33388 Federal Register / Vol. 59, No. 123 / Tuesday, June 28, 1994 / Rules and Regulations

DEPARTMENT OF TRANSPORTATION

Research and Special ProgramsAdministration

49 CFR Part 195

[Docket PS-127; Amdt. 19542]

RIN 2137-AC27

Regulatory Review: Hazardous Liquidand Carbon Dioxide Pipeline SafetyStandards

AGENCY: Research and Special ProgramsAdministration (RSPA), DOT.ACTION: Final rule.

SUMMARY: This rulemaking amendsmiscellaneous hazardous liquid andcarbon dioxide pipeline safety standardsto provide clarity, eliminateunnecessary or overly burdensomerequirements, and foster economicgrowth. The changes result from theregulatory review RSPA carried out inresponse to the President's directive ofJanuary 28, 1992, on reducing theburden of government regulation. Thechanges reduce costs in the liquidpipeline industry withoutcompromising safety.EFFECTIVE DATE: This regulation iseffective July 28, 1994. Theincorporation by reference of certainpublications listed in the regulations isapproved by the Director of the FederalRegister as of July 28, 1994.FOR FURTHER INFORMATION CONTACT: J.Willock, (202) 366-2392, regarding thesubject matter of this final rulemaking,or the Dockets Unit, (202) 366-5046,regarding copies of this final rulemakingor other material that is referencedherein.

SUPPLEMENTARY INFORMATION:.Background

In a January 28, 1992, memorandum,the President wrote to Department andagency heads about the need to reducethe burden imposed by governmentregulation. The President wasconcerned that agencies were not doingenough to review and revise existingregulations to eliminate unnecessaryand overly burdensome requirements.The President recognized thatregulations that do,not keep pace withnew technologies and innovationsimpose needless costs and impedeeconomic growth.

In response to the President'smemorandum, DOT published a noticerequesting public comment on theDepartment's regulatory. programs (57FR 4745; Feb. 7, 1992). Commenterswere asked to identify regulations thatsubstantially impede economic growth,

may no longer be necessary, areunnecessarily burdensome, imposeneedless costs or red tape, or overlap orconflict with other DOT or federal'regulations. The deadline for submittingcomments was March 2, 1992.

RSPA received comments from sixorganizations about the pipeline safetyregulations in part 195. Comments werefrom three regulated pipelinecompanies, a pipeline trade association,a state pipeline safety agency, and afederal agency. RSPA considered allcomments in its review of theregulations, and these comments areavailable in the docket. Some commentswill be considered in futurerulemakings. Additionally, RSPA haspublished a separate rulemaking"Update of Standards Incorporated byReference" (58 FR 14519; March 18,1993) which updates the editions of theindustry standards that are incorporatedin part 195.

On November 27, 1992, RSPApublished a Notice of ProposedRulemaking; NPRM, (57 FR 56304)proposing 18 changes to the regulationsbased on the comments received fromthe public and asked for furthercomments regarding the proposedchanges. RSPA received comments from21 organizations: 15 pipelinecompanies, 3 pipeline tradeassociations, 2 environmentalorganizations, and 1 countygovernment. RSPA considered allcomments in preparation of the finalrulemaking and the comments areavailable in the Docket.

Advisory Committee

The Technical Hazardous LiquidPipeline Safety Standards Committee(THLPSSC), consisting of 15 members,was established by statute to considerthe feasibility, reasonableness, andpracticability of proposed pipelineregulations. RSPA implemented thecommittee balloting process by mail.After initial balloting, the processallowed each member to review theballots, including comments, of all othermembers, and to change his or her voteor initial comment if desired. Althoughsome THLPSSC members did not voteon every proposed change, a tally of thesecond ballots showed that a largemajority of THLPSSC members foundall the proposed changes technicallyfeasible, reasonable, and practicable.Nonetheless, in developing the finalregulations, RSPA considered all finalTHLPSSC votes and comments,including minority positions. Thefollowing discussion explains howRSPA treated THLPSSC positions andpublic comments on the proposed

amendments in developing the finalrule.

Changes to Part 195 Safety Standards

The following discussion explains thechanges to various standards in part'195: -b

Section 195.1 Applicability.

Offshore production. Part 195 doesnot apply to pipelines used in offshoreproduction, whether on the OuterContinental Shelf or in state offshorewaters. However, this exception isclearly statedin part 195 only forproduction on the Outer ContinentalShelf (§ 195.1(b)(5)). To clarify that alloffshore pipelines used in productionare outside part 195, RSPA proposed todelete from § 195.1(b)(5) the phrase "onthe Outer Continental Shelf'.

The 10 THLPSSC members who votedon the proposed amendment to§ 195.1(b)(5) all approved theamendment.

In addition, RSPA received commentsfrom three operators and two pipeline-related associations in support of theamendment and no adverse comments.Therefore, § 195.1(b)(5) is amended asproposed in the NPRM.

We also requested comments on-whether-there is a gap in the regulationof production lines in state offshorewaters. Only one commenter responded.This commenter opined that existingstate and federal programs adequatelyregulate production lines in statewaters. In Louisiana, the Departments ofNatural Resources and EnvironmentalQuality were said to havecomprehensive regulations on facilityinstallation, operation, integrity, andremoval, and sufficient authority toaddress any "gap" that is identified.Since the other states with production-lines in state waters have similarregulations, RSPA does not believe thereis a gap in the regulation of productionlines in state waters.

In-plant piping. Part 195 does notapply to pipeline transportation throughonshore production, refining, ormanufacturing facilities, or storage orin-plant piping systems associated withsuch facilities ( 195.1(b)(6)). Becausethe physical distinction between aregulated pipeline serving a plant and-unregulated in-plant piping is unclear,RSPA proposed to add a definition of"in-plant'piping system" to § 195.2. Thedefinition proposed was: '"Iiplantpiping system means piping that islocated on the grounds of a plant andused to transfer hazardous liquid orcarbon dioxide between plant facilitiesor between plant facilities and apipeline, not including any device andassociated piping that are necessary to

Federal Register./ Vol. 59, No. 123 / Tuesday, June 28, 1994 / Rules and Regulations

control pressure in the pipeline." TheNPRM explained that we wouldconsider in-plant piping to extend to theplant boundary in the absence of anecessary pressure control device onplant grounds.

All ten THLPSSC members who votedon this proposal supported it. However,four members believed that because theNPRM primarily concerned pipelinetransportation rather than production,refining, or manufacturing plants, it didnot give- plant owners adequate noticethat the proposed definition could affectplant piping. These members wantedRSPA to publish a separate NPRM onthe subject of in-plant piping.

RSPA does not agree that anotherNPRM is needed. The subject of in-plantpiping and the associated issues wereclearly discussed in the publishedNPRM. Also, all interested persons,including plant owners as well aspipeline operators, were given anopportunity to comment on the subjectof in-plant piping.

RSPA received comments on theproposed definition from sevenoperators, two pipeline-relatedassociations, and one state agency. Twooperators and one association fullysupported the proposal.

One operator and a pipeline-relatedassociation thought plant owners werenot adequately notified of the proposedrule, and that RSPA should treat thesubject in a separate NPRM. Ourposition on this issue is given supra inresponse to a similar criticism by fourTHLPSSC members.

Another operator was concerned thatthe proposed definition would causeoperator-owned components, such aspipe, meters, instruments, andmanifolds, that are located on plantgrounds downstream from the operator'spressure control device to fall outsidepart 195. The operator was worried thatother agencies would regulate thesecomponents as non-transportationrelated facilities. We are not persuaded,however, that the potential for suchregulation is-sufficient reason to excludethe components from the definition ofinplant piping system. The aim of theproposed definition was to distinguishunregulated piping, not to limit the'jurisdiction of other governmentagencies.

