# Controlling Corrosion on Hazardous Liquid and Carbon Dioxide Pipelines

- **operation:** document
- **citation:** 66 FR 66994
- **title:** Controlling Corrosion on Hazardous Liquid and Carbon Dioxide Pipelines
- **source type:** rulemaking
- **agency:** Research and Special Programs Administration
- **status:** historical
- **official:** true
- **published on:** 2001-12-27
- **effective on:** 2002-01-28
- **summary:** This Final Rule makes changes in some of the corrosion control standards for hazardous liquid and carbon dioxide pipelines. The changes are based on our review of the adequacy of the present standards compared to similar standards for gas pipelines and acceptable safety practices. The changes are intended to improve the clarity and effectiveness of the present standards, and reduce the potential for pipeline accidents due to corrosion.
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- **source url:** https://www.federalregister.gov/documents/2001/12/27/01-31655/controlling-corrosion-on-hazardous-liquid-and-carbon-dioxide-pipelines
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Federal Register, Volume 66 Issue 248 (Thursday, December 27, 2001) [Federal Register Volume 66, Number 248 (Thursday, December 27, 2001)] [Rules and Regulations] [Pages 66994-67007] From the Federal Register Online via the Government Publishing Office [ www.gpo.gov ] [FR Doc No: 01-31655] [[Page 66993]] ----------------------------------------------------------------------- Part III Department of Transportation ----------------------------------------------------------------------- Research and Special Programs Administration ----------------------------------------------------------------------- 49 CFR Part 195 Controlling Corrosion on Hazardous Liquid and Carbon Dioxide Pipelines; Final Rule Federal Register / Vol. 66, No. 248 / Thursday, December 27, 2001 / Rules and Regulations [[Page 66994]] ----------------------------------------------------------------------- DEPARTMENT OF TRANSPORTATION Research and Special Programs Administration 49 CFR Part 195 [Docket No. RSPA-97-2762; Amdt. 195-73] RIN 2137-AD24 Controlling Corrosion on Hazardous Liquid and Carbon Dioxide Pipelines AGENCY: Research and Special Programs Administration (RSPA), DOT. ACTION: Final rule. ----------------------------------------------------------------------- SUMMARY: This Final Rule makes changes in some of the corrosion control standards for hazardous liquid and carbon dioxide pipelines. The changes are based on our review of the adequacy of the present standards compared to similar standards for gas pipelines and acceptable safety practices. The changes are intended to improve the clarity and effectiveness of the present standards, and reduce the potential for pipeline accidents due to corrosion. DATES: This Final Rule takes effect January 28, 2002. The incorporation by reference of the publication listed in the rule is approved by the Director of the Federal Register January 28, 2002. Compliance dates: Under Sec. 195.563(c), operators of certain effectively coated buried piping in breakout tank areas or pump stations are not required to cathodically protect that piping until December 29, 2003. Under Sec. 195.567(a), operators of cathodically protected pipelines or pipeline segments that lack test leads for external corrosion control are not required to install test leads until December 29, 2004. Under Sec. 195.573(a)(2), operators are not required to determine the circumstances in which a close-interval survey or comparable technology is practicable and necessary until December 29, 2003. Under Sec. 195.573(b), operators of unprotected pipe are not required to reevaluate the need for corrosion control on the pipe at least every 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, 400 Seventh Street, SW., Washington, DC 20590, or by E-mail at [email protected] . SUPPLEMENTARY INFORMATION: Background Corrosion causes a significant proportion of hazardous liquid pipelines accidents. Based on this finding, we reviewed the corrosion control standards in 49 CFR part 195 to determine if the standards need to be made clearer, more effective, or consistent with acceptable safety practices. We believe that improving the standards will have the potential to reduce the number of accidents caused by corrosion. The review began September 8, 1997, when we held a public meeting in Oak Brook, Illinois to discuss how part 195 corrosion control standards and the corrosion control standards for gas pipelines in 49 CFR part 192 might be improved (62 FR 44436; Aug. 21, 1997). We held the public meeting in conjunction with meetings of National Association of Corrosion Engineers International (NACE), a professional technical society dedicated to corrosion control. Participants agreed, universally, that part 192 and part 195 corrosion control standards are largely sufficient, and although some changes may be needed, the standards should remain generally unchanged. Based on this conclusion, we began to consider whether the more comprehensive part 192 gas standards, possibly with some changes, would be appropriate for part 195's hazardous liquid and carbon dioxide pipelines. We met then, from time to time, with representatives of NACE, the pipeline industry, and state pipeline safety agencies for technical input. At these meetings, we also examined whether the part 192 standards need to be more effective or clearer. The meetings raised various concerns about the effectiveness and clarity of some of the part 192 corrosion control standards and