Controlling Corrosion on Hazardous

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Thursday,

December 27, 2001

Part III

Department of Transportation

Research and Special Programs Administration

49 CFR Part 195

Controlling Corrosion on HazardousLiquid and Carbon Dioxide Pipelines;Final Rule

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66994 Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001/ Rules and Regulations

DEPARTMENT OF TRANSPORTATION

Research and Special ProgramsAdministration

49 CFR Part 195

[Docket No. RSPA–97–2762; Amdt. 195–73]

RIN 2137–AD24

Controlling Corrosion on HazardousLiquid and Carbon Dioxide Pipelines

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

SUMMARY: This Final Rule makeschanges in some of the corrosion controlstandards for hazardous liquid andcarbon dioxide pipelines. The changesare based on our review of the adequacyof the present standards compared tosimilar standards for gas pipelines andacceptable safety practices. The changes

are intended to improve the clarity andeffectiveness of the present standards,and reduce the potential for pipelineaccidents due to corrosion.DATES: This Final Rule takes effect

January 28, 2002. The incorporation byreference of the publication listed in therule is approved by the Director of theFederal Register January 28, 2002.

Compliance dates: Under§ 195.563(c), operators of certaineffectively coated buried piping in

breakout tank areas or pump stations arenot required to cathodically protect thatpiping until December 29, 2003. Under§ 195.567(a), operators of cathodicallyprotected pipelines or pipelinesegments that lack test leads for externalcorrosion control are not required toinstall test leads until December 29,2004. Under § 195.573(a)(2), operatorsare not required to determine thecircumstances in which a close-intervalsurvey or comparable technology ispracticable and necessary untilDecember 29, 2003. Under § 195.573(b),operators of unprotected pipe are notrequired to reevaluate the need forcorrosion control on the pipe at leastevery 3 years until December 29, 2003.FOR FURTHER INFORMATION CONTACT: L.M. Furrow by phone at 202–366–4559,

by fax at 202–366–4566, by mail at U.S.Department of Transportation, 400Seventh Street, SW., Washington, DC20590, or by E-mail [email protected].

SUPPLEMENTARY INFORMATION:

Background

Corrosion causes a significantproportion of hazardous liquidpipelines accidents. Based on thisfinding, we reviewed the corrosion

control standards in 49 CFR part 195 todetermine if the standards need to bemade clearer, more effective, orconsistent with acceptable safetypractices. We believe that improving thestandards will have the potential toreduce the number of accidents caused

by corrosion.The review began September 8, 1997,

when we held a public meeting in OakBrook, Illinois to discuss how part 195corrosion control standards and thecorrosion control standards for gaspipelines in 49 CFR part 192 might beimproved (62 FR 44436; Aug. 21, 1997).We held the public meeting inconjunction with meetings of NationalAssociation of Corrosion EngineersInternational (NACE), a professionaltechnical society dedicated to corrosioncontrol. Participants agreed, universally,that part 192 and part 195 corrosioncontrol standards are largely sufficient,and although some changes may be

needed, the standards should remaingenerally unchanged.Based on this conclusion, we began to

consider whether the morecomprehensive part 192 gas standards,possibly with some changes, would beappropriate for part 195’s hazardousliquid and carbon dioxide pipelines. Wemet then, from time to time, withrepresentatives of NACE, the pipelineindustry, and state pipeline safetyagencies for technical input. At thesemeetings, we also examined whether thepart 192 standards need to be moreeffective or clearer. The meetings raisedvarious concerns about the effectiveness

and clarity of some of the part 192corrosion control standards and thesuitability of applying those standardsto hazardous liquid and carbon dioxidepipelines. We also took into accountthat the National Association of PipelineSafety Representatives, the Gas PipingTechnology Committee, and theNational Transportation Safety Boardhad at various times recommendedchanges to part 192 and part 195corrosion control standards. So, togather public comment on our concernsand the changes these organizationsrecommended, we held another public

meeting on April 28, 1999, in SanAntonio, Texas, and invited the publicto submit written comments. Thecomment period remained open until

June 30, 1999 (64 FR 16885; April 7,1999).

Notice of Proposed Rulemaking

Sixty-two persons filed writtencomments in response to the SanAntonio meeting notice. We thensummarized these comments in a noticeof proposed rulemaking (NPRM)published last year (65 FR 76968; Dec.

8, 2000). The NPRM proposed to add topart 195 a new subpart H calledCorrosion Control. Subpart H wouldprescribe corrosion control standards forall new and existing steel pipelines towhich part 195 applies. At this time, wealso decided to address the concerns,recommendations, and comments thatpertain primarily to the corrosion

control standards in part 192 in aseparate notice of proposed rulemakingon gas pipelines.

Although there was little support inthe record for allowing NACE StandardRP0169–96, ‘‘Control of ExternalCorrosion on Underground orSubmerged Metallic Piping Systems,’’ toserve as an alternative to standardsproposed in subpart H, we specificallyrequested further comment on this issuedue to NACE’s standing in the field of corrosion. Unfortunately, no onecommenting on the NPRM responded tothat request, perhaps because of earlier

discussions of the issue in Oak Brookand San Antonio. While NACE urged usto reference the entire NACE Standard,not just section 6 as we proposed, NACEdid not assert that the NACE Standardcould serve as an acceptable alternativeto proposed subpart H.

The NPRM discussed each of thestandards proposed for inclusion insubpart H. Many of these standards areidentical to present corrosion controlrequirements in part 195, and many of the standards are substantially like thepresent requirements in part 192.Proposed subpart H also includesstandards that, while based on present

part 192 requirements, include changeswhich we think are beneficialimprovements.

Discussion of Comments

We received comments from thefollowing entities in response to theNPRM: Alberta Energy Company (AEC),City of Dallas Water Utilities, EnronTransportation Services Company(Enron), Environmental Defense,Equilon Pipeline Company (Equilon),L.A. ‘‘Roy’’ Bash, NACE, Phillips PipeLine Company (Phillips), State of IowaUtilities Board (Iowa), State of

Washington Utilities and TransportationCommission (WUTC), and ToscoCorporation (Tosco). Most commenterssupported the rulemaking, and all butthe City of Dallas recommended changesto some of the proposed standards.

The City of Dallas related itsexperience with a major pipeline spillcaused partly by corrosion. Gasolinecontaining MTBE, a fuel oxygenatewhich effects the taste and odor of water, entered a lake resulting in a watersupply crisis. The City stated that it iscritical for DOT to adopt rules to require




66995Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001/ Rules and Regulations

1Paragraph 1.3 reads:The provisions of this standard shall be applied

under the direction of competent persons who, byreason of knowledge of the physical sciences andthe principles of engineering and mathematics,required by education and related practicalexperience, are qualified to engage in the practiceof corrosion control on buried or submergedmetallic piping systems. Such persons may beregistered professional engineers or personsrecognized as corrosion specialists or cathodicprotection specialists by NACE if their professionalactivities include suitable experience in externalcorrosion control of buried or submerged metallicpiping systems.

all pipelines, especially thosetransporting gasoline with MTBE near amunicipal water resource, to beregularly monitored for corrosion,cracks, and leaks; and that anydeficiencies found, be timely repaired.

This rulemaking will accomplishwhat the City of Dallas is seeking withrespect to corrosion. In particular,

§§ 195.573, 195.579, and 195.583 willrequire operators to monitor pipelinesregularly for corrosion and correct anydeficiencies found in corrosion control.Additionally, new § 195.585 specifiescorrective action for any harmfulcorrosion found. The timeliness of correcting corrosion control deficienciesand harmful corrosion is covered byexisting §§ 195.401(b) and 195.452(h).

The requirement for operators topatrol their pipelines regularly for signsof failures is longstanding (§ 195.412(a)).However, we recently broadenedrequirements by publishing standardson integrity management which willrequire pipelines in or near high-consequence areas, such as drinkingwater sources, to be internally inspectedor pressure tested at regular intervals forcorrosion, cracks, and other defects (65FR 75377; Dec. 1, 2000). These newstandards currently apply to operatorswith 500 or more miles of hazardousliquid pipelines, and we have proposedsimilar standards for the remaininghazardous liquid operators subject topart 195 (66 FR 15821; Mar. 21, 2001).

The following material, which isorganized by sections of final subpart H,summarizes comments on the NPRM. In

addition, the material explains how wetreated the comments and otherconsiderations in developing finalsubpart H. If a subsection is notmentioned, no significant commentswere received on the correspondingproposed rule and we are adopting theproposed rule as final.

Section 195.551. This informationalsection provides the content of subpartH. Subpart H contains minimumrequirements for protecting steelpipelines against corrosion.

In commenting on proposed§ 195.551, Tosco suggested we replace

the term ‘‘steel’’ with ‘‘metallic’’ sosubpart H would apply to pipelinesmade of any metal. Indeed, ourcorrosion control standards for gaspipelines apply to any metallic pipeline(49 CFR 192.451(a)). However, incontrast to gas pipelines, hazardousliquid and carbon dioxide pipelines arealmost exclusively made of steel. Forthis reason, many of the existingstandards in part 195, includingcorrosion control standards, apply onlyto steel pipelines. Our review of thecorrosion control standards did not

disclose a need to expand their coverageto include pipelines made of metalsother than steel. In commenting on theNPRM, no one, including Tosco,presented information to explain whythe coverage should be expanded.Nevertheless, operators are required toprovide us an opportunity to review thesafety of any pipeline that is to be

constructed with a material other thansteel (§ 195.8). In the case of a metallicpipeline made from a material otherthan steel, such as aluminum, ourreview would include the operator’splan for corrosion control.

Section 195.553. This new sectionwas not in the NPRM. It providesdefinitions of terms used in subpart H.The definitions of ‘‘active corrosion,’’‘‘electrical survey,’’ and ‘‘pipelineenvironment,’’ proposed in § 195.569(c),drew no adverse comment.Additionally, final § 195.553 establishesdefinitions of ‘‘ buried’’ and ‘‘you.’’ The

definition of ‘‘ buried’’ reflects thecommon corrosion control practice of treating any portion of pipe in contactwith the soil as if that portion were

buried. The term ‘‘you’’ has the samemeaning as ‘‘operator.’’