In contrast, an operator of gatheringand processing facilities was concernedthat part 195 would apply to plantpiping that lies between anynecessarypressure control device and theconnection to a pipeline. Thiscommenter apparently did not realizethat such piping is subject to part 195.RSPA has applied part 195 to such-piping because, it is subject to pressure

which is controlled by a-deviceoperators must have to meet§ 195.406(b). However, this applicationhas had little effect on plant owners,because we hold the pipeline operator,not the plant owner, responsible forcompliance.

An-operator commenting on the plantdevice exclusion in the proposeddefinition advised us to change "controlpressure" to "prevent overpressure."This commenter said the change wouldavoid making pipeline operatorsresponsible under part 195 forponessential pressure control devices.We agree the suggested rewordingwould better convey the intent of theproposal. But, in the final definition, wehave changed "control pressure in thepipeline" to "control pressure in thepipeline under § 195.406(b)" to conveythe intent even more precisely.

The state agency commented that ifpiping on plant grounds does notinclude a device necessary to controlpipeline pressure, the jurisdiction ofpart 195 over the pipeline should notend at the plant boundary. Instead, thestate agency recommended endingjurisdiction at a component inside theplant, such as a flange, where thepipeline can be isolated for purposes oftesting. Although operators may usesuch components, part 195 does notrequire that they be on the pipeline.Also, we believe the plant boundary isa more convenient demarcation of in-plant piping than an unspecific inside-the-plant component. Thus, the stateagency's comment is not incorporated inthe final definition.

The state agency, an operator, and apipeline-related association wereconcerned that because segments oftransfer piping located off plant groundswere not included in the proposeddefinition, a large number of shortpipelines would come under part 195.RSPA recognizes that production,refining, or manufacturing plants ofteninstall transfer piping off plant grounds.A plant may use this piping to transferhazardous liquids between its differentfacilities located on the same grounds;between its different facilities locatedon separate grounds (usually separatedby a roadway, railway, waterway, or'industrial area); between its facilitiesand a transportation system, such as arailroad or pipeline; or between itsfacilities and the facilities of anotherplant or industrial consumer. The threecommenters thought the off-groundssegments should qualify as in-plantpiping if they connect facilities of thesame plant. The association 'also wantedto include under the definition off- -grounds segments that connect facilitiesof different plants. In addition, the

operator and association argued that theoff-grounds segments pose minimumrisk to public safety and theenvironment, because the segmentsgenerally are located'in industrial areas,roadways, or railways. The associationfurther argued that a plant has the sameoperational control, including responsecapability, over the off-groundssegments as it does over piping on plantgrounds.

In response to these comments, wenote that § 195.1(b)(6) echoes section201(3) of the Hazardous Liquid PipelineSafety Act of 1979 (HLPSA), (49 U.S.C.app. 2001(3)), which excludes certain"in-plant piping systems" fromregulation under the HLPSA. Sinceneither the HLPSA nor its legislativehistory explain "in-plant piping," weadopt an ordinary, reasonableunderstanding of the term. Therefore,we do not-accept the interpretation thatthe term includes piping that crosses theproperty of others outside plantgrounds. However, many plants areseparated by a public thoroughfare, andplant transfer piping crosses thethoroughfare. A single publicthoroughfare would include any road,from a country lane to an interstatehighway, but it does not include arailroad. Because transfer piping thatcrosses such thoroughfares iscomparable in most respects to other in-plant piping, RSPA considers the in-plant piping exception to include thethoroughfare crossings. Thethoroughfare exception does not applyto inter-facility lines or delivery lines,because these lines are distinct from in-plant piping. We did not intend theproposed definition of "in-plant pipingsystems" to expand our presentinterpretation of the term. So the final'definition does not incorporate any ofthe comments concerning pipinglocated off plant grounds other than forthoroughfare crossings.

However; the proposed definition'sfirst use of the term "pipeline" ischanged to "pipeline or other mode oftransportation." This change is needed.to include, within the definition, pipingon plant grounds that transfer hazardousliquid or carbon dioxide between plantfacilities and modes of transportationother than pipeline.

Terminal facilities. Part 195 does notapply to the transportation of hazardousliquid or carbon dioxide by vessel,aircraft, tank truck, tank car, or othervehicle, or by terminal facilities usedexclusively to transfer hazardous liquidor carbon dioxide between such modesof transportation (§ 195.1(b)(7)). RSPAproposed to amend § 195.1(b)(7) toclarify that terminal facilities located offterminal grounds are subject to part 195,

.33389

33390 Federal Register / Vol. 59, No. 123, / Tuesday; June 28, 1994 /I Rules and Regulations

and to distinguish unregulated terminalfacilities from a regulated pipelineentering or leaving the terminal. As withthe proposed in-plant piping definition,any device and associated piping onterminal grounds necessary to controlpressure in a regulated pipeline wouldnot be excepted from part 195.

The THLPSSC voted to approve thisproposal, but four members believed theNPRM did not give terminal ownersadequate notice that the proposedamendment could affect their piping.These members wanted RSPA topublish a separate NPRM on the subject.For the reasons stated supra in responseto a similar argument by these THLPSSCmembers concerning in-plant piping,RSPA does not agree that another NPRMis needed.

Five operators and two pipeline-related associations commented on theproposid amendment to § 195.1(b)(7).Of these commenters, two operators andone association agreed with theproposal.

A few commenters e~pressed thesame concerns about the proposed.amendment to §.195.1(b)(7) as they didabout the proposed in-plant pipingdefinition. These concerns were that theNPRM did not adequately notify plant(terminal) owners of the proposed rule,and that some operator-ownedcomponents located on plant (terminal)grounds would fall outside part 195.Our response to these concerns is thesame as stated supra regarding in-plantpiping.in regard to transfer lines located

outside terminal grounds at ports, anoperator and a pipeline-relatedassociation pointed out that the U.S.Coast Guard regulates transfers betweenterminal storage and dock facilities.,These commenters suggested that RSPAand Coast Guard develop amemorandum of understanding to limitCoast Guard's regulatigns to dockfacilities.

We recognize that Coast Guard andRSPA jurisdictions overlap in portareas, but the two agencies havedifferent responsibilities. Also, theoverlap does not automatically result inregulatory conflicts, and thecommenters did not mention any.Nonetheless, though we have notchanged the final rule as a result of thiscomment, in enforcing part 195 at portareas, RSPA will act appropriately toresolve any unnecessary regulatoryburdens.

Carbon dioxide injection system.Section 195.1(b)(8) provides that part195 does not apply to "[tiransportationof carbon dioxide downstream from apoint in the vicinity of the well site atwhich carbon dioxide is delivered to a

production facility." RSPA proposed toamend this section to clarify that theexception covers pipelines used in the.injection of carbon dioxide for oil,recovery operations.

The THLPSSC approved the proposedamendment (10 voted in favor and 5 didnot vote), and we received no adversecomments from the public. Theproposed amendment to § 195.1(b)(8) is,therefore, adopted as final.

Section 195.2 Definitions.The proposed revision of the

definition of "Secretary" is -not adoptedin this rulemaking. Instead, it is beinghandled in an omnibus rulemakingcovering all regulations involvingpipeline safety.