the suitability of applying those standards to hazardous liquid and carbon dioxide pipelines. We also took into account that the National Association of Pipeline Safety Representatives, the Gas Piping Technology Committee, and the National Transportation Safety Board had at various times recommended changes to part 192 and part 195 corrosion control standards. So, to gather public comment on our concerns and the changes these organizations recommended, we held another public meeting on April 28, 1999, in San Antonio, Texas, and invited the public to submit written comments. The comment period remained open until June 30, 1999 (64 FR 16885; April 7, 1999). Notice of Proposed Rulemaking Sixty-two persons filed written comments in response to the San Antonio meeting notice. We then summarized these comments in a notice of proposed rulemaking (NPRM) published last year (65 FR 76968; Dec. 8, 2000). The NPRM proposed to add to part 195 a new subpart H called Corrosion Control. Subpart H would prescribe corrosion control standards for all new and existing steel pipelines to which part 195 applies. At this time, we also decided to address the concerns, recommendations, and comments that pertain primarily to the corrosion control standards in part 192 in a separate notice of proposed rulemaking on gas pipelines. Although there was little support in the record for allowing NACE Standard RP0169-96, ``Control of External Corrosion on Underground or Submerged Metallic Piping Systems,'' to serve as an alternative to standards proposed in subpart H, we specifically requested further comment on this issue due to NACE's standing in the field of corrosion. Unfortunately, no one commenting on the NPRM responded to that request, perhaps because of earlier discussions of the issue in Oak Brook and San Antonio. While NACE urged us to reference the entire NACE Standard, not just section 6 as we proposed, NACE did not assert that the NACE Standard could serve as an acceptable alternative to proposed subpart H. The NPRM discussed each of the standards proposed for inclusion in subpart H. Many of these standards are identical to present corrosion control requirements in part 195, and many of the standards are substantially like the present requirements in part 192. Proposed subpart H also includes standards that, while based on present part 192 requirements, include changes which we think are beneficial improvements. Discussion of Comments We received comments from the following entities in response to the NPRM: Alberta Energy Company (AEC), City of Dallas Water Utilities, Enron Transportation Services Company (Enron), Environmental Defense, Equilon Pipeline Company (Equilon), L.A. ``Roy'' Bash, NACE, Phillips Pipe Line Company (Phillips), State of Iowa Utilities Board (Iowa), State of Washington Utilities and Transportation Commission (WUTC), and Tosco Corporation (Tosco). Most commenters supported the rulemaking, and all but the City of Dallas recommended changes to some of the proposed standards. The City of Dallas related its experience with a major pipeline spill caused partly by corrosion. Gasoline containing MTBE, a fuel oxygenate which effects the taste and odor of water, entered a lake resulting in a water supply crisis. The City stated that it is critical for DOT to adopt rules to require [[Page 66995]] all pipelines, especially those transporting gasoline with MTBE near a municipal water resource, to be regularly monitored for corrosion, cracks, and leaks; and that any deficiencies found, be timely repaired. This rulemaking will accomplish what the City of Dallas is seeking with respect to corrosion. In particular, Secs. 195.573, 195.579, and 195.583 will require operators to monitor pipelines regularly for corrosion and correct any deficiencies found in corrosion control. Additionally, new Sec. 195.585 specifies corrective action for any harmful corrosion found. The timeliness of correcting corrosion control deficiencies and harmful corrosion is covered by existing Secs. 195.401(b) and 195.452(h). The requirement for operators to patrol their pipelines regularly for signs of failures is longstanding (Sec. 195.412(a)). However, we recently broadened requirements by publishing standards on integrity management which will require pipelines in or near high-consequence areas, such as drinking water sources, to be internally inspected or pressure tested at regular intervals for corrosion, cracks, and other defects (65 FR 75377; Dec. 1, 2000). These new standards currently apply to operators with 500 or more miles of hazardous liquid pipelines, and we have proposed similar standards for the remaining hazardous liquid operators subject to part 195 (66 FR 15821; Mar. 21, 2001). The following material, which is organized by sections of final subpart H, summarizes comments on the NPRM. In addition, the material explains how we treated the comments and other considerations in developing final subpart H. If a subsection is not mentioned, no significant comments were received on the corresponding proposed rule and we are adopting the proposed rule as final. Section 195.551. This informational section provides the content of subpart H. Subpart H contains minimum requirements for protecting steel pipelines against corrosion. In commenting on proposed Sec. 195.551, Tosco suggested we replace the term ``steel'' with ``metallic'' so subpart H would apply to pipelines made of any metal. Indeed, our corrosion control standards for gas pipelines apply to any metallic pipeline (49 CFR 192.451(a)). However, in contrast to gas