Section 195.555. This section, basedon proposed § 195.553, keeps in effectthe existing qualification standards in§ 195.403(c) for corrosion controlsupervisors. Under § 195.403(c), eachoperator must require and verify that itssupervisors maintain a thoroughknowledge of that portion of thecorrosion control proceduresestablished under § 195.402 for which

they are responsible, to insurecompliance.

While Tosco and WUTC supportedthe proposed rule, Phillips objected toit. Phillips believed that part 195 shouldinclude qualifications for supervisors of all operation and maintenanceactivities, not just corrosion control. Inthe negotiated rulemaking onqualification of pipeline personnel (64FR 46866; Aug. 27, 1999), we removedthe requirements in § 195.403(c)concerning qualifications of supervisorsof operations and maintenanceactivities, effective October 28, 2002.

We did so based on the requirementunder subpart G of part 195, that on thisdate, individuals performing regulatedoperation and maintenance activitiesmust be fully qualified, thus lesseningthe need to regulate the qualifications of their supervisors. After revising§ 195.403(c), our more specific review of the corrosion control standards calledattention to the special role thatsupervisors play in carrying outcorrosion control activities. As weexplained in the NPRM, individualsqualified to do such activities as taking

electrical readings, usually hand thedata collected over to supervisors whomake critical decisions about corrosioncontrol adequacy and the need forcorrective action. None of thecommenters, including Phillips, arguedthat corrosion control supervisors donot need to have the qualificationsrequired by existing § 195.403(c). So

given the special role of corrosioncontrol supervisors and the apparentacceptability of the existing supervisorqualification requirements, we continueto believe those requirements shouldremain in effect after October 28, 2002.This decision does not affect theexpiration on October 28, 2002, of qualification requirements forsupervisors of other operation andmaintenance activities.

Equilon and NACE believedqualifications for supervisors should beno less rigorous than stated in paragraph1.3 of NACE Standard RP0169–96.

These NACE provisions address theneed for corrosion control supervisors tohave a minimum level of technicalcompetency.1 In our corrosion controlreview, we considered this NACEprovision as well as 49 CFR 192.453,which provides that gas pipelinecorrosion control procedures must becarried out by or under the direction of a person qualified in corrosion controlmethods. Also, in the San Antoniomeeting notice, we asked if morespecific standards are needed forindividuals who direct corrosion controlprocedures. Everybody who respondedopposed changing § 192.453, and most

responders also opposed establishingspecific technical qualifications likethose in NACE Standard RP0169–96.We expect that individuals who qualifyas a supervisor under proposed§ 195.553, will have appropriatetechnical training or experience incorrosion control. Given that neither ourreview, nor comments on the NPRMdisclosed anything in the pipelineindustry’s safety record to demonstratethe need for more specific technicalqualifications, we did not adopt theEquilon and NACE comment.

Sections 195.557, 195.559, and

195.561. These three standards on





external coating are based on proposed§ 195.555 and 195.557. Collectively, thestandards require buried or submergedpipelines to have external coating withparticular attributes, and requireoperators to inspect pipe coating andrepair any damage. As stated inproposed § 195.555, the standards arelimited to pipelines constructed,

relocated, replaced, or otherwisechanged after certain effective dates in§ 195.401(c); and limited to certainconverted pipelines. In final § 195.557,we have clarified that aboveground

breakout tank bottoms need not becoated. We determined that such arequirement is impractical and not acustomary corrosion control practice.

In the NPRM, we proposed in§ 195.555 to limit the applicability of proposed §§ 195.557 (external coating),195.559 (cathodic protection), and195.561 (test leads) to pipelinesconstructed, replaced, relocated, or

otherwise changed after the applicableeffective date. We based proposed§ 195.555, for the most part, on existing§ 195.200, titled Scope, which similarlylimits the applicability of correspondingexisting §§ 195.238, 195.242, and195.244. However, we inadvertentlyomitted from § 195.555 the pipemovement exception included in§ 195.200. In this Final Rule, thesubstance of proposed § 195.555regarding external coating and cathodicprotection is in § 195.557(a), which doesinclude the omitted exception for pipemovement. We addressed the proposedlimit on test leads differently, as

discussed below under the heading,section 195.567.

Tosco believes it would be helpful toinclude in subpart H the past effectivedates cross-referenced in proposed§ 195.555. Tosco believes the dates arenot widely known. We did not adoptthis comment because the dates arealready stated in § 195.401(c) forpurposes of indicating the applicabilityof standards in addition to corrosioncontrol standards, and we do not wantto create an unnecessary redundancy inpart 195.

Final § 195.557 specifies which

pipelines must have external coating.Rather than cross-referencing § 195.5(b)to indicate which converted pipelinesmust have coating, we transferred tofinal § 195.557 the coating aspect of § 195.5(b). We transferred the cathodicprotection aspect to final § 195.563(b);and the test lead aspect is covered by§ 195.567.

Equilon and NACE suggested weestablish an additional standard tominimize damage to coating whenoperators install pipe by boring, driving,directional drilling, or any similar

method. Final § 195.559(d) requiresexternal coating to have enough strengthto resist damage due to handling andsoil stress. We believe this standard is

broad enough to cover the potential pipeinstallation problems raised by thesecommenters.

Phillips advised against requiring theinstallation of coating on older existing

bare or ineffectively coated pipelines.We believe Phillips may be referencingexisting hazardous liquid pipelinesconstructed before the applicableeffective dates stated in § 195.401(c).These pipelines are not subsequentlyreplaced, relocated, or otherwisechanged. Final § 195.557 does notrequire these older pipelines to becoated.

Tosco suggested that § 195.557 shouldinclude the dates for which pipelinesmust have external coating. The finalrule accomplishes this objective bycross-referencing § 195.401(c). Restating

the dates listed in § 195.401(c) would beunnecessarily redundant since the datesare in § 195.401(c) for purposes otherthan corrosion control.

Section 195.563. Final § 195.563combines cathodic protectionrequirements proposed in §§ 195.555,195.559, and 195.563. It also cross-references final § 195.573(b), whichrequires cathodic protection of unprotected pipe found to have activecorrosion. As a result, all pipelines thatmust have cathodic protection undersubpart H are identified in a singlesection.

Final § 195.563(a), which is based onproposed §§ 195.559(a) and (b), requirescathodic protection on each pipelinethat must have an external coatingunder § 195.557(a). The cross-referenceto § 195.557(a) limits the cathodicprotection requirement to thosepipelines constructed, relocated,replaced, or otherwise changed aftercertain dates, as proposed under§ 195.555. Section 195.563(a) does notcontain the second sentence of proposed§ 195.559(a) which would requireoperators to have a test procedure todetermine whether adequate cathodic

protection was achieved. We now believe this sentence is redundant dueto the routine monitoring conducted todetermine the adequacy of cathodicprotection, required by final§ 195.573(a). Also, amended§ 195.402(c)(3) requires operators tohave procedures to carry out§ 195.573(a). Although proposed§ 195.559(b) only referred to completionof construction as the beginning of theperiod during which cathodicprotection must be installed, final§ 195.563(a) reflects the broader

applicability indicated by proposed§ 195.555.

We proposed in § 195.559(a), whichwas based on existing § 195.242(a), arequirement that operators installcathodic protection systems on all

buried or submerged pipelines ‘‘tomitigate corrosion that might result instructural failure.’’ Equilon and NACE

suggested this proposed rule would beclearer if we replaced ‘‘structuralfailure’’ with ‘‘structural failure orpenetration of pipe or tank wall.’’ Inlight of their comment, we believe thephrase, ‘‘to mitigate corrosion that mightresult in structural failure,’’ createsconfusion. It could be interpreted torequire protection only against severeexternal corrosion. Moreover, since it isclear that existing § 195.242(a) requirescathodic protection against all externalcorrosion, the phrase seemssuperfluous. Therefore, we did not useit in final § 195.563(a).

Equilon and NACE also commentedon the § 195.559(b) proposedrequirement that a cathodic protectionsystem be installed not later than 1 yearafter completing construction. They

believe cathodic protection should be ineffective operation at the end of 1 year,to guard against significant corrosionthat could be caused by stray currentsor galvanic long-line currents. We

believe effective operation is implicit inthe existing and proposed standards oninstallation of cathodic protection.Nevertheless, to avoid confusion on thispoint, in final § 195.563(a) we replaced‘‘installed’’ with ‘‘in operation.’’ This

change is consistent with thecomparable standard for gas pipelines in§ 192.455(a)(2). Under final § 195.571,when the cathodic protection system isplaced in operation, it would have tocomply with one or more of theapplicable criteria and otherconsiderations for cathodic protectioncontained in paragraphs 6.2 and 6.3 of NACE Standard RP0169–96. Subsequentelectrical tests and other steps required

by final § 195.573(a) will assure thatadequate protection is maintained.

WUTC raised the concern that underproposed § 195.559(b) corrosion could

go uncontrolled on some facilities for upto 2 years. Based on a Washington Stateadministrative rule, WUTCrecommended that § 195.559(b) requirethat facilities be cathodically protectedwithin 90 days after they are buried orsubmerged. We did not propose tochange the currently required time limit(1 year after completing construction)

because our review of the corrosioncontrol standards and the commentsfrom the San Antonio meeting did notindicate any need to reduce theinstallation time limit. After considering





WUTC’s comment, we still believe 1year after construction is acceptable asa generally applicable time limitconsidering that soil conditions mayneed time to stabilize in order tosupport cathodic protection.

Final § 195.563(b) requires cathodicprotection on certain convertedpipelines. This requirement does not

differ substantively from the cathodicprotection aspect of the corrosioncontrol requirement of § 195.5(b).Therefore, we are modifying § 195.5(b)to cross-reference the new subpart Hstandards.

Under final § 195.563(c), which is based on proposed § 195.563, all buriedor submerged pipelines, that have aneffective external coating must havecathodic protection. This requirementdoes not apply to breakout tanks. Thisrequirement is substantially the same asexisting § 195.414(a), which requiresthat all effectively coated pipelines must

be cathodically protected, except for breakout tank areas and buried pumpingstation piping.