The definition of "In-plant pipingsystem" is discussed above in § 195.1Applicability.I Two commenters objected to theproposed definition for petroleumproducts because of its use of the terms"flammable", "toxic", and "corrosive"which are not defined under part 195.The commenters stated that absentspecific definitions for these terms, theirapplicability could be unclear.

RSPA agrees with the commentsabout the lack of clarity in the proposeddefinition for petroleum products. So,the final rule for this section includesnew definitions for "flammable","toxic", and "corrosive" that come fromthe definitions contained in 49 CFR part173 for Transportation and Packaging ofHazardous Materials for the terms"flammable liquid", "poisonousmaterial", and "corrosivematerial",respectively. RSPA has adopted thedefinition of "poisonous material" for"toxic" because it considers the termssynonymous.

Sections 195.2, 195.106, 195.112,195.212 and 195.413 (NominalOutside Diameter of the Pipe in Inches)

RSPA proposed to standardize thedimensioning of pipe size throughoutpart 195 (Changes are made to §§ 195.2,195.106(b), 195.106(c), 195.112(c), -195.212(b)(3)(ii) and 195.413(a)). All 10THLPSSC members who voted were infavor of the proposal and no commenterobjected thereto. Accordingly, theproposed amendment is adopted asfinal.

Section 195.3 Matter incorporated byreference.

Section 195.3 sets out the generalrequirements for the incorporation inthe regulations of industry standards forthe design, construction and operationof hazardous liquid and carbon dioxidepipelines. Paragraph 195.3(a) states thatincorporation of a document by

reference has the same force as if thedocument were copied in theregulations. Some operatorslhavemisinterpreted this -section to mean thatthey must.comply with all of the termscontained in a referenceddocument.Accordingly, RSPA hereby revises§ 195.3(a) to clarify that an entiredocument is not incorporated when thedocument is incorporated by reference;rather, only those portions specificallyreferenced in the regulations areincorporated.

The rule is 'being revised to conformto a recent update of references inanother rulemaking (Update ofStandards Incorporated by Reference (58FR 14519; March 18, 1993)). Also,references to ASME/ANSI Codes B31:8and B31.G are being added. The 10THLPSSC members who voted and 7commenters favored the revision.

Section 195.5 Conversion to servicesubject to this part.

Section 195.5 regulates the conversionof steel pipelines to hazardous liquid or'carbon dioxide service that is subject topart 195. Under § 195.5(a)(4), aconverted pipeline must behydrostatically tested to substantiate themaximum operating pressure (MOP)permitted by § 195.406.1

To substantiate the MOP of aconverted pipeline, an operator mustknow the pipe design pressure (seecurrent § 195.406(a)(1)). Consequently,if pipe design pressureis unknown, asteel pipeline may not be convertedunder § 195.5. Although the designpressure of components is an MOPfactor under § 195.406(a)(2), pipelinecomponents iire normally designed to beas strong or stronger than attached 'pipe.Thus, pipe design is the critical factorin substantiating MOP under§195.5(a)(4), and lack of knowledge ofcomponent design pressure is not asignificant safety concern.

RSPA proposed to amend § 195.5 topermit conversion using an approachfound in section 845.214 and AppendixN of ASME B31.8 for gas pipelineswhose design pressure is unknown.Under this proposal, operators wouldpressure test the pipeline underAppendix N until pipe yield occurs.*Instead of design pressure, this yieldtest pressure would be used tocomputeMOP by applying certain reductionfactors to 80 percent of the first pressure'that produces pipe yield.

All THLPSSC members who voted onthe proposed amendment to § 195.5

I Section 195.5(a)(4) actually uses the term"maximum allowable operating pressure," but forconsistency with § 195.406. this term is changedbelow to MOP by removing the word "allowable."

Federal Register / Vol. 59, No. 123 / Tuesday, June 28, 1994 / Rules and Regulations33391

supported it in concept. However, twomembers thought the wording ofAppendix N should be copied directlyinto part 195 to avoid referencing a gaspipeline code in liquid pipelineregulations. We believe the principles ofAppendix N apply equally to gas andliquid pipelines. And since the B31.8Code is widely used, operators ofhazardous liquid or carbon dioxidepipelines will not find it difficult toobtain and apply Appendix N.

RSPA received five comments on theproposed amendment to § 195.5. Twooperators and a pipeline-relatedassociation agreed with the proposedamendment.

One operator suggested that ifpipelines operating at less than 20percent of specified minimum yieldstrength (SMYS) are subject to § 195.5,RSPA should allow operators up to 10years to meet the testing requirements.At present, none of the standards in part195, including § 195.5, applies topipelines operating at less than 20percent of SMYS (see §,195.1(b)(3)).However, this commenter may have hadin mind § 206 of the Pipeline Safety Actof 1992 (Pub. L. 102-508), whichprovides that exceptions to regulationsunder the Hazardous Liquid PipelineSafety Act of 1979 (49 U.S.C. app. 2001et seq.), such as part 195, may not bebased solely on low internal stress.Because of this statutory mandate, RSPAhas proposed to apply part 195 tocertain low-stress hazardous liquidpipelines (Docket PS-117; 58 FR 12213;March 3, 1993). Still, that proposalwould not require any existing low-stress hazardous liquid pipeline to betested under § 195.5, because suchpipelines would not.be convertedpipelines. Of course, if part 195becomes applicable to low stresspipelines, any pipeline converted to lowstress hazardous liquid service subjectto part 195 would have to be testedunder § 195.5. But, since testing is thebackbone of the conversion process,RSPA does not believe § 195.5 should beamended to extend the time for testingto 10 years.

A state agency was concerned that iftestpressure must be measured at thehigh elevation point of test segments,the test could stress the low point of thesegment beyond yield. However, theAppendix N test method should notresult in overstress at the low elevation,because the method does not requireincreases in test pressure after the firstyield occurs in the test segment.

In a separate rulemaking proceeding(Docket No. PS-124; 57 FR 39572;August 31, 1992), RSPA proposed toallow the use of the Appendix Nmethod in converting pipelines to gas

service under 49 CFR 192.14. This gaspipeline conversion standard is similarto § 195.5. Comments to that noticeargued that pressure testing to yield isunnecessary to qualify certain pipelinesthat operate at low stress (generallypipelines 123/4 inches or less in nominaloutside diameter operating at pressuresof 200 psig or less). RSPA believes thesecomments are also relevant to hazardousliquid pipelines. All other factors beingequal, hazardous liquid pipelinesoperating at low internal stress presentless risk of failure from -time-dependentdefects than higher stress hazardousliquid pipelines. Because of the lowerrisk, RSPA has modified the final ruleto provide that pipelines 123/4 inches orless in nominal outside diameter to beoperated at a pressure of 200 psig or less,may be converted without testing toyield. The MOP of such pipelines maybe determined under § 195.406 by using200 psig as pipe design pressure.

The proposed rule has been redraftedto improve clarity, to better relateconversion to design pressure and MOPunder § 195.406, and to include thechanges discussed supra. In the finalrule, the proposed amendment to§ 195.5(a)(1) is revised and published asan amendment to § 195.406(a)(1). Thislatter section deals. specifically withpipe design pressure and MOP. As setforth infra, revised § 195.406(a)(1)provides that when pipe design pressureis unknown for steel pipelines beingconverted, a reduced value of first yieldhydrostatic test pressure may be used asdesign pressure to compute MOP. If thepipeline to be converted is 123/4 inchesor less in nominal outside diameter andis not yield tested, 200 psig may be usedas design pressure.

Section 195.8 Transportation ofhazardous liquid or carbon dioxide inpipelines constructed with other thansteel pipe.