pipelines, hazardous liquid and carbon dioxide pipelines are almost exclusively made of steel. For this reason, many of the existing standards in part 195, including corrosion control standards, apply only to steel pipelines. Our review of the corrosion control standards did not disclose a need to expand their coverage to include pipelines made of metals other than steel. In commenting on the NPRM, no one, including Tosco, presented information to explain why the coverage should be expanded. Nevertheless, operators are required to provide us an opportunity to review the safety of any pipeline that is to be constructed with a material other than steel (Sec. 195.8). In the case of a metallic pipeline made from a material other than steel, such as aluminum, our review would include the operator's plan for corrosion control. Section 195.553. This new section was not in the NPRM. It provides definitions of terms used in subpart H. The definitions of ``active corrosion,'' ``electrical survey,'' and ``pipeline environment,'' proposed in Sec. 195.569(c), drew no adverse comment. Additionally, final Sec. 195.553 establishes definitions of ``buried'' and ``you.'' The definition of ``buried'' reflects the common corrosion control practice of treating any portion of pipe in contact with the soil as if that portion were buried. The term ``you'' has the same meaning as ``operator.'' Section 195.555. This section, based on proposed Sec. 195.553, keeps in effect the existing qualification standards in Sec. 195.403(c) for corrosion control supervisors. Under Sec. 195.403(c), each operator must require and verify that its supervisors maintain a thorough knowledge of that portion of the corrosion control procedures established under Sec. 195.402 for which they are responsible, to insure compliance. While Tosco and WUTC supported the proposed rule, Phillips objected to it. Phillips believed that part 195 should include qualifications for supervisors of all operation and maintenance activities, not just corrosion control. In the negotiated rulemaking on qualification of pipeline personnel (64 FR 46866; Aug. 27, 1999), we removed the requirements in Sec. 195.403(c) concerning qualifications of supervisors of operations and maintenance activities, effective October 28, 2002. We did so based on the requirement under subpart G of part 195, that on this date, individuals performing regulated operation and maintenance activities must be fully qualified, thus lessening the need to regulate the qualifications of their supervisors. After revising Sec. 195.403(c), our more specific review of the corrosion control standards called attention to the special role that supervisors play in carrying out corrosion control activities. As we explained in the NPRM, individuals qualified to do such activities as taking electrical readings, usually hand the data collected over to supervisors who make critical decisions about corrosion control adequacy and the need for corrective action. None of the commenters, including Phillips, argued that corrosion control supervisors do not need to have the qualifications required by existing Sec. 195.403(c). So given the special role of corrosion control supervisors and the apparent acceptability of the existing supervisor qualification requirements, we continue to believe those requirements should remain in effect after October 28, 2002. This decision does not affect the expiration on October 28, 2002, of qualification requirements for supervisors of other operation and maintenance activities. Equilon and NACE believed qualifications for supervisors should be no less rigorous than stated in paragraph 1.3 of NACE Standard RP0169- 96. These NACE provisions address the need for corrosion control supervisors to have a minimum level of technical competency.\1\ In our corrosion control review, we considered this NACE provision as well as 49 CFR 192.453, which provides that gas pipeline corrosion control procedures must be carried out by or under the direction of a person qualified in corrosion control methods. Also, in the San Antonio meeting notice, we asked if more specific standards are needed for individuals who direct corrosion control procedures. Everybody who responded opposed changing Sec. 192.453, and most responders also opposed establishing specific technical qualifications like those in NACE Standard RP0169-96. We expect that individuals who qualify as a supervisor under proposed Sec. 195.553, will have appropriate technical training or experience in corrosion control. Given that neither our review, nor comments on the NPRM disclosed anything in the pipeline industry's safety record to demonstrate the need for more specific technical qualifications, we did not adopt the Equilon and NACE comment. --------------------------------------------------------------------------- \1\ Paragraph 1.3 reads: The provisions of this standard shall be applied under the direction of competent persons who, by reason of knowledge of the physical sciences and the principles of engineering and mathematics, required by education and related practical experience, are qualified to engage in the practice of corrosion control on buried or submerged metallic piping systems. Such persons may be registered professional engineers or persons recognized as corrosion specialists or cathodic protection specialists by NACE if their professional activities include suitable experience in external corrosion control of buried or submerged metallic piping systems. --------------------------------------------------------------------------- Sections 