However, Equilon and NACE eachstated it saw no need to except buriedpiping in breakout tank areas andpumping stations from the requirementto cathodically protect effectively coatedpipelines. We agree that the exceptionseems to lack a sound safety basis. Forexample, NACE Standard RP0169–96does not have a similar exception fromcathodic protection. Also, we believe itis now common practice in thehazardous liquid pipeline industry tocathodically protect effectively coated

buried piping in breakout tank areas andpump stations. So, in view of theEquilon and NACE comments, and ourfurther consideration, we decided toterminate the exception for buriedpiping in breakout tank areas andpumping stations. Therefore, the finalrule keeps the exception in effect onlyuntil December 29, 2003. This periodwill give operators time to installcathodic protection on any effectivelycoated piping in breakout tank areas andpumping stations where it is not alreadyinstalled. Also, since no one commentedon application of the proposed rule to

the bottoms of breakout tanks and theremay not be many older breakout tanksthat have effectively coated bottoms, thefinal rule does not change the presentexception for breakout tank bottoms.

Initially, we did not proposeregulations similar to §§ 195.414(b) and(c), which require cathodic protection inareas of active corrosion found throughelectrical inspections previouslyrequired on bare pipelines, breakouttank areas, and buried pumping stationpiping. We reasoned that §§ 195.414(b)and (c) are no longer necessary because

the inspection deadlines had expired.However, we now recognize that thecathodic protection provisions of §§ 195.414(b) and (c) are continuingrequirements, and so we included themin subpart H as final § 195.563(d).

Section 195.565. This section,concerning the installation of cathodicprotection on breakout tanks, is the

same as proposed § 195.559(c). Therewere no comments on proposed§ 195.559(c).

Section 195.567. In this sectionconcerning test leads, paragraphs (a)and (b) are based on proposed § 195.561and existing § 195.244. The existing testlead standards in § 195.244 apply toonshore pipelines constructed, replaced,relocated, or otherwise changed aftercertain past dates; and to onshoreconverted pipelines if required by§ 195.5(b). The NPRM did not proposeto vary this application. However, uponfurther consideration of the importanceof test leads in determining theadequacy of cathodic protection, we areapplying final § 195.567 to all onshorepipelines that must have cathodicprotection under subpart H. Thisincreased coverage will affect pipelinesor segments of pipelines that must havecathodic protection under existing§§ 195.414 and 195.416(d) (i.e.,effectively coated pipelines and placeson bare pipelines, breakout tank areas,and pumping station piping whereactive corrosion is found throughelectrical inspection). The increasedcoverage will also affect convertedpipelines that were not substantially in

compliance with existing § 195.244when placed in service, as § 195.5(b)now permits. To ease the burden of compliance on existing cathodicallyprotected pipelines or pipelinesegments on which test leads are notnow required by existing § 195.244 or§ 195.5(b), final § 195.567(a) allowsoperators 3 years to identify thesepipelines or pipeline segments andinstall test leads as necessary to meet§ 195.567(b). On existing unprotectedpipelines, any newly identified segmentthat must have cathodic protection as aresult of an electrical survey under final

§ 195.573(b), must have test leads intime to carry out the annual monitoringtest under final § 195.573(a).

Final § 195.567 is consistent withacceptable practices. The practicesrecommended for test leads in NACEStandard RP0169–96 and in ASMEB31.4 are not limited to new, relocatedor replaced pipelines. Also, our gaspipeline regulations in 49 CFR 192.469and 192.471 for test stations and testleads, apply to all gas pipelines thatmust be cathodically protected under 49CFR part 192. Moreover, existing

§ 195.416(a) requires annual testing of each cathodically protected pipeline todetermine the adequacy of cathodicprotection; and operators normallycomply with this requirement byobtaining electrical measurementsthrough test leads. So we believe§ 195.567 will have only a minimalimpact on hazardous liquid pipeline

companies.Based on existing § 195.244(b)(1), we

proposed in § 195.561(b)(1) thatoperators install test leads with enoughlooping or slack to prevent the leadsfrom being unduly stressed or brokenduring backfilling. Equilon and NACEsuggested that to assure test lead wiresremain effective, we should add thephrase ‘‘to remain mechanically secureand electrically conductive.’’ We believethe objective of this phrase is within thepurpose of the existing rule, andtherefore, added the phrase to final§ 195.567(b)(2) for emphasis.

The long term integrity of test leads isalso covered by final § 195.567(c). Basedon proposed § 195.573, this standardrequires maintenance of test leads.There were no comments on theproposed rule, however we edited thefinal rule for clarity.

Equilon and NACE also commentedon testing cathodic protection of offshore pipelines. They contended thattest lead readings at platforms or atshore locations may be of little benefitin determining the adequacy of cathodicprotection of offshore pipelines. As analternative to such readings, theysuggested we require operators to

analyze or inspect each cathodicprotection system before the end of itsdesign life. In our experience, test leadsfor offshore pipelines normally areinstalled only on platforms or on shore

because of the difficulty of accessingleads at underwater locations. For thisreason, § 195.567 does not apply to

buried or submerged portions of offshore pipelines. Since pipelinecorrosion in an offshore environmentgenerally occurs at a uniform rate, we

believe readings taken by operators atoffshore platforms or on shore are usedsatisfactorily to determine the adequacy

of protection over the entire pipeline.Moreover, this test method is acceptablefor offshore gas pipelines underparagraph A862.15 of the ASME B31.8Code. Because there is no information tosupport the need to require the use of an alternative testing method, we chosenot to take action on the commenters’suggestion.

WUTC commented that because theproposed standard does not prescribethe number or precise location of testleads, government inspectors maydisagree with operators over whether





test readings are sufficient to determinethe adequacy of cathodic protection. Toameliorate this situation, WUTCsuggested that we require operators toconduct close-interval electrical surveysevery 5 years. Although final § 195.567does not specify the number or preciselocation of test leads, it does provide aperformance standard for the location of

test leads. Under § 195.567(b)(1) testleads must be installed at sufficientlyfrequent intervals to obtain electricalmeasurements indicating the adequacyof cathodic protection. Section 4.5 of NACE Standard RP0169–96, which listsmany customary test lead locations, may

be used as a guide to comply with§ 195.567(b)(1). Additionally, the finalrule on monitoring external corrosioncontrol, § 195.573, will require operatorsto use close-interval surveys in somesituations and install additional testleads where warranted.

Section 195.569. This section, which

is based on proposed § 195.565,provides that whenever an operatorlearns that any portion of a buriedpipeline is exposed, the exposed portionmust be examined for external corrosionif the pipe is bare or has deterioratedcoating. Further, if external corrosionrequiring remedial action is found, theoperator must investigate pipe in thevicinity of the exposed portion (byvisual examination, indirect method, or

both) to determine if there is anyadditional external corrosion requiringremedial action.

Phillips requested more flexibility inthe proposed requirement to look for

additional corrosion. Phillipscommented that the extent of furtherinvestigation should depend on the typeof corrosion found and whether thecorrosion could be expected to extend

beyond the exposed segment. We do not believe there is a clear understanding of the relationship between the type of corrosion and the likelihood of findingsimilar corrosion in the vicinity of theexposed pipe to justify limits on therequirement for additional investigation.Pipe and soil conditions are generallytoo variable to make such predictionswith accuracy. Therefore, we did not

adopt Phillips’ comment.WUTC believed subpart H shouldinclude additional requirements foroperators to do more to determine thecondition of coating than just visuallyexamine it whenever pipelines areexposed. WUTC stated that thestandards should require operators toconduct surveys to identify areas withcoating defects and take remedialmeasures such as re-coating thepipeline. Although the final rules do notspecifically require pipe coatingsurveys, operators must conduct

electrical tests periodically to determinethe adequacy of corrosion control ontheir buried pipelines. Low cathodicprotection potential readings obtainedduring these tests often are a sign of coating defects. So, in areas with lowpotential readings, many operatorssupplement cathodic protection testswith coating surveys to help them

identify places where the pipeline must be excavated to look for corrosion cellsor to determine where additionalcathodic protection must be applied.The need to mandate the use of coatingsurveys in addition to electrical tests forcorrosion, was not evident from ourreview of the regulations.

Section 195.571. This standard,proposed as § 195.567, incorporates byreference the criteria and otherconsiderations in section 6 of NACEStandard RP0169–96, as standards forthe adequacy of cathodic protection.

Environmental Defense and Iowaargued that because cathodic protectioncriteria are fundamental to safety, thecriteria should be stated in part 195rather than incorporated by reference.Iowa believed that acquiring andmaintaining a separate document isarbitrary and unnecessarily

burdensome. In considering thesecomments, we reviewed OMB CircularA119 and the National TechnologyTransfer and Advancement Act of 1995.Both documents direct Federal agenciesto use consensus standards wherepractical to meet their policy objectivesrather than develop government-uniquestandards. We also reviewed the rules of

the Federal Register on incorporation by reference. In light of these Federalpolicies, we think it is appropriate forus to incorporate the NACE criteria andother considerations by reference, asproposed.

Enron, Environmental Defense, and L.A. (Roy) Bash urged us to adopt thecriteria in Appendix D of part 192instead of the NACE criteria. Enroncommented that many operators aresuccessfully using Appendix D forhazardous liquid pipelines; andEnvironmental Defense viewedAppendix D as more specific and

therefore more enforceable. Roy Bashsubmitted technical documentation insupport of two Appendix D criteria, 300mV shift and E-log-I. In the NPRM wediscussed our reluctance to proposeAppendix D as the new standard forhazardous liquid pipelines because theAppendix D 300 mV shift and E-log-Icriteria are not incorporated in theNACE Standard. Furthermore, weexplained that under paragraph 6.2.1 of the NACE Standard, operators may useany criteria which they can demonstrateachieves corrosion control comparable

to section 6 criteria. Also, operators maycontinue to use criteria which they havesuccessfully applied to existingpipelines, on these pipelines. While thisprovision may satisfy Enron, and shouldsatisfy Roy Bash’s concern about thecontinued use of the 300 mV shift andE-log-I criteria, the lack of specificity inparagraph 6.2.1 may be indicative of

Environmental Defense’s concern. Yet,we do not believe the performancewording of paragraph 6.2.1 alone issufficient reason not to reference section6 of the NACE Standard. On thecontrary, we generally favorperformance standards overspecification standards because theyencourage operators to develop andapply better alternatives. If however, anoperator chooses to use alternativecriteria, we will carefully examine theoperator’s rationale for determinationthat the criteria met the ‘‘comparable to’’or ‘‘successfully applied’’ tests of

paragraph 6.2.1 of the NACE Standard.WUTC was concerned that the criteriain section 6 of the NACE Standardwould not be mandatory becauseparagraph 6.1.1 refers to paragraph 1.2,which states that the Standard is aguide; and also refers to paragraph 1.4,which allows deviations from theStandard. Proposed § 195.567 referssolely to the criteria and otherconsideration provisions of section 6,which are contained in paragraphs 6.2and 6.3 of the NACE Standard. We didnot intend to allow operators to treatsection 6 as a guide or to deviate fromthe criteria and other considerations in

section 6. Therefore, the final rule refersto paragraphs 6.2 and 6.3, instead of section 6.