The proposal to replace the word"he" with "the Secretary" to removeany implication of gender is not adoptedin this rulemaking. Instead, thisproposal will be handled in an omnibusrulemaking to make minor clarificationsand error corrections covering all thepipeline safety regulations.

Section 195.50, Reporting accidentsand § 195.52 Telephonic notice ofcertain accidents.

Sections 195.50(f) and 195.52(a)(3)require operators to prepare reports and.give telephonic notice of accidents,respectively, when the estimatedproperty damage due to an accidentexceeds $5,000. RSPA discovered fromits regulatory review and previousenforcement cases that a significant

amount of confusion exists amongpipeline operators as to which costestimates must be included incalculating the "estimated propertydamage to the property of the operatoror others * * *" Frequently, whenreporting accidents, pipeline operatorsfail to include as "property damage" thefair market value of the product releasedor those costs associated with clean-upand recovery efforts. RSPA believesthese costs should be included whenreporting accidents.

Because the $5,000 reportingrequirement requires the reporting ofminor accidents, RSPA proposedamending §§ 195.50(f) and 195.52(a)(3)to increase the reporting threshold to$50,000, the same level as required in49 CFR part 192 and to include asproperty damage the value of theproduct released and the costsassociated with clean-up and recoveryefforts. The THLPSSC voted 10 to 0 infavor of the change (5 members did notvote). Two of those favoring theproposed changes recommended thatRSPA modify the final rule to limitproperty damage to fair market value ofthe lost product and initial clean-up andproduct recovery costs. One membersaid that clean-up and recovery costsshould not be included in total propertydamage.

Three commenters disagreed with theproposed changes and recommendedthat the rule be withdrawn. Onecomplaint was that the statistical basewould be discontinuous because, in thefuture, RSPA would not receiveinformation on accidents costingbetween $5,000 and $50,000. Anothercomplaint was that the change couldaffect the development of environmentalprotection requirements. RSPAunderstands that a change in reportinglevels will cause a slight skewing due totruncation of the data, but believesrequiring operators to report accidentsbased solely on the $5,000 propertydamage criterion is unnecessary andburdensome. Significant accidents willstill bereported because the othercriteria (especially those that areenvironmentally related) requiringreports will be unchanged: (1) Explosionor fire, (2) loss of 50 barrels of liquid,(3) escape of five barrels a day of highlyvolatile liquids, (4) a death, (5) bodilyharm, or (6) resulted in the pollution ofany stream. Because these requirementsremain unchanged, those operators withmore frequent small releases will still beidentified. As to a skewing of the data,those organizations that keep track ofsuch statistical data should be able tomake adjustments to account for suchchanges. Also, as explained in theNPRM, this change will make the liquid

.33391

33392 Federal Register / Vol. 59, No. 123 / Tuesday, June 28, 1994 / Rules and Regulations

safety reporting requirements consistentwith the gas safety reportingrequirements which will eliminateconfusion. The rule change should havelittle, if any, effect on the environmentbecause the same spill volume reportingcriteria remain in effect. Only the dollarlevel of the reporting criterion is beingchanged.

Two commenters supported the rulechanges as they were written. Fiveothers favored the changes, butproposed modification of the rules toexplain more fully the meaning of"estimated total damage" in order tospell out the items that must be covered.They said that "estimated total damage"is ambiguous and confusing and subjectto interpretation. One commenter statedthat the costs of subsurface restorationshould be excluded from propertydamage because it is nearly impossibleto estimate the subsurface restorationcosts within the time allowed to reportthe accident

RSPA agrees that early estimates ofthe costs to clean-up a liquid spill maynot be exact; however, the operatorshould, at a later date, submit a revisedreport that provides more reliable costfigures for the clean-up.

RSPA is clarifying the issue byamending § 195.50(0 to read: "(f)Estimated property damage, includingcost of clean-up and recovery, yalue oflost product, and damage to theproperty of the operator or others, orboth, exceeding $50,000" and "§ 195.52(a)(3) to read: "(3) Causedestimated property damage, includingcost of clean-up and recovery, value oflost product, and damage to theproperty of the operator or others, orboth, exceeding $50,000."

Section 195.106 Internal designpressure.

Section 195.106(a) prescribes theformula for calculating the designpressure of steel pipe. In addition,§ 195.106(b) regulates the pipe yieldstrength used in the design pressureformula. When the specified minimumyield strength (SMYS) of pipe isunknown, § 195.106(b) requires thatyield strength be derived from tensiletests on random samples of pipe. Basedon a comparable gas pipeline safetystandard (49 CFR 192.107(b)(2)), RSPAproposed to amend § 195.106(b) to allowoperators to use 24,000 psi as yieldstrength if pipe of unknown SMYS isnot tensile tested. Editing changes to§ 195.106(b) were also proposed.

The 10 THLPSSC members who votedon the proposed amendment of§ 195.106(b) supported it (5 did notvote). In addition, RSPA receivedcomments from four operators and one

pipeline-related association. Theassociation and three of the operatorsagreed with the proposal. One of theseoperators suggested further editing, partof which RSPA has included in the finalrule.

One operator was concerned that theproposed rule could unjustifiablyreduce the MOP of its pipelines. Theoperator said its pipelines are made ofGrade B pipe (yield strength at least35,000 psi) or better. However, somepipelines may contain pipe for whichdocumentation of yield strength ortensile testing does not exist. For suchpipe, without new tensile testing, yieldstrength would have to be assumed to be24,000 psi. The operator suggested thatRSPA allow operators to use appropriateevidence besides tensile tests todemonstrate the yield strength of pipe.'

In response to this comment, we note,first, that the proposed amendment to§ 195.106(b) would not affect the designpressure of existing pipelines unlessthey are replaced, relocated, orotherwise changed (see § 195.100).Second, § 195.106(b) currently requiresoperators to use as yield strength eitherSMYS or a value based on tensiletesting. So the operator's apparentdifficulty in verifying yield strength is aproblem of compliance with the currentrule. Third, the proposed rule wouldrelax the burden of tensile testing onlywhen MOP does not exceed the levelthat corresponds to a yield strength of24,000 psi. When a higher MOP isdesired, operators must use the tensiletesting option. Finally, RSPA is notaware of any acceptable evidence of theyield strength of pipe of unknownSMYS apart from appropriate tensiletesting. Thus, the amendments 'to§ 195.106(b), as discussed above, areadopted.

Section* 195.204 Inspection-general.The THLPSSC voted 10 to 0 in favor

of the proposed change to make thelanguage gender neutral and, except fora minor correction, no objections werereceived from commenters. Thc-proposed change is adopted as'corrected.

Section 195.228 Welds; standards ofacceptability.

One of the comments we received onproposed amendments tonondestructive testing requirementsunder § 195.234(e) (discussed infra)concerned the standards for acceptanceof weld flaws (§ 195.228(b)). A pipeline-related association asked us to.incorporate by reference the .alternativeacceptance standards for girth weldsthat are in the Appendix to AmericanPetroleum Institute (API) Standard 1104

(17th edition). For weld acceptability,§ 195.228(b) now references thestandards in Section 6 of API Standard1104.

In a notice of proposed rulemakinginvolving our review of the gas pipelinesafety standards in 49 CFR part 192(Docket PS-124; 57 FR 39572; August31, 1992), RSPA proposed to allow gasoperators to apply the API appendix inaddition to section 6 criteria. Althoughthat proposal was based on a petition byAPI to incorporate the appendix byreference in both parts 192 and 195, weoverlooked the request to include sucha proposal iii the present rulemaking.