195.557, 195.559, and 195.561. These three standards on [[Page 66996]] external coating are based on proposed Sec. 195.555 and 195.557. Collectively, the standards require buried or submerged pipelines to have external coating with particular attributes, and require operators to inspect pipe coating and repair any damage. As stated in proposed Sec. 195.555, the standards are limited to pipelines constructed, relocated, replaced, or otherwise changed after certain effective dates in Sec. 195.401(c); and limited to certain converted pipelines. In final Sec. 195.557, we have clarified that aboveground breakout tank bottoms need not be coated. We determined that such a requirement is impractical and not a customary corrosion control practice. In the NPRM, we proposed in Sec. 195.555 to limit the applicability of proposed Secs. 195.557 (external coating), 195.559 (cathodic protection), and 195.561 (test leads) to pipelines constructed, replaced, relocated, or otherwise changed after the applicable effective date. We based proposed Sec. 195.555, for the most part, on existing Sec. 195.200, titled Scope, which similarly limits the applicability of corresponding existing Secs. 195.238, 195.242, and 195.244. However, we inadvertently omitted from Sec. 195.555 the pipe movement exception included in Sec. 195.200. In this Final Rule, the substance of proposed Sec. 195.555 regarding external coating and cathodic protection is in Sec. 195.557(a), which does include the omitted exception for pipe movement. We addressed the proposed limit on test leads differently, as discussed below under the heading, section 195.567. Tosco believes it would be helpful to include in subpart H the past effective dates cross-referenced in proposed Sec. 195.555. Tosco believes the dates are not widely known. We did not adopt this comment because the dates are already stated in Sec. 195.401(c) for purposes of indicating the applicability of standards in addition to corrosion control standards, and we do not want to create an unnecessary redundancy in part 195. Final Sec. 195.557 specifies which pipelines must have external coating. Rather than cross-referencing Sec. 195.5(b) to indicate which converted pipelines must have coating, we transferred to final Sec. 195.557 the coating aspect of Sec. 195.5(b). We transferred the cathodic protection aspect to final Sec. 195.563(b); and the test lead aspect is covered by Sec. 195.567. Equilon and NACE suggested we establish an additional standard to minimize damage to coating when operators install pipe by boring, driving, directional drilling, or any similar method. Final Sec. 195.559(d) requires external coating to have enough strength to resist damage due to handling and soil stress. We believe this standard is broad enough to cover the potential pipe installation problems raised by these commenters. Phillips advised against requiring the installation of coating on older existing bare or ineffectively coated pipelines. We believe Phillips may be referencing existing hazardous liquid pipelines constructed before the applicable effective dates stated in Sec. 195.401(c). These pipelines are not subsequently replaced, relocated, or otherwise changed. Final Sec. 195.557 does not require these older pipelines to be coated. Tosco suggested that Sec. 195.557 should include the dates for which pipelines must have external coating. The final rule accomplishes this objective by cross-referencing Sec. 195.401(c). Restating the dates listed in Sec. 195.401(c) would be unnecessarily redundant since the dates are in Sec. 195.401(c) for purposes other than corrosion control. Section 195.563. Final Sec. 195.563 combines cathodic protection requirements proposed in Secs. 195.555, 195.559, and 195.563. It also cross-references final Sec. 195.573(b), which requires cathodic protection of unprotected pipe found to have active corrosion. As a result, all pipelines that must have cathodic protection under subpart H are identified in a single section. Final Sec. 195.563(a), which is based on proposed Secs. 195.559(a) and (b), requires cathodic protection on each pipeline that must have an external coating under Sec. 195.557(a). The cross-reference to Sec. 195.557(a) limits the cathodic protection requirement to those pipelines constructed, relocated, replaced, or otherwise changed after certain dates, as proposed under Sec. 195.555. Section 195.563(a) does not contain the second sentence of proposed Sec. 195.559(a) which would require operators to have a test procedure to determine whether adequate cathodic protection was achieved. We now believe this sentence is redundant due to the routine monitoring conducted to determine the adequacy of cathodic protection, required by final Sec. 195.573(a). Also, amended Sec. 195.402(c)(3) requires operators to have procedures to carry out Sec. 195.573(a). Although proposed Sec. 195.559(b) only referred to completion of construction as the beginning of the period during which cathodic protection must be installed, final Sec. 195.563(a) reflects the broader applicability indicated by proposed Sec. 195.555. We proposed in Sec. 195.559(a), which was based on existing Sec. 195.242(a), a requirement that operators install cathodic protection systems on all buried or submerged pipelines ``to mitigate corrosion that might result in structural failure.'' Equilon and NACE suggested this proposed rule would be clearer if we replaced ``structural failure'' with ``structural failure or penetration of pipe or tank wall.'' In light of their comment, we believe the phrase, ``