WUTC was also concerned aboutspecial conditions, such as elevatedtemperatures, disbonded coatings,thermal insulating coatings, shielding,

bacterial attack, and unusualcontaminants in the electrolyte, whichmay cause cathodic protection to beineffective. WUTC believed the rules oncoating and cathodic protection shouldaddress these special conditions. Thetheory behind final § 195.571 is that if all external surfaces of a pipeline are

cathodically protected according to thecriteria and other considerations inparagraphs 6.2 and 6.3 of the NACEStandard, external corrosion will becontrolled successfully. In practice, if anoperator learns though in-lineinspection or other means that becauseof a special condition external corrosionis not being controlled successfully, theoperator must take corrective action.The operator could either remedy thecondition or adjust the cathodicprotection system to assure theadequacy of cathodic protection in the





2Paragraph 10.1.1.3 reads: Where practicable anddetermined necessary by sound engineeringpractice, a detailed (close-interval) potential surveyshould be conducted to (a) assess the effectivenessof the cathodic protection system; (b) provide baseline operating data; (c) locate areas of inadequateprotection levels; (d) identify locations likely to beadversely affected by construction, stray currents,or other unusual environmental conditions; or (e)select areas to be monitored periodically.

area of the special condition. We believethis requirement is implicit in final§ 195.571. Section 195.573(e) alsowould require corrective action if thecondition is detected by monitoringunder § 195.573.

In addition, WUTC was concernedthat the proposed rules did not specifyhow long the cathodic protection

current may be shut off when measuringpolarization decay under the minimum100 mV criterion. WUTC suggested thatthe limit be no more than 48 hours,unless a recording chart showscontinuing significant decay beyondthat time. To satisfy the100 mV criterion

by the decay method, operators mustdetermine that a negative polarizationvoltage shift of at least 100 mV occursafter the immediate voltage shift caused

by shutting off the cathodic protectioncurrent. Whether this minimumnegative voltage shift occurs in minutesor hours after the current is cut off, it

is irrelevant to satisfying the criterion.We recognize that the longer the currentremains off, the greater the opportunityfor the pipeline to corrode. However, inour experience decay tests have notposed a serious problem in this regardto warrant establishing a time limit.

Finally, WUTC opposed use of the netprotective current criterion on bare orineffectively coated hazardous liquidpipelines. WUTC was concerned aboutthe criterion being applied only atpredetermined current discharge pointsidentified through leaks, leak history, orelectrical surveys, preventing thepipeline from having complete cathodic

protection against corrosion leaks.WUTC suggested that if we allow use of the criterion, we limit its use topipelines constructed before part 195went into effect. According to part 195’sterms, the net protective currentcriterion applies only to bare orineffectively coated pipelines. Becauseall pipelines subject to part 195construction standards must beeffectively coated, the net protectivecurrent criterion will mostly be used onolder pipelines constructed before thosestandards took effect. The effective datesfor different groups of pipelines are

stated in § 195.401(c).WUTC’s primary concern seems to bethat we did not propose a requirementthat operators fully cathodically protect

bare or ineffectively coated pipelines.We did not propose such action forseveral practical reasons. Tocathodically protect these pipelines overtheir entire surface area without firstcoating or recoating them would requirevery high levels of impressed currents.Cathodic protection systems producingsuch high current levels would be costlyto install, maintain, and operate. Also,

to coat all bare or ineffectively coated buried pipelines in order to facilitatecathodic protection could be a costlyendeavor. We also considered thepossibility that raising pipe sections tocoat them would likely createunanticipated stresses and disturb pipefoundations, introducing new riskfactors not present in the existing

pipelines.Section 195.573. This section is based

on proposed § 195.569. It requiresoperators to monitor the performance of cathodic protection facilities andmonitor unprotected pipe for activecorrosion.

Final § 195.573(a) enhances proposed§ 195.569 with regard to determinationsof the adequacy of cathodic protection.We edited § 195.573(a) to clearly statethat operators must conduct tests todetermine whether cathodic protectioncomplies with § 195.571 and notwhether cathodic protection isadequate, as proposed. In addition, weare concerned that proposed § 195.569does not provide latitude in monitoringseparately protected short segments of

bare or ineffectively coated pipelines, asdoes the corresponding rule formonitoring protected gas pipelines (49CFR 192.465(a)). The gas rule allowsmonitoring of short protected segmentsover a 10-year period where annualmonitoring is impractical. Weconsidered adding a similar provision to§ 195.573(a) but decided that the 10-yearperiod would add more latitude thancircumstances warrant on bare orineffectively coated hazardous liquid

pipelines. Many operators now monitorshort protected segments of bare orineffectively coated lines on the samecycle as adjoining unprotectedsegments. So, rather than use the gasrule provision, we added a provisionthat allows monitoring at 3-yearintervals which is consistent with themonitoring cycle we are adopting forunprotected sections (see discussion of § 195.573(b) below).

We also addressed the problem of how to test pipelines to determine theadequacy of cathodic protection. Incomplying with existing § 195.416(a),

which was the basis of proposed§ 195.569, operators generallyconducted electrical surveys. Thisaction involves measuring potentials atpre-established test stations, todetermine the adequacy of cathodicprotection. In practice, however, thismethod of compliance has not always

been sufficient to assure protection of all pipeline surfaces. Corrosionproblems often arise in areas betweentest stations where there may beinterference currents, differentenvironmental conditions, damaged

coatings, or malfunctioning anodes. So,in order to check on cathodic protectionadequacy in greater detail, manyoperators augment test station data withperiodic close-interval electrical surveysor use newer technologies. As WUTCpointed out in its comments, these moredetailed surveys also help operatorsdetermine if additional test stations are

needed to assure the adequacy of cathodic protection.

Paragraph 10.1.1.3 of NACE StandardRP0169–96 recommends that operatorsuse close-interval surveys where theyare practicable and sound engineeringjudgment indicates they are necessary.2

For this reason and because we believethe general method of monitoringcathodic protection at established teststations may not always be sufficient,we have referenced the NACE provisionin final § 195.573(a)(2). Although thefinal rule does not prescribe a frequencyof close-interval surveys, operators will

have to describe in their maintenanceprocedures the circumstances in whicha close-interval survey or comparabletechnology is practicable and necessaryto accomplish the objectives of paragraph 10.1.1.3 of the NACEStandard, and then follow thoseprocedures.

In order to provide operators withtime to prepare for compliance with thenew close-interval survey requirement,the compliance date for existingpipelines will not be mandatory untilDecember 29, 2003.

Final § 195.573(b), which is based onproposed § 195.569(c), requires that

operators must reevaluate theirunprotected pipe and cathodicallyprotect the pipe where active corrosionis found. Operators must determine if active corrosion exists by electricalsurvey where practical, or otherwise bya review and analysis of certainmaintenance records and the pipelineenvironment. Proposed definitions of the terms ‘‘active corrosion,’’ ‘‘electricalsurvey,’’ and ‘‘pipeline environment’’are combined with other definitions infinal § 195.553. Also, final § 195.573(b)applies to ‘‘pipe’’ rather than‘‘pipelines’’ as proposed, because we

did not intend for the proposed rule toapply to unprotected breakout tank bottoms. Integrity inspection of the bottoms of breakout tanks is covered byexisting § 195.432.





Equilon, Environmental Defense, andNACE argued that because unprotectedpipelines may deteriorate as they age,operators should reevaluate thesepipelines at intervals of less than 5years, the maximum interval proposedin the NPRM. They suggested that to beconsistent with part 192 we set themaximum interval at 3 years, not to

exceed 39 months. Like thesecommenters, Iowa also saw a need toadd 3 months to the maximum interval,whether it be 5 or 3 years, to providescheduling and operational flexibility.

In view of the three commentsfavoring a 3-year inspection interval andthe Technical Hazardous LiquidPipeline Safety Standards Committee’sunanimous recommendation toestablish a maximum 3-year interval(see the Advisory CommitteeConsideration heading below), wereconsidered whether the appropriatemaximum inspection interval should be

3 or 5 years. We considered the fact thatthe relation between relevant riskfactors on unprotected pipelines and anappropriate inspection interval isuncertain. As discussed in the NPRM,we are also seeking to make thecorrosion control standards for gas andhazardous liquid pipelines consistentwherever reasonable. At present part192 prescribes a maximum inspectioninterval of 3 years for unprotected gaspipelines; and part 195 prescribes 5years. Although there is no evidence inthe record to demonstrate conclusivelythe advantage of a 3-year interval overa 5-year interval, taking into

consideration the risk to the public andenvironment, we believe the moreconservative 3-year interval is theprudent choice. Furthermore, we

believe this choice is reasonable basedon our enforcement experience, as wellas, discussions with industryrepresentatives which indicate thatmany hazardous liquid pipelineoperators inspect their unprotectedpipelines every 3 years. Therefore, thefinal rule is changed from the proposedmaximum 5-year interval to a maximum3-year interval.

In order to provide operators with

time to prepare for compliance with thenew 3-year inspection interval,compliance will not be mandatory untilDecember 29, 2003.

Equilon and NACE suggested that in-line inspection may be a moreappropriate alternative to electricalsurvey than analysis of leak repairs andother matters as proposed in§ 195.569(c). However, the proposedrule did not limit an operator’s choiceof alternatives to an analysis of leakrepairs. Rather, where electrical surveysare impractical, we proposed the use of

any alternative means of determiningwhether active corrosion exists, as longas that means includes a review andanalysis of leak repair and inspectionrecords, corrosion monitoring records,exposed pipe inspection records, andthe pipeline environment. Under thefinal rule, if operators have in-lineinspection data and want to use it as an

alternative to electrical surveys wheresuch surveys are impractical, they maydo so provided they interpret the datain light of the required review andanalysis of other pertinent information.