In the part 192 rulemaking, RSPA'sgas pipeline safety advisory committeevoted to support the proposedamendment. Also, all but one of thepublic comments were in favor ofallowing use of the Appendix of APIStandard 1104.

The dissenting commenter wasconcerred that industry inspectionpersonnel may not be qualified to applythe appendix. However, this commentermay not have recognized that under§§ 192.243(b) and (c), operators mustensure that nondestructive testing isperformed in accordance with writtenprocedures by persons who have beenproperly trained and qualified. Sections195.234(b) and (c) provide similarrequirements for nondestructive testingof welds on hazardous liquid andcarbon dioxide pipelines. RSPA believesthese requirements are adequate toassure proper application of theappendix.

The Appendix of API Standard 1104applies equally to girth welds in gas andliquid pipelines. This amendment is notmandatory, rather it provides pipelineoperators an optional operatingprocedure. In view of the prioropportunity for public comment on useof the appendix for gas pipelines, thefavorable response by publiccommenters and RSPA's advisorycommittee, and the fact that use of theappendix would not be mandatory, webelieve that a further opportunity forpublic comment is unnecessary to allowuse of the appendix under § 195.228(b).We feel this amendment is a logicaloutgrowth of the Notice and furthers ourefforts to make parts 192 and 195consistent wherever possible. Thisamendment will not have a substantialimpact on the regulated community.

Thus, in accordance with 5 U.S.C.553(b)(3)(B), we are amending§ 195.228(b) to reference the appendixwithout further rulemaking notice.However, should any person beadversely affected by this decision orwish to change the final rule, thatperson may submit a petition for

Federal Register / Vol. 59, No. 123 / Tuesday, June 28, 1994 / Rules and Regulations33393

reconsideration under RSPA'srulemaking procedures in 49 CFR106.35.

The final rule provides that theappendix may be used only for girthwelds to which the appendix applies.For example, as section A.1 of theappendix states, neither welds in pumpstations nor welds used to connectfittings and valves are covered by theappendix. Also, the appendix appliesonly to girth welds between pipe ofequal nominal wall thickness.

Section 195.234 Welds:Nondestructive testing.

Section 195.234(e) requires that "100percent of each day's girth weldsinstalled in * * * [certainl locationsmust be nondestructively tested 100percent unless impracticable, in whichcase at least 90 percent must be tested."RSPA proposed to amend § 195.234(e)to clarify that "90 percent" pertains tothe number of girth welds that must betested over their entire circumference.

In addition, § 195.234(g) requires: "Atpipeline tie-ins 100 percent of the girthwelds must be nondestructively tested."RSPA proposed to clarify that thisstandard applies to tie-ins ofreplacement sections of pipeline.

The THLPSSC supported theproposed amendments, although onemember thought part 195 should definethe word "impracticable." We did notadopt this recommendation because theword is used in its ordinary dictionarysense.

Three operators and two pipeline-related associations commented on theproposed amendments. Threecommenters agreed with the proposal,one suggested editing changes, and onemade a related proposal discussed supraunder the heading, "§ 195.228(b) Welds;standards of acceptability." Althoughwe did not adopt all the editingsuggestions, these comments helped usprovide clarity to the final rule.

In addition, one commenter thoughtthe proposed amendment of § 195.234(g)was unnecessary because § 195.200already indicates that § 195.234(g)applies to replacement sections.Moreover, the commenter thoughtadding the proposed phrase to§ 195.234(g) would create confusionover whether §§ 195.234(a) through (f)apply to replacement sections. Whilethese observations have theoreticalmerit, in practice, some operators havefailed to recognize that "pipeline tie-ins" include tie-ins of replacementsections. The clarifying phrase addsemphasis where it is apparently neededto assure compliance %Wth the fullextent of the rule. Section 195.234(g) is,therefore, adopted as proposed.

Sections 195.246 Installation of pipein a ditch and 195.248 Cover overburied pipeline.

Section 195.246(b) is inconsistentwith § 195.413(b)(3) for pipe in the Gulfof Mexico and its inlets (See § 195.2Definitions) under water less than 15feet deep but at least 12 feet deep,because § 195.246(b) permits the pipe tobe without cover or to be above theseabed if properly protected. Such pipeis a "hazard to navigation" under thedefinition of that teWn in § 195.2, andmust have the minimum cover requiredby § 195.413(b)(3). In addition,§§ 195.248(a) and (b) are inconsistentwith § 195.413(b)(3) for pipe in the Gulfof Mexico and its inlets under water lessthan 12 feet deep. Section 195.248(a)allows pipe to be less than 12 inchesbelow the seabed (i.e., a hazard tonavigation). In certain instances,§ 195.248(b) allows pipe to be withoutcover or less than 12 inches below theseabed. Neither condition is allowedunder § 195.413(b)(3). In light of theseinconsistences, RSPA proposed in theNPRM to amend §§ 195.246(b) and195.248(a) and (b) to correct theproblem.

Ten THLPSSC members favored theproposed changes (5 members did notvote). One of the members favoring thechanges said it would make more senseto retain the existing regulation whichoperators have adhered to for years. Insimilar manner, two commenters andone pipeline-related organization agreedwith the proposal. One commenter andtwo pipeline-related organizationsdisagreed and suggested that referencesto a depth of 15 feet in the rule beeliminated. RSPA proposed changes to§§ 195.246(b), 195.248(a) and 195.248(b)so these sections would conform withPublic Law 101-599 (section 1, 104 Stat.3038 (1990)) which requires burial ofpipe where the subsurface is under 15feet of water as measured from meanlow water. Therefore, §§ 195.246(b),195.248(a) and 195.248(b) are adoptedas proposed in the NPRM.

Section 195.262 Pumping equipment.

Section 195.262(d) regulates thelocation of pumping equipment. Therule prohibits the installation ofpumping equipment on property notunder the operator's control. It alsoprohibits installation less than 50 feetfrom the pump station boundary. RSPAproposed to amend § 195.262(d) toclarify that these two restraints onlocation apply conjunctively notalternatively.

The THLPSSC members who voted onthe proposed amendment supported itin concept, but 5 members

recommended further editing of the rule.for clarity. Although three of the fivepersons who commented on theproposal supported it as proposed, theother two commenters thought furtherclarifying changes were needed. In viewof these comments and THLPSSC views,we have modified the final rule basedon identical wording suggested by fiveTHLPSSC members and one commenter.

Section 195-304 Testing ofcomponents.

Section 195.304(b) excludes fromhydrostatic testing under part 195 anycomponent that is the only item beingreplaced or added to a pipeline systemif the component or a prototype wastested at the factory. RSPA proposed toamend § 195.304(b) to clarify that theexcluded components do not includepipe.

The THLPSSC fully supported theproposed amendment. Of the sixcomments from the public on theproposal, a pipeline-related associationand two operators agreed with it, whilethree operators suggested changes.

An operator suggested that instead ofamending § 195.304(b), we shouldrevise the definition of "component" toexclude pipe. We did not adopt thissuggestion because the revision wouldaffect every rule in part 195 that usesthe term "component." Editingsuggested by another operator was notadopted because it concerned mattersnot addressed in the NPRM.

One operator felt pipe should beexcluded from hydrostatic testing under§ 195.304(b) to the same extent as othercomponents. The operator said that.hydrostatically testing short sections ofmill tested pipe is duplicative, costly,and not needed for safety. Although theNPRM did not propose to alter theexisting requirement that replacementsections of pipe of any length must behydrostatically tested to part 195standards before operation, we do notagree with this commenter's contention.Normal pipe mill tests are not-duplicative of part 195 tests, and are nota proven safe alternative to part 195requirements. However, for shortsections of replacement pipe, part 195test requirements could be ruetanywhere, including, by priorarrangement with the operator, in thepipe mill. So if an operator wishes toavoid field testing of short replacementsections of pipe, it only needs to assurethat the mill tests of those sections weredone in accordance with part 195 testrequirements.

