[Amdt. 195–70, 65 FR 75409, Dec. 1, 2000]

PARTS 196–197—[RESERVED]

PART 198—REGULATIONS FORGRANTS TO AID STATE PIPELINESAFETY PROGRAMS

Subpart A—General

Sec.198.1 Scope.198.3 Definitions.

Subpart B—Grant Allocation

198.11 Grant authority.198.13 Grant allocation formula.

Subpart C—Adoption of One-Call DamagePrevention Program

198.31 Scope.198.33 [Reserved]198.35 Grants conditioned on adoption of

one-call damage prevention program.198.37 State one-call damage prevention

program.198.39 Qualifications for operation of one-

call notification system.

AUTHORITY: 49 U.S.C. 60105, 60106, 60114; and49 CFR 1.53.

SOURCE: 55 FR 38691, Sept. 20, 1990, unlessotherwise noted.

Subpart A—General

§ 198.1 Scope.This part prescribes regulations gov-

erning grants-in-aid for State pipelinesafety compliance programs.

§ 198.3 Definitions.As used in this part:Adopt means establish under State

law by statute, regulation, license, cer-tification, order, or any combination ofthese legal means.

Excavation activity means an exca-vation activity defined in § 192.614(a) ofthis chapter, other than a specific ac-tivity the State determines would notbe expected to cause physical damageto underground facilities.