WUTC suggested we put the followingsentence in the final rule: ‘‘Eachoperator shall take prompt remedialaction to correct any deficienciesindicated by the monitoring.’’ Wediscussed in the NPRM why we did notpropose such a requirement. We statedthat it is unnecessary to direct suchaction due to the existing requirementsunder § 195.401(b). This section

requires operators to correct within areasonable time any condition thatcould adversely affect safe operation of a pipeline system; and if an immediatehazard exists, to cease operating theaffected part of the system until thecondition is corrected. In addition, onpipelines that could affect highconsequence areas, new § 195.452(h)requires operators to take promptactions to address integrity issues and torepair certain conditions within specifictime limits. However, in light of WUTC’s comment, we established§ 195.573(e) to draw attention to the

remedial action required by existing§§ 195.401(b) and 195.452(h).WUTC also was concerned that the

discretion built into the proposeddefinition of ‘‘active corrosion’’ wouldallow operators to ignore corrosion leaksdetrimental to public safety or theenvironment. WUTC suggested werequire operators to classify andschedule all corrosion leaks for repair.In response, we believe the purpose of proposed § 195.569(c) is to requireoperators to look for and cathodicallyprotect certain areas of corrosion beforeleaks occur. Operator response to leaks,whether due to corrosion or othercauses, is not covered by new subpart H.Leak response is governed by existing§ 195.401(b) or § 195.452(h), whichtogether require timely corrective actionfor all unsafe conditions on pipelinessubject to Part 195.

Section 195.575. This standardrequires electrical isolation to providefor adequate cathodic protection. Thestandard is based on proposed§ 195.571.

Enron expressed support for theproposed rule; however, Tosco believed

we should specify the frequency of inspection and electrical tests.

We did not adopt Tosco’s comment because the purpose of the proposedinspection and electrical tests is toensure that electrical isolation isadequate when it is installed. All post-installation inspections and tests of cathodic protection facilities are

covered by final § 195.573.In final paragraph (d), for clarity, we

changed the proposed wording ‘‘wherea combustible atmosphere isanticipated’’ to read ‘‘where acombustible atmosphere is reasonable toforesee.’’ Similarly in paragraph (e), wechanged the proposed ‘‘where faultcurrents or unusual risk of lightningmay be anticipated’’ to read ‘‘where it isreasonable to foresee fault currents or anunusual risk of lightning.’’

Section 195.577. The purpose of thisstandard, which is based on proposed§ 195.575, is to minimize the adverseeffects of stray currents on pipelines andthe effects of impressed currents onadjacent structures. Expressing supportfor the proposed rule, Tosco stated thatthe proposed program to identify, testfor, and minimize the detrimentaleffects of stray currents may result inoperators participating in corrosioncoordinating groups. We agree that suchcoordination may be necessary for aneffective program.

Section 195.579. This standard,proposed as § 195.577, requiresoperators to investigate the effects of transporting hazardous liquid or carbondioxide which could corrode the

pipeline, and take adequate steps tomitigate corrosion. Tosco suggested thatin the final rule we clarify that theinvestigation may be done by review of operating history. A review of relevantoperating history may be a satisfactoryinvestigation in some situations.However, we did not explicitly includethis option in final § 195.579. We usedthe proposed wording because we thinkit is broad enough to permit operators touse any method of investigation thatwill provide a sound basis for decidinghow to mitigate internal corrosionadequately.

Under proposed § 195.577(d), if operators discover harmful corrosioninside removed pipe, they mustinvestigate further to determine if additional harmful corrosion exists inthe vicinity of the removed pipe.Phillips suggested that the extent of further investigation should dependupon the type of corrosion found andwhether that corrosion could beexpected to extend beyond the exposedsegment. We do not believe there is aclear understanding of the relationship

between the type of corrosion and the





likelihood of finding similar corrosionin the vicinity of removed pipe to justifylimits on a requirement for additionalinvestigation. The effect of corrosiveliquids on pipe may be too variable tomake such predictions with accuracy.Therefore, we did not adopt Phillips’comment.

Section 195.581. This section, based

on proposed § 195.579, modifies anexisting requirement (§ 195.416(i)) thatall pipelines exposed to the atmospheremust be protected against atmosphericcorrosion by a suitable coating. Final§ 195.581 gives operators flexibilitywhen deciding to coat pipelines whereatmospheric corrosion will be limited toa light surface oxide, or will not affectthe safe operation of the pipeline beforethe next scheduled inspection. Splashzones of offshore pipelines and soil-to-air interfaces of onshore pipelines areomitted from this exception.

Iowa opposed allowing pipe withmetal loss to remain unprotected orunrepaired. Iowa stated that publicsafety should not depend on anoperator’s judgment of whether acorroding pipe will not fail before thenext inspection (which could be up to3 years). Yet under the proposed rule, if an operator chose not to coat, it wouldhave to show that testing, investigation,or experience supports the decision. Inother words, safety would not dependsolely on an operator’s judgment. Also,the need for coating would be reviewedagain in 3 years. A 3-year delay incoating a pipeline judged to be safeshould not jeopardize public safety,

considering that atmospheric corrosiongenerally progresses at a slow rate.Therefore, we did not adopt Iowa’scomment. Nevertheless, mindful of Iowa’s concern, we edited the finalwording to clarify that any decision notto coat a particular pipeline must besupported by testing, investigation, orexperience relevant to that pipeline.

Tosco called the proposed rule ‘‘apositive revision.’’ However, Enronrecommended that we add ‘‘active’’ as adescriptor of ‘‘atmospheric corrosion.’’It believed the term ‘‘active atmosphericcorrosion’’ would clarify that the rule

does not apply to harmless corrosion.We did not adopt Enron’s comment because we think the proposedexceptions will satisfy Enron’sobjective. Also, ‘‘active atmosphericcorrosion’’ is a term that may not be ingeneral use in the industry.

Section 195.583. Under this section,proposed as § 195.581, operators mustperiodically inspect exposed pipelinesfor atmospheric corrosion, givingparticular attention to areas such as soil-to-air interfaces. Onshore pipelinesmust be inspected every 3 years; and

offshore pipelines every year. If anyinspection reveals atmosphericcorrosion, the operator must protect thepipeline against atmospheric corrosionin accordance with § 195.581.

Enron, Equilon, Iowa, and NACEadvocated adding a 3 months graceperiod to the maximum 3-yearinspection interval. We agree that this

period is useful to allow operatorsscheduling and operational flexibility,and included it in final § 195.583.

Tosco wanted to make certain that theproposed remedial action would not berequired for light surface oxide. By thecross reference to § 195.581, final§ 195.583 allows operators latitudewhen deciding to coat pipelines whichexhibit only a light surface oxide.

AEC urged us to allow operators touse means of assessment other thanperiodic visual inspection. As anexample, AEC commented that by usingin-line inspection and a corrosiongrowth model, operators could predictwhen a pipeline should be reinspectedor repaired. This approach, according toAEC, would enable operators to allocateresources for maximum benefits insteadof periodically scattering them acrossentire systems. AEC’s commentindicates two things: first, AECapparently misunderstood the proposedrule to mandate visual inspection; andsecond, AEC would like operatorsthemselves to decide appropriateinspection frequencies with the aid of acorrosion growth model. As to the firstitem, the proposed rule would not limitoperators to using visual means of

inspection. They could use any meanscapable of detecting atmosphericcorrosion, including in-line inspectiondevices. As to growth models, AEC didnot suggest which model, if any, cansuccessfully predict the growth of atmospheric corrosion on exposedpipelines in changing and variedenvironments. Furthermore, AEC didnot suggest how operators would decidewhen to inspect exposed pipe that hasno history of corrosion. Since the recordof this rulemaking proceeding lacksinformation on these important issues,we have adopted the proposed

inspection frequencies as final.However, we would welcome receivingmore complete information that couldpossibly serve as a basis for changingthe rule as AEC suggests.

AEC also suggested we extend theproposed maximum inspection intervalfor onshore pipelines from 3 years to 5years. It believes that extending the timeto 5 years is appropriate becauseatmospheric corrosion rates are low, andexposed pipe is typically locatedoutside high consequence areas wherethe maximum interval for reevaluation

of pipeline integrity is 5 years (see§ 195.452(j)(3)). In developing theproposed rule, we considered whether 3or 5 years would be the appropriatemaximum interval. We proposed 3 yearsprimarily because the ASME B31.4Code, a widely accepted consensusstandards code for hazardous liquidpipelines, specifies a minimum 3-year

inspection frequency for atmosphericcorrosion onshore. Generally,atmospheric corrosion rates are found to

be low and therefore, we must assumethis factor was considered when the 3-year consensus standard was adopted.However, a low rate by itself does notseem to justify a longer interval. Also,the 5-year interval for integrityreevaluation in high consequence areasis based on various factors besidescorrosion rate, including the timeneeded to carry out in-line inspectionsor pressure testing on the pipelinesinvolved. Moreover, the 5-year

reevaluation applies in addition to othermonitoring frequencies required by part195, such as annual cathodic protectionmonitoring and biweekly right-of-wayinspections. Yet, we did not intend the5-year period to serve as a yardstick fordetermining the adequacy of othermonitoring frequencies.

Finally, AEC was concerned about thepossible adverse consequences of visually inspecting soil-to-air interfaceson pipe spans over creeks and ravines.AEC suggested that if the interface is ona steep bank, the process of visuallyexamining the pipe could accelerate

bank erosion causing water pollutionand overstress of the pipeline. We believe the proposed inspectionrequirement is flexible enough to allowoperators to take precautions ininspecting soil-to-air interfaces on steep

banks to avoid or minimize thedisturbance AEC foresees. Should adisturbance occur that affects the safeoperation of the pipeline, the operatorwould have to correct the problem. Wedid not change the final rule as a resultof this comment.

Section 195.585. This section, whichis substantively the same as proposed

§ 195.583, requires operators to takecertain actions to correct corroded pipe.If general corrosion reduces pipe wallthickness to less than that required forthe maximum operating pressure of thepipeline or if localized corrosion pittingexists to a degree that leakage mightresult, the operator must: replace thepipe; repair the pipe; or reduce themaximum operating pressurecommensurate with the strength of thepipe. We edited the final rule to clarifythat it is the ‘‘maximum operatingpressure’’ that must be reduced.