33393

73394 Federal Register / Vol. 59, No. 123 / Tuesday, June 28, 1994 / Rules and Regulations

Section 195.406 Maximum operatingpressure.

The changes to § 195.406 arediscussed supra under § 195.5.

Section 195.412 Inspection of rights-of-way and crossings under navigablewaters.

Section 195.112(a) requires anoperator, at intervals not exceeding 3weeks, but at least 26 times eachcalendaryear, to inspect the surfaceconditions on or adjacent to eachpipeline right-of-way. Because somesurface condition activities that affectthe safety and operation of pipelines anmore visible from aerial patrols thanfrom walking or driving the right-of-way, RSPA proposed that'the section b(changed to clarify that aerial patrols arEan optional method of compliance. Nocomments were received regarding thechange and the THLPSSC voted 10 to 0in favor of the change (5 members didnot vote). Accordingly, the change to§ 195.412(a) is adopted as proposed.

Section (b) requires operators, atintervals not exceeding 5 years, toinspect each crossing under a navigablewaterway (except offshore) to determinthe condition of the crossing. Thepurpose of the inspection is to look forany damage, unanticipated loading, orloss of protection that could threaten thsafety of the pipeline. We stated in theNPRM that bored crossings are usuallyso deep that there is little likelihood thipipeline could be affected by waterwayrelated events, such as scouring oranchor dragging. We proposed to add a:exception to § 195.412(b) to cover boreccrossings that are too deep to be subjectto waterway-related damage.

The THLPSSC voted 10 to 0 in favorof the rule (5 members did not vote).However, a state pipeline agencysuggested the existing regulation beretained. The agency stated that apipeline operator cannot be 100 percensure a bored crossing is so deep itcannot be affected as stated. RSPAreceived four additional comments,three of which expressed an opinionthat the phrase "too deep to anticipatedamage from waterway conditions orvessel traffic" is vague andinappropriate. The other commentersaid the proposal is unduly restrictiveand should be refocused from boredcrossings to a more generic performancstandard potentially including allcrossings.

In view of the comments received,RSPA agrees with those who opinedthat "too deep to anticipate damagefrom waterway conditions or vesseltraffic" is too vague. In the absence ofa recognized standard on the subject, it

is too speculative to judge when boredcrossings are buried at a sufficient depthto be safe from damage by external 'forces. Therefore, it is in the interest ofpublic safety that the current rulerequiring inspection at intervals notexceeding 5 years be retained.Accordingly, the proposed change to§ 195.412(b) is not adopted.

Section 195.416 External CorrosionControl.

Section 195.416(a tates that eachoperator shall, at infgrvals'not exceeding15 months, but at least once eachcalendar year, conduct tests on eachunderground facility that is undercathodic protection to determinewhether protection is adequate. RSPA isclarifying the rule to reduce anymisunderstanding regarding what ismeant by "underground." The word"underground" in this paragraph hasmeant any facility that is buried or incontact withthe ground. This ruleclarification will not change the burdenon operators because RSPA complianceinspectors have consistently requiredany facility in contact with the groundto be cathodically protected.

e RSPA received two commentsregarding the change to § 195.416(a).One commenter recommended thatoffshore pipelines be excluded from

.e annual testing requirements. RSPA'believes there is no acceptablesubstitute for regular testing to

3 determine if corrosion protection of all- lines, both onshore and offshore, is

adequate. Accordingly, "in contact withn the ground or submerged" is added to

the rule to assure that all underwatert pipelines, both onshore and offshore,

are included in the definition. The othercommenter suggested requiring thetesting of "carrier pipes" in casings."Carrier pipes" are normally buried andsubject to the rule. The THLPSSC voted10 to 0 in favor of the proposed change

t (5 members did not vote). The revisionto § 195.416(a) is adopted as modified.

Section 195.416(0 requires that anypipe found to be generally corroded sothat the remaining wall thickness is lessthan the minimum thickness requiredby the pipe specification tolerancesmust either be replaced with coatedpipe that meets the requirements of part195 or, if the area is small, must be'repaired. However, the operator need

a not replace generally corroded pipe ifthe operating pressure is reduced to.becommensurate with the limits onoperating pressure specified in§ 195.406, based on the actual remainingwall thickness.

Section 195.416(g) states that iflocalized corrosion pitting is found toexist to a degree where leakage might

result, the pipe must be replaced orrepaired, or the operating pressure mustbe reduced commensurate with thestrength of the pipe based on the actualremaining wall thickness in the pits.

RSPA recognizes that paragraphs (f)and (g) do not provide guidance for anoperator's use in determining thestrength of the actual remaining wallthickness of corroded steel pipe. Toprovide such guidance, RSPA proposedamending § 195.416(h) to adopt theASME Manual B31G procedure fordetermining the remaining strength ofcorroded steel pipe in existingpipelines. Application of the procedurewas proposed to be in accordance withthe limitations set out in the B31GManual. The rule would provideguidance as to whether a corrodedregion (not penetrating the pipe wall)may be left in service; this option mightrequire a reduction in maximumallowable operating pressure, but maybe more economical than replacementor repair of the corroded pipe.

Ten THLPSSC members voted for theproposal (5 members did not vote).

Comments relative to § 195.416(h)were received from five commenters.One commenter said the proposal tochange § 195.416(h) is inappropriateand should be redone to be consistentwith § 192.485. Others stated that theproposal was unnecessarily restrictivebecause it did not allow the use of otherproven industry developed methods fordetermining the remaining strength ofcorroded pipelines. The mostnoteworthy method mentioned was "AModified Criterion for Evaluating theRemaining Strength of Corroded Pipe(with RSTRENG disk)" developed byBattelle under the Pipeline ResearchCommittee of the American GasAssociation (AGA). (Project PR 3-805,December 1989, AGA catalog No.L51609). Project PR 3-805 wasundertaken to devise a modifiedcriterion that, while still assuringpipeline integrity, would eliminate asmuch as possible the excessivespecifications embodied in the ASvEB31G manual. The AGA modi. edcriterion, using a complex analysisapproach, can be carried out by meansof a PC-based program called RSTRENG.The modified criterion can also-beapplied via tables or curves or a long-hand equation if a simplified analysis ispreferred.

The addition of the modified criterionto the rule does not compromise safetybecause it merely accepts an establishedpipeline industry guideline, and doesnot impose new r quirements on theoperators. Accordrngly, RSPA isamending § 195.416(h) to include theAGA/Battelle-A Modified Criterion for

Federal Register / Vol. 59, No. 123 / Tuesday, June 28, 1994 / Rules and Regulations 33395

Evaluating the Remaining Strength ofCorroded Pipe (with the computer diskRSTRENG).

- Rulemaking Analyses

Impact AssessmentThis final rule is not considered a

significant regulatory action undersection 3(f) of Executive Order 12866and, therefore, was not subject to reviewby the Office of Management andBudget. The rule is not consideredsignificant under the regulatory policiesand procedures of the Department ofTransportation (44 FR 11034).