Environmental Defense believed thissection also should require operators toaccount for why corrosion has becomeso advanced. This commenter suggestedoperators should review their corrosioncontrol systems to ensure that furtherharmful corrosion will not occur. We

believe the combination of cathodicprotection criteria under § 195.571 and

periodic monitoring under § 195.573will accomplish the objective of thiscomment. Whenever an operatordiscovers a corrosion control deficiency,it must review its corrosion controlsystem and make adjustments asnecessary to provide adequateprotection against corrosion. If adequateprotection cannot be achieved, the pipeinvolved may have to be replaced.

Section 195.587. This section is basedon proposed § 195.585. It authorizes, butdoes not require, operators to use thewidely accepted ASME B31G criteria fordetermining the remaining strength of

corroded steel pipe.Iowa fully supported the proposedrule. In contrast, WUTC was concernedthat because ASME B31G allows wallloss of up to 80 percent without repairor replacement, it does not provide areasonable measure of strength neededto withstand cyclical stresses,environmental loads, and othercombined forces.

Although WUTC is correct, weconsider B31G to be a guide to thecapability of corroded pipe to withstandinternal pressure. Final § 195.587advises operators that B31G sets limitson use of the criteria. One limitation

states that a pipe subject to significantsecondary stresses should not be kept inservice for the purpose of satisfying thecriteria (paragraph 1.2(d)). To ensurethat operators consider the effects of secondary stresses, in final§ 195.585(a)(1), we added the words‘‘needed for serviceability’’ immediatelyfollowing ‘‘strength of the pipe.’’Consequently, as a remedy for generallycorroded pipe, operators may reducemaximum pressure commensurate withthe pipe strength needed forserviceability. In determining theamount of pressure reduction required,

operators may use B31G but also mustconsider any significant secondarystresses that may affect pipeserviceability.

Section 195.589. Under this section,proposed as § 195.587, operators must tokeep current records or maps of thelocation of cathodically protectedpipelines; cathodic protection facilities(including anodes) installed after theFinal Rule takes effect; and structures

bonded to cathodic protection systems.Additionally, operators must keeprecords of required maintenance

activities including inspections, tests,analyses, checks, demonstrations,examinations, investigations, reviews,and surveys. These records mustdemonstrate the adequacy of corrosioncontrol measures, or that corrosionrequiring control measures does notexist. Operators will have to keep theserecords for at least 5 years, except that

records related to § 195.569(examination of pipeline whenexposed); §§ 195.573(a) and (c)(monitoring external corrosion control);and §§ 195.579(b)(3) and (c) (monitoringinternal corrosion control) will have to

be kept for as long as the pipelineinvolved is in service.

Commenting on examinations of exposed pipe, Equilon and NACE

believed that there is no need to keeprecords of good pipe for as long as thepipeline remains in service, and thatthere is no need to keep records of defective pipe after the latest in-line

inspection. Equilon and NACE alsocontended that old records of internalcorrosion monitoring are of little benefitwithout knowledge of flow rates,upstream pipeline operations, fluidproperties, and other information. Noneof these records are generally available.We did not adopt either comment

because the proposed records provide auseful history of pipeline condition andare easy to maintain in electronic form.The records may be helpful in assessingcorrosion control needs, and could beused as a comparative base forevaluating in-line inspection data.

We also considered the Equilon andNACE comment that subpart H shouldnot require operators to keep records of maintenance activities that occur beforesubpart H takes effect. Final § 195.589specifically states that records must bekept for certain maintenance activities‘‘required by this subpart.’’ For example,final § 195.589 does not requireoperators to keep records of corrosioncontrol monitoring conducted beforesubpart H takes effect. However, untilsubpart H takes effect, § 195.404(c)(3)requires records of corrosion controlinspections and tests required bysubpart F of part 195. Operators mustcontinue to maintain recordsestablished under that section for theretention period prescribed.

Tosco believed we should revise§ 195.404(c)(3) to indicate that corrosioncontrol records are required by subpartH. However, no confusion about theapplication of § 195.404(c)(3) tocorrosion control should occur becausethis section applies only to inspectionsand tests ‘‘required by this subpart,’’meaning, required by subpart F. Afternew subpart H goes into effect, Subpart

F will no longer require corrosioncontrol inspections and tests.

Phillips argued that the current 2-yearretention requirement in § 195.404(c)(3)is adequate for auditing compliance,since 2 years of records show thecurrent state of corrosion control.However, as we explained in the NPRM,5 years is the minimum retention period

that will assure the availability of records for our compliance auditing.

Environmental Defense stated that itwould help government inspectorsdetermine the adequacy of cathodicprotection systems if we requiredoperators to keep records of the locationof existing cathodic protection facilitiesand not just those facilities installedafter subpart H takes effect. While thissuggestion has merit, we did notpropose to require records of existingfacilities due to the difficulty of creatingsuch records, particularly for galvanicanode systems. Also, in our experiencethe lack of such a requirement has notcaused a significant problem due to thenumber of operators who keep recordsof the location of existing corrosioncontrol facilities.

Format and Organization

In accordance with Federal Registerguidelines, we drafted final subpart H inan easier to read and understand format.Section headings are in the form of questions. We minimized passive voiceand used the word ‘‘you’’ as a substitutefor ‘‘operator.’’ Also, a few proposedsections were eliminated, combinedwith other sections, or separated into

two or more sections. This Final Rulealso changes §§ 195.5, 195.402, 195.404and removes §§ 195.236, 195.238,195.242, 195.244, 195.414, 195.416,195.418 to account for the new subpartH.

Advisory Committee Consideration

We presented the NPRM forconsideration by the TechnicalHazardous Liquid Pipeline SafetyStandards Committee (THLPSSC) at ameeting in Washington, DC on February7, 2001 (66 FR 132; Jan. 2, 2001). TheTHLPSSC is RSPA’s statutory advisory

committee for hazardous liquid pipelinesafety. The committee has 15 members,representing industry, government, andthe public. Each member is qualified toconsider the technical feasibility,reasonableness, cost-effectiveness, andpracticability of proposed pipelinesafety standards. The committee votedunanimously to approve proposedsubpart H but unanimouslyrecommended that we require operatorsof bare or ineffectively coated pipe toinspect the pipe for external corrosionevery 3 years. Our treatment of this





recommendation is discussed in theDiscussion of Comments section undersection 195.573. A transcript of theFebruary 7, 2001, meeting is available inDocket No. RSPA–98–4470.

Regulatory Analyses and Notices

Executive Order 12866 and DOT Policies and Procedures. RSPA does not

consider this rulemaking to be asignificant regulatory action undersection 3(f) of Executive Order 12866(58 FR 51735; Oct. 4, 1993). Therefore,the Office of Management and Budget(OMB) has not received a copy of thisrulemaking to review. RSPA also doesnot consider this rulemaking to besignificant under DOT regulatorypolicies and procedures (44 FR 11034:February 26, 1979).

We prepared a Final RegulatoryEvaluation of the final rules and a copyis in the docket. The evaluation statesthat the rules are, on the whole,

comparable either to existing safetystandards currently in part 195 forhazardous liquid pipelines or to existingsafety standards in part 192 for gaspipelines. The evaluation also statesthat the information presented at publicmeetings and meetings with industryand state representatives stronglysuggests that imposing gas pipelinesafety standards for corrosion control onhazardous liquid pipelines would notrequire a significant departure fromcustomary safety practices on liquidpipelines.

An important feature of the final rules

not found in part 192 or part 195 is thereference to cathodic protection criteriain NACE Standard RP0169–96. Theevaluation states that these criteria arewell known and widely followedthroughout the industry, as indicated bymeetings with industry representativesand by the voluntary standards in theASME B31.4 Code. The evaluationfurther states that operators who do notnow apply the NACE criteria are likelyto apply the criteria in appendix D of part 192. The final rules would allowuse of appendix D criteria underconditions stated in the NACE Standard.The evaluation concludes that thereshould be only minimal additional cost,if any, for operators to comply with thefinal rules.

Final § 195.563(c) (protectingeffectively coated pipelines), § 195.567(test leads), and § 195.573(a)(2)(monitoring cathodic protection byclose-interval surveys or comparabletechnology) are changed from theproposed rules. However, the changesare consistent with industry practicesand should not result in more thanminimal additional costs.

Regulatory Flexibility Act. The finalrules are consistent with customarypractices for corrosion control in thehazardous liquid and carbon dioxidepipeline industry. Therefore, based onthe facts available about the anticipatedimpacts of this rulemaking, I certify,pursuant to section 605 of theRegulatory Flexibility Act (5 U.S.C.

605), that this rulemaking will not havea significant impact on a substantialnumber of small entities.

Executive Order 13084. The finalrules have been analyzed in accordancewith the principles and criteriacontained in Executive Order 13084,‘‘Consultation and Coordination withIndian Tribal Governments.’’ Becausethe rules will not significantly oruniquely affect the communities of theIndian tribal governments and will notimpose substantial direct compliancecosts, the funding and consultationrequirements of Executive Order 13084

do not apply.Paperwork Reduction Act. Section195.589 contains minor additionalinformation collection requirements.Operators will be required to record thelocation of certain newly installedprotection facilities, and keep theserecords for as long as the pipelineconcerned is in service. In addition,records of inspections, tests, and othermaintenance actions will have to bekept for as long as the pipeline is inservice or for 5 years, depending on thenature of the information recorded. Thepresent minimum retention period forrecords of inspections and tests is 2

years or the prescribed interval of test orinspection, whichever is longer (up to 5years in some cases).

Hazardous liquid pipeline operatorsare required to keep records underInformation Collection 2137–0047,Transportation of Hazardous Liquids byPipeline: Record Keeping and ReportingRequirements. Operators alreadymaintain records of the location of theirprotection facilities for as long as thepipeline is in service. They do so to findthe facilities for their own purposes andto carry out existing monitoringrequirements in part 195. Also, we

believe the burden of retaininginspection, test, and survey records forthe longer period will be minimal.These records are largely computerizedand maintaining these records in acomputer file represents very minimalcosts. Because the additional paperwork

burdens of this final rule are likely to beminimal, we believe that submitting ananalysis of the burdens to OMB underthe Paperwork Reduction Act isunnecessary.

Unfunded Mandates Reform Act of 1995. This rulemaking will not impose

unfunded mandates under theUnfunded Mandates Reform Act of 1995. It will not result in costs of $100million or more to either State, local, ortribal governments, in the aggregate, orto the private sector, and is the least

burdensome alternative that achievesthe objective of the rule.

National Environmental Policy Act.

We have analyzed the final rules forpurposes of the National EnvironmentalPolicy Act (42 U.S.C. 4321 et seq.).Because the rules parallel presentrequirements or practices, we havedetermined they will not significantlyaffect the quality of the humanenvironment. An environmentalassessment document is available forreview in the docket. We also made afinding of no significant impact.

Impact on Business Processes and Computer Systems. We do not want toimpose new requirements that mandate

business process changes when theresources necessary to implement thoserequirements could otherwise beapplied to ‘‘Y2K’’ or related computerproblems. The final rules do notmandate business process changes orrequire modifications to computersystems. Because the rules do not affectthe ability of organizations to respond tothose problems, we have not delayedthe effectiveness of the requirements.

Executive Order 13132. The finalrules have been analyzed in accordancewith the principles and criteriacontained in Executive Order 13132(‘‘Federalism’’). The final rules do notcontain any regulation that (1) has

substantial direct effects on the States,the relationship between the nationalgovernment and the States, or thedistribution of power andresponsibilities among the variouslevels of government; (2) imposessubstantial direct compliance costs onState and local governments; or (3)preempts state law. Therefore, theconsultation and funding requirementsof Executive Order 13132 do not apply.Nevertheless, during our review of theexisting corrosion control standards,representatives of state pipeline safetyagencies gave us advice both in private

sessions and in the two public meetingswe held. In addition, our pipeline safetyadvisory committees, which includerepresentatives of state governments,were, on two occasions in 1999, briefedon the corrosion control review project.

Executive Order 13211. Thisrulemaking is not a ‘‘Significant energyaction’’ under Executive Order 13211. Itis not a significant regulatory actionunder Executive Order 12866 and is notlikely to have a significant adverse effecton the supply, distribution, or use of energy. Further, this rulemaking has not





been designated by the Administrator of the Office of Information and RegulatoryAffairs as a significant energy action.

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, 49CFR part 195 is amended as follows:

PART 195 —[AMENDED]

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

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

2. Section 195.3 is amended byadding paragraphs (b)(8) and (c)(7) toread as follows:

§ 195.3 Matter incorporated by reference.

* * * * *

(b) * * *(8) NACE International, 1440 South

Creek Drive, Houston, TX 77084.(c) * * *(7) NACE International (NACE):(i) NACE Standard RP0169–96,

‘‘Control of External Corrosion onUnderground or Submerged MetallicPiping Systems’ (1996).

(ii) [Reserved]3. Section 195.5(b) is revised to read

as follows:

§ 195.5 Conversion to service subject tothis part.

* * * * *(b) A pipeline that qualifies for use

under this section need not comply withthe corrosion control requirements of subpart H of this part until 12 monthsafter it is placed into service,notwithstanding any previous deadlinesfor compliance.

* * * * *4. Section 195.402(c)(3) is revised to

read as follows:

§ 195.402 Procedural manual foroperations, maintenance, and emergencies.

* * * * *

(c) * * *(3) Operating, maintaining, and

repairing the pipeline system inaccordance with each of therequirements of this subpart and subpartH of this part.

* * * * *

§ 195.404 [Amended]

5. In § 195.404, paragraph (a)(1)(v) isremoved, and paragraphs (a)(1)(vi)through (a)(1)(viii) are redesignated asparagraphs (a)(1)(v) through (a)(1)(vii).

§§ 195.236, 195.238, 195.242, 195.244,195.414, 195.416, 195.418 [Removed]

6. The following sections are removedand reserved: §§ 195.236, 195.238,195.242, 195.244, 195.414, 195.416, and195.418.

7. Subpart H is added to read asfollows:

Subpart H —Corrosion ControlSec.195.551 What do the regulations in this

subpart cover?195.553 What special definitions apply to

this subpart?195.555 What are the qualifications for

supervisors?195.557 Which pipelines must have coating

for external corrosion control?195.559 What coating material may I use for

external corrosion control?195.561 When must I inspect pipe coating

used for external corrosion control?195.563 Which pipelines must have

cathodic protection?195.565 How do I install cathodic

protection on breakout tanks?195.567 Which pipelines must have test

leads and how do I install and maintainthe leads?

195.569 Do I have to examine exposedportions of buried pipelines?

195.571 What criteria must I use todetermine the adequacy of cathodicprotection?

195.573 What must I do to monitor externalcorrosion control?

195.575 Which facilities must I electricallyisolate and what inspections, tests, andsafeguards are required?

195.577 What must I do to alleviateinterference currents?

195.579 What must I do to mitigate internal

corrosion?195.581 Which pipelines must I protect

against atmospheric corrosion and whatcoating material may I use?

195.583 What must I do to monitoratmospheric corrosion control?

195.585 What must I do to correct corrodedpipe?

195.587 What methods are available todetermine the strength of corroded pipe?

195.589 What corrosion control informationdo I have to maintain?

Subpart H —Corrosion Control

§ 195.551 What do the regulations in thissubpart cover?

This subpart prescribes minimumrequirements for protecting steelpipelines against corrosion.

§ 195.553 What special definitions apply tothis subpart?

As used in this subpart—Active corrosion means continuing

corrosion which, unless controlled,could result in a condition that isdetrimental to public safety or theenvironment.

Buried means covered or in contactwith soil.

Electrical survey means a series of closely spaced pipe-to-soil readings overa pipeline that are subsequentlyanalyzed to identify locations where acorrosive current is leaving the pipeline.

Pipeline environment includes soilresistivity (high or low), soil moisture(wet or dry), soil contaminants that maypromote corrosive activity, and other

known conditions that could affect theprobability of active corrosion.

You means operator.

§ 195.555 What are the qualifications forsupervisors?

You must require and verify thatsupervisors maintain a thoroughknowledge of that portion of thecorrosion control proceduresestablished under § 195.402(c)(3) forwhich they are responsible for insuringcompliance.

§ 195.557 Which pipelines must havecoating for external corrosion control?

Except bottoms of aboveground breakout tanks, each buried orsubmerged pipeline must have anexternal coating for external corrosioncontrol if the pipeline is—

(a) Constructed, relocated, replaced,or otherwise changed after theapplicable date in § 195.401(c), notincluding the movement of pipe covered

by § 195.424; or(b) Converted under § 195.5 and—(1) Has an external coating that

substantially meets § 195.559 before thepipeline is placed in service; or

(2) Is a segment that is relocated,replaced, or substantially altered.

§ 195.559 What coating material may I usefor external corrosion control?

Coating material for externalcorrosion control under § 195.557must—

(a) Be designed to mitigate corrosionof the buried or submerged pipeline;

(b) Have sufficient adhesion to themetal surface to prevent under filmmigration of moisture;

(c) Be sufficiently ductile to resistcracking;

(d) Have enough strength to resistdamage due to handling and soil stress;

(e) Support any supplemental

cathodic protection; and(f) If the coating is an insulating type,

have low moisture absorption andprovide high electrical resistance.

§ 195.561 When must I inspect pipecoating used for external corrosioncontrol?

(a) You must inspect all external pipecoating required by § 195.557 just priorto lowering the pipe into the ditch orsubmerging the pipe.

(b) You must repair any coatingdamage discovered.





1A pipeline does not have an effective externalcoating material if the current required tocathodically protect the pipeline is substantially thesame as if the pipeline were bare.

§ 195.563 Which pipelines must havecathodic protection?

(a) Each buried or submerged pipelinethat is constructed, relocated, replaced,or otherwise changed after theapplicable date in § 195.401(c) musthave cathodic protection. The cathodicprotection must be in operation not later

than 1 year after the pipeline isconstructed, relocated, replaced, orotherwise changed, as applicable.

(b) Each buried or submerged pipelineconverted under § 195.5 must havecathodic protection if the pipeline—

(1) Has cathodic protection thatsubstantially meets § 195.571 before thepipeline is placed in service; or

(2) Is a segment that is relocated,replaced, or substantially altered.

(c) All other buried or submergedpipelines that have an effective externalcoating must have cathodic protection.1

Except as provided by paragraph (d) of this section, this requirement does notapply to breakout tanks and does notapply to buried piping in breakout tankareas and pumping stations untilDecember 29, 2003.

(d) Bare pipelines, breakout tankareas, and buried pumping stationpiping must have cathodic protection inplaces where regulations in effect before

January 28, 2002 required cathodicprotection as a result of electricalinspections. See previous editions of this part in 49 CFR, parts 186 to 199.

(e) Unprotected pipe must have

cathodic protection if required by§ 195.573(b).

§ 195.565 How do I install cathodicprotection on breakout tanks?

After October 2, 2000, when youinstall cathodic protection under§ 195.563(a) to protect the bottom of anaboveground breakout tank of more than500 barrels (79.5m3) capacity built toAPI Specification 12F, API Standard620, or API Standard 650 (or itspredecessor Standard 12C), you mustinstall the system in accordance withAPI Recommended Practice 651.

However, installation of the systemneed not comply with APIRecommended Practice 651 on any tankfor which you note in the corrosioncontrol procedures established under§ 195.402(c)(3) why compliance with allor certain provisions of APIRecommended Practice 651 is notnecessary for the safety of the tank.

§ 195.567 Which pipelines must have testleads and what must I do to install andmaintain the leads?

(a) General. Except for offshorepipelines, each buried or submergedpipeline or segment of pipeline undercathodic protection required by thissubpart must have electrical test leadsfor external corrosion control. However,

this requirement does not apply untilDecember 27, 2004 to pipelines orpipeline segments on which test leadswere not required by regulations ineffect before January 28, 2002.

(b) Installation. You must install testleads as follows:

(1) Locate the leads at intervalsfrequent enough to obtain electricalmeasurements indicating the adequacyof cathodic protection.

(2) Provide enough looping or slack so backfilling will not unduly stress or break the lead and the lead willotherwise remain mechanically secure

and electrically conductive.(3) Prevent lead attachments fromcausing stress concentrations on pipe.

(4) For leads installed in conduits,suitably insulate the lead from theconduit.

(5) At the connection to the pipeline,coat each bared test lead wire and baredmetallic area with an electricalinsulating material compatible with thepipe coating and the insulation on thewire.