A Regulatory Evaluation has beenprepared and is available in the docket.RSPA estimates the proposed changes toexisting rules would result in anestimated savings of $1,534,000 per yearfor the hazardous liquid pipelineindustry at no cost to the industry, andwith no adverse effect on safety. Asdiscussed above, these savings wouldcome largely from the use of newtechnology, greater flexibility inconstructing and operating pipelines,and the elimination of unnecessaryrequirements.Federalism Assessment

RSPA has analyzed the proposedrules under the criteria of ExecutiveOrder 12612 (52 FR 41685; October 30,1987). The regulations have nosubstantial effects on the states, on thecurrent federal-state relationship, or onthe current distribution of power andresponsibilities among the variouslevels of government. Thus, preparationof a federalism assessment is notwarranted.

Regulatory Flexibility ActRSPA criteria for small companies or

entities are those with less than$1,000,000 in revenues and areindependently owned and operated.Few of the companies subject to thisrulemaking meet these criteria.Accordingly, based on the factsavailable concerning the impact of thisproposal, I certify under Section 605 ofthe Regulatory Flexibility Act that thisproposal would not have a significanteconomic impact on a substantialnumber of small entities. This ruleapplies to intrastate and interstatepipeline facilities used in thetransportation of hazardous liquids orcarbon dioxide.

Paperwork Reduction ActThe documentation for the

information collection requirements forpart 195 was submitted to the Office ofManagement and Budget (OMB) during

the original rulemaking processes.Currently, regulations in part 195 arecovered by OMB Control Numbers2137-0047 (approved through May 31,1994), 2137-0578 (approved throughOctober 31, 1994) and 2137-0583(approved through May 31, 1994). Thereare no new information collectionrequirements in this final rule.List of Subjects in 49 CFR Part 195

Ammonia, Carbon dioxide,Incorporation by reference, Petroleum,Pipeline safety, Reporting andrecordkeeping requirements.

In consideration of the foregoing,RSPA is amending 49 CFR part 195 asfollows:

PART 195-[AMENDED]

1. The authority citation for part 195continues to read as follows:

Authority: 49 app. U.S.C. 2002 and 2015;and 49 CFR 1.53.

2. In § 195.1, the introductory text ofparagraph (b) is republished, paragraph(b)(5) is revised, in paragraph (b)(6) ahyphen is added between the words"in" and "plant", and paragraphs (b)(7)and (b)(8) are revised to read as follows:

§ 195.1 Applicability.

(b) This part does not apply to-

(5) Transportation of hazardous liquidor carbon dioxide in offshore pipelineswhich are located upstream from theoutlet flange of each facility wherehydrocarbons or carbon dioxide areproduced or where producedhydrocarbons or carbon dioxide are firstseparated, dehydrated, or otherwiseprocessed, whichever facility is fartherdownstream;

(7) Transportation of hazardous liquidor carbon dioxide-

(i) By vessel, aircraft, tank truck, tankcar, 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 carbondioxide between non-pipeline modes oftransportation or between a non-pipeline mode and a pipeline, notincluding any device and associatedpiping that are necessary to controlpressure in the pipeline under§ 195.406(b); and

(8) Transpoitation 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 theinjection system, whichever is fartherupstream; or

(ii) The connection of the first branchpipeline in the production field thattransports carbon dioxide to injectionwells or to headers or manifolds fromwhich pipelines branch to injectionwells.

3. In § 195.2, the introductory text isrepublished, definitions for Corrosiveproduct, Flammable product, In-plantpiping system, Petroleum, Petroleumproduct, and Toxic product are added inalphabetical order to read as follows:

§ 195.2 Deflnitionis.As used in this part-

Corrosive product means "corrosivematerial" as defined by § 173.136 Class8-Definitions of this chapter.

Flammable product means"flammable liquid" as defined by§ 173.120 Class 3-Definitions of thischapter.

In-plant piping system means pipingthat is located on the grounds of a plantand used to transfer hazardous liquid orcarbon dioxide between plant facilitiesor between plant facilities and apipeline or other mode oftransportation, not including any deviceand associated piping that are necessaryto control pressure in the pipeline under§ 195.406(b).

Petroleum means crude oil,condensate, natural gasoline, natural gasliquids, 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.

Toxic product means "poisonousmaterial" as defined by § 173.132 Class6, Division 6.1-Definitions of thischapter.§§ 195.2, 195.112, 195.212, 195.4,13(Amended]

4. In the list below, for each sectionindicated in the left column, the phraseindicated in the middle column is "removed and the phrase indicated in theright column is added:

33396 Federal Register / Vol.-59, No. 123 ITuesday, June 28, 1994 / Rules and Regulations

Section Remove Add195.2, Gatheing line .................... 8 inches or less in nominal diameter .............. 219.1 mm (85/a in) or less nominal outside di-

ameter.195.112(c) ........................ An outside diameter of 4 inches or more ........ A nominal outside diameter of 114.3 mm (41/2in) or more.195.212(b)(3)(ii) .............. ............ ........................ The pipe is 12 inches or less in outside diam- The pipe is 323.8 mm (123/4 in) or less nomi-

eter. nal outside diameter.195.413(a) ........................................................... Except for gathering lines of 4-inch nominal Except for gathering lines of 114.3 mm (41/diameter or smaller. in) nominal outside diameter or smaller.

-5. In § 195.3, paragraph (a) is revisedto read as follows:

§ 195.3 Matter Incorporated by reference.

(a) Any document or portion thereofincorporated by reference in this part isincluded in this part as though it wereprinted in full. When only a portion ofa document is referenced, then this partincorporates only that referencedportion of the document and theremainder is not incorporated..Applicable editions are listed inparagraph (c) of this section inparentheses following the title of thereferenced material. Earlier editionslisted in previous editions of this-section may be used for componentsmanufactured, designed, or installed inaccordance with those earlier editions atthe time they were listed. The user mustrefer to the appropriate previous editionof 49 CFR for a listing of the earliereditions.* * * * *

6. In § 195.3, paragraphs (b)(1)through (b)(5) are redesignated asparagraphs (b)(2) through (b)(6) andparagraph (b)(1) is added to read asfollows:

§ 195.3 Matter Incorporated by reference.* * * * *

(b)*

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

7. In § 195.3, paragraphs (c)(2)(iii) and(c)(2)(iv) are redesignated as paragraphs(c)(2)(v) and (c)(2)(vi) and paragraphs(c)(2)(iii) and (c)(2)(iv) are added to readas follows:

§ 195.3 Matter Incorporated by reference.* * * * *

(c) * *

(2) * * *

(iii) ASME/ANSI B31.8 "GasTransmission and Distribution PipingSystems" (1989 with ASME/ANSIB31.8a-1990, B31.8b-1990, B31.8c-1992 Addenda and Special Errata issuedJuly 6, 1990, and Special Errata (Second)issued February 28, 1991). -

(iv) ASME/ANSI B31G, "Manual forDetermining the Remaining Strength ofCorroded Pipelines" (1991).* * * *. *

8. In § 195.3, paragraphs (c)(1)through (c)(4) are redesignated asparagraphs (c)(2) through (c)(5) andparagraph (c)(1) is added to read asfollows:

§ 195.3 Matter incorporated by reference.* * * * *

(c) * * *(1) American Gas Association (AGA):

AGA Pipeline Research Committee,Project PR-3-805, "A ModifiedCriterion for Evaluating the RemainingStrength of Corroded Pipe" (December'1989). The RSTRENG program may beused for calculating remaining strength.* * * * *

9. Section 195.5 is amended byrevising paragraphs (a)(1) and (a)(4) toread as follows:

§ 195.5 Conversion to service subject tothis part.