(c) Maintenance. You must maintainthe test lead wires in a condition thatenables you to obtain electricalmeasurements to determine whethercathodic protection complies with§ 195.571.

§ 195.569 Do I have to examine exposedportions of buried pipelines?

Whenever you have knowledge thatany portion of a buried pipeline isexposed, you must examine the exposedportion for evidence of externalcorrosion if the pipe is bare, or if thecoating is deteriorated. If you findexternal corrosion requiring correctiveaction under § 195.585, you mustinvestigate circumferentially andlongitudinally beyond the exposed

portion (by visual examination, indirectmethod, or both) to determine whetheradditional corrosion requiring remedialaction exists in the vicinity of theexposed portion.

§ 195.571 What criteria must I use todetermine the adequacy of cathodicprotection?

Cathodic protection required by thissubpart must comply with one or moreof the applicable criteria and otherconsiderations for cathodic protectioncontained in paragraphs 6.2 and 6.3 of

NACE Standard RP0169–96(incorporated by reference, see § 195.3).

§ 195.573 What must I do to monitorexternal corrosion control?

(a) Protected pipelines. You must dothe following to determine whethercathodic protection required by thissubpart complies with § 195.571:

(1) Conduct tests on the protectedpipeline at least once each calendaryear, but with intervals not exceeding15 months. However, if tests at thoseintervals are impractical for separatelyprotected short sections of bare orineffectively coated pipelines, testingmay be done at least once every 3calendar years, but with intervals notexceeding 39 months.

(2) Identify before December 29, 2003or not more than 2 years after cathodicprotection is installed, whichever comeslater, the circumstances in which aclose-interval survey or comparabletechnology is practicable and necessaryto accomplish the objectives of paragraph 10.1.1.3 of NACE StandardRP0169–96 (incorporated by reference,see § 195.3).

(b) Unprotected pipe. You mustreevaluate your unprotected buried orsubmerged pipe and cathodicallyprotect the pipe in areas in which activecorrosion is found, as follows:

(1) Determine the areas of activecorrosion by electrical survey, or wherean electrical survey is impractical, by

other means that include review andanalysis of leak repair and inspectionrecords, corrosion monitoring records,exposed pipe inspection records, andthe pipeline environment.

(2) For the period in the first column,the second column prescribes thefrequency of evaluation.

Period Evaluation frequency

Before December 29,2003.

At least once every 5calendar years, butwith intervals notexceeding 63

months.Beginning December

29, 2003.At least once every 3

calendar years, butwith intervals notexceeding 39months.

(c) Rectifiers and other devices. Youmust electrically check for properperformance each device in the firstcolumn at the frequency stated in thesecond column.





Device Check frequency

Rectifier ..................... At least six timeseach calendar year,but with intervalsnot exceeding 21 ⁄ 2months.

Reverse currentswitch.

Diode .........................

Interference bondwhose failure would jeopardize struc-tural protection.

Other interferencebond.

At least once eachcalendar year, butwith intervals notexceeding 15months.

(d) Breakout tanks. You must inspecteach cathodic protection system used tocontrol corrosion on the bottom of anaboveground breakout tank to ensurethat operation and maintenance of thesystem are in accordance with API

Recommended Practice 651. However,this inspection is not required if younote in the corrosion control proceduresestablished under § 195.402(c)(3) whycompliance with all or certain operationand maintenance provisions of APIRecommended Practice 651 is notnecessary for the safety of the tank.

(e) Corrective action. You mustcorrect any identified deficiency incorrosion control as required by§ 195.401(b). However, if the deficiencyinvolves a pipeline in an integritymanagement program under § 195.452,you must correct the deficiency as

required by § 195.452(h).§ 195.575 Which facilities must Ielectrically isolate and what inspections,tests, and safeguards are required?

(a) You must electrically isolate each buried or submerged pipeline fromother metallic structures, unless youelectrically interconnect andcathodically protect the pipeline andthe other structures as a single unit.

(b) You must install one or moreinsulating devices where electricalisolation of a portion of a pipeline isnecessary to facilitate the application of corrosion control.

(c) You must inspect and electricallytest each electrical isolation to assurethe isolation is adequate.

(d) If you install an insulating devicein an area where a combustibleatmosphere is reasonable to foresee, youmust take precautions to prevent arcing.

(e) If a pipeline is in close proximityto electrical transmission tower footings,ground cables, or counterpoise, or inother areas where it is reasonable toforesee fault currents or an unusual riskof lightning, you must protect thepipeline against damage from fault

currents or lightning and take protectivemeasures at insulating devices.

§ 195.577 What must I do to alleviateinterference currents?

(a) For pipelines exposed to straycurrents, you must have a program toidentify, test for, and minimize thedetrimental effects of such currents.

(b) You must design and install eachimpressed current or galvanic anodesystem to minimize any adverse effectson existing adjacent metallic structures.

§ 195.579 What must I do to mitigateinternal corrosion?

(a) General. If you transport anyhazardous liquid or carbon dioxide thatwould corrode the pipeline, you mustinvestigate the corrosive effect of thehazardous liquid or carbon dioxide onthe pipeline and take adequate steps tomitigate internal corrosion.

(b) Inhibitors. If you use corrosion

inhibitors to mitigate internal corrosion,you must—(1) Use inhibitors in sufficient

quantity to protect the entire part of thepipeline system that the inhibitors aredesigned to protect;

(2) Use coupons or other monitoringequipment to determine theeffectiveness of the inhibitors inmitigating internal corrosion; and

(3) Examine the coupons or othermonitoring equipment at least twiceeach calendar year, but with intervalsnot exceeding 71 ⁄ 2 months.

(c) Removing pipe. Whenever you

remove pipe from a pipeline, you mustinspect the internal surface of the pipefor evidence of corrosion. If you findinternal corrosion requiring correctiveaction under §195.585, you mustinvestigate circumferentially andlongitudinally beyond the removed pipe(by visual examination, indirectmethod, or both) to determine whetheradditional corrosion requiring remedialaction exists in the vicinity of theremoved pipe.

(d) Breakout tanks. After October 2,2000, when you install a tank bottomlining in an aboveground breakout tank

built to API Specification 12F, APIStandard 620, or API Standard 650 (orits predecessor Standard 12C), you mustinstall the lining in accordance with APIRecommended Practice 652. However,installation of the lining need notcomply with API RecommendedPractice 652 on any tank for which younote in the corrosion control proceduresestablished under § 195.402(c)(3) whycompliance with all or certainprovisions of API RecommendedPractice 652 is not necessary for thesafety of the tank.

§ 195.581 Which pipelines must I protectagainst atmospheric corrosion and whatcoating material may I use?

(a) You must clean and coat eachpipeline or portion of pipeline that isexposed to the atmosphere, exceptpipelines under paragraph (c) of thissection.

(b) Coating material must be suitable

for the prevention of atmosphericcorrosion.

(c) Except portions of pipelines inoffshore splash zones or soil-to-airinterfaces, you need not protect againstatmospheric corrosion any pipeline forwhich you demonstrate by test,investigation, or experience appropriateto the environment of the pipeline thatcorrosion will—

(1) Only be a light surface oxide; or(2) Not affect the safe operation of the

pipeline before the next scheduledinspection.

§ 195.583 What must I do to monitoratmospheric corrosion control?

(a) You must inspect each pipeline orportion of pipeline that is exposed tothe atmosphere for evidence of atmospheric corrosion, as follows:

If the pipeline islocated:

Then the frequency ofinspection is:

Onshore .................... At least once every 3calendar years, butwith intervals notexceeding 39months.

Offshore .................... At least once eachcalendar year, but

with intervals notexceeding 15months.

(b) During inspections you must giveparticular attention to pipe at soil-to-airinterfaces, under thermal insulation,under disbonded coatings, at pipesupports, in splash zones, at deckpenetrations, and in spans over water.

(c) If you find atmospheric corrosionduring an inspection, you must provideprotection against the corrosion asrequired by § 195.581.

§ 195.585 What must I do to correct

corroded pipe?

(a) General corrosion. If you find pipeso generally corroded that the remainingwall thickness is less than that requiredfor the maximum operating pressure of the pipeline, you must replace the pipe.However, you need not replace the pipeif you—

(1) Reduce the maximum operatingpressure commensurate with thestrength of the pipe needed forserviceability based on actual remainingwall thickness; or





(2) Repair the pipe by a method thatreliable engineering tests and analysesshow can permanently restore theserviceability of the pipe.

(b) Localized corrosion pitting. If youfind pipe that has localized corrosionpitting to a degree that leakage mightresult, you must replace or repair thepipe, unless you reduce the maximum

operating pressure commensurate withthe strength of the pipe based on actualremaining wall thickness in the pits.

§ 195.587 What methods are available todetermine the strength of corroded pipe?

Under § 195.585, you may use theprocedure in ASME B31G, ‘‘Manual forDetermining the Remaining Strength of Corroded Pipelines,’’ or the proceduredeveloped by AGA/Battelle, ‘‘AModified Criterion for Evaluating theRemaining Strength of Corroded Pipe

(with RSTRENG disk),’’ to determine thestrength of corroded pipe based onactual remaining wall thickness. Theseprocedures apply to corroded regionsthat do not penetrate the pipe wall,subject to the limitations set out in therespective procedures.

§ 195.589 What corrosion control

information do I have to maintain?(a) You must maintain current records

or maps to show the location of —(1) Cathodically protected pipelines;(2) Cathodic protection facilities,

including galvanic anodes, installedafter January 28, 2002; and

(3) Neighboring structures bonded tocathodic protection systems.

(b) Records or maps showing a statednumber of anodes, installed in a statedmanner or spacing, need not showspecific distances to each buried anode.

(c) You must maintain a record of each analysis, check, demonstration,examination, inspection, investigation,review, survey, and test required by thissubpart in sufficient detail todemonstrate the adequacy of corrosioncontrol measures or that corrosionrequiring control measures does notexist. You must retain these records forat least 5 years, except that recordsrelated to §§ 195.569, 195.573(a) and (b),and 195.579(b)(3) and (c) must beretained for as long as the pipelineremains in service.

Issued in Washington, DC on December 19,2001.

Ellen G. Engleman,

Administrator.

[FR Doc. 01–31655 Filed 12–26–01; 8:45 am]

BILLING CODE 4910 –60 –P

Documents

Controlling Corrosion on Hazardous