(a) * * *(1) The design, construction,

operation, and maintenance history ofthe pipeline must be reviewed and,where sufficient historical records arenot available, appropriate tests must beperformed to determine if the pipelineis in satisfactory condition for safeoperation. If one or more of the variablesnecessary to. verify the design pressureunder § 195.106 or to perform thetesting under paragraph (a)(4) of thissection is unknown, the design pressuremay be verified and the maximumoperating pressure 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 thatproduces a yielding, the design factor Fin § 195.106(a) and the appropriatefactors in § 195.106(e).*. * * * *

(4) The pipeline must be tested inaccordance with subpart E of this partto substantiate the maximum operatingpressure permitted by § 195.406.

10. Section 195.50(f) is revised to readas follows:

§ 195.50 Reporting accidents.* * * * *

(i) Estimated property damage,including cost of clean-up and recovery,value of lost product, and damage to theproperty of the operator or others, orboth, exceeding $50,000.

11. Section 195.52(a)(3) is revised toread as follows:

§ 195.52 Telephonic notice of certainaccidents.

(a) * * *

(3) Caused estimated propertydamage, including cost of cleanup andrecovery, value of lost product, anddamage to the property of the operatoror others, or both, exceeding $50,000;

12. Section 195.106(b) is revised toread as follows:

§ 195.106 Internal design pressure.* * * * *

(b) The yield strength to be used indetermining the internal design pressureuner paragraph (a) of this section is thespecified minimum yield strength. If thespecified minimum yield strength is notknown, the yield strength to be used inthe design formula is one of thefollowing:

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

Pipe size No. of tests

Less than 168.3 mm One test for each(65/8 in) nominal out- 200 lengths.side diameter.

168.3 through 323.8 mm One test for each(6/s through 123/4 in) 100 lengths.nominal outside diam-eter.

Larger than 323.8 mm One test for each(123/4 in) nominal out- 50 lengths.side diameter.

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

Federal Register / Vol. 59, No. 123 / Tuesday, June 28, 1994 / Rules and Regulations

the yield strength of the pipe is taken asthe lower-of the following:

(A) Eighty percent of the average yieldstrength determined by the tensile tests.

(B) The lowest yield strengthdetermined by the tensile tests.

(2) If the pipe is not tensile tested asprovided in paragraph (b) of thissection, the yield strength shall be takenas 165,474 kPa (24,000 psi).* * * * *

13. In § 195.106(c), the last sentence isrevised to read as follows:

§ 195.106 Internal design pressure.

(c) * * * However, the nominal wallthickness may not be more than 1.14times the smallest measurement takenon pipe that is less than 508 mm (20 in)nominal outside diameter, nor morethan 1.1.1 times the smallestmeasurement taken on pipe that is 508mm (20 in) or more in nominal outsidediameter.*t * * *

14. In § 195.204, the last sentence isrevised -to read as follows:§ 195.204 Inspection-general.

* * * No person may be used toperform inspections unless that personhas been trained and is qualified in thephase of construction to be inspected.

15. Section 195.228(b) is revised toread as follows:

§ 195.228 Welds and welding Inspection:Standards of acceptability.

(b) The acceptability of a weld isdetermined according to the standardsin section 6 of API Standard 1104.However, if a girth weld iA unacceptableunder those standards for a reason otherthan a crack, and if the Appendix to APIStandard 1104 applies to the weld, theacceptability of the weld may bedetermined under that appendix.

16. Section 195.234 is amended byrevising the introductory text ofparagraph (e) and by revising paragraph(g) to read as follows:

§ 195.234 Welds: Nondestructive testing.* *t * * *

(e) All girth welds installed each dayin the following locations must benondestructively tested over their entirecircumference, except that whennondestructive testing is impracticablefor a girth weld, it need not be tested ifthe number of girth welds for whichtesting is impracticable.does not exceed10 percent of the girth welds installedthat day:*f * *r * *

(g) At pipeline tie-ins, including tie-ins of replacement sections, 100 percent

of the girth welds must be* nondestructively tested.

17. Section 195.246 is amended byrevising paragraph (b) to read as follows:

§ 195.246 Installation of pipe in a ditch.

(b) Except for pipe in the Gulf ofMexico and its inlets, all offshore pipein water at least 3.7 m 12-ft-deep but notmore than 61 m (200 ft) deep, asmeasured from the mean low tide, mustbe installed so that the top of the pipeis below the natural bottom unless thepipe is supported by stanchions, held inplace by anchors or heavy concretecoating, or protected by an equivalentmeans.

18. Section 195.248 is amended byrevising in the first column of the tablein paragraph (a) the language "Otheroffshore areas under water less than 12-ft-deep as measured from the mean lowtide" -to read "Gulf of Mexico and itsinlets and other offshore areas underwater less than 12-ft-deep as measuredfrom the mean low tide" and by revisingthe introductory text of paragraph, (b) to,read as follows:

§ 195.248 Cover over buried pipeline.

(b) Except for the Gulf of Mexico andits inlets, less cover than the minimumrequired by paragraph (a) of this sectionand § 195.210 may be used if-

19. Section 195.262(d) is revised toread as follows:

§ 195.262 Pumping equipment.* * *r *Z *

(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.

20. The introductory text of§ 195.304(b) is revised to read asfollows:

§195.304 Testing of components.

(b) A component, other than pipe, thatis the only item being replaced or addedto the pipeline system need not behydrostatically tested under paragraph(a) of this section if the manufacturercertifies that either-

21. Section 195.406 is amended byrepublishing the introductory text ofparagraph (a) and revising paragraph(a)(1) to read as follows:

§ 195.406 Maximum operating pressure.(a) Except for surge pressures and

other variations from normal operations,

no operator may operate a pipeline at apressure that exceeds any of thefollowing:(1) The internal design pressure of the

pipe determined in accordance with§ 195.106. However, for steel pipe inpipelines being converted under § 195.5,if one or more factors of the designformula (§ 195.106) are unknown, one ofthe following pressures is to be used asdesign pressure:

(i) Eighty percent of the first testpressure that produces yield undersection N5.0 of Appendix N of ASMEB31.8, reduced by the appropriate*factors in §§ 195.106 (a) and (e); or

(ii) If the pipe is 323.8 mm (12/4 in)or less outside diameter and is nottested to yield under this paragraph,1379 kPa (200 psig).

22. Section 195.412(a) is revised toread as follows:

§ 195.412 Inspection of rights-of-way andcrossings under navigable waters.

(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.

23. Section 195.416 is amended byrevising paragraph (a), redesignatingparagraph (h) as paragraph (i) andadding a new paragraph (h) to read asfollows:

§ 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 undercathodic protection to determinewhether the protection is adequate.

(h) The strength of the pipe, based onactual remaining wall thickness, forparagraphs (0 and (g) of this sectionmay be determined by the procedure inASME B31G, manual for Determiningthe Remaining Strength of Corroded -Pipelines or by the procedure developedby AGA/Battelle-A Modified Criterionfor Evaluating the Remaining Strengthof Corroded Pipe (with RSTRENG disk).Application of the procedure in theASME B31G manual or the AGA/Battelle Modified Criterion is applicableto corroded regions (not penetrating thepipe wall) in existing steel pipelines in,accordance with limitations set out inthe respective procedures..

33397

-3398 Federal Register / Vol. 59, No. 123 / Tuesday, June 28, 1994 / Rules and Regulations

Issued in Washington, DC, on June 9, 1994.Ana Sol Guti&rez,Acting Administrator, Research and SpecialPrograms Administration.[FR Doc. 94-15510 Filed 6-27-94; 8"45 am]BILLING CODE 4910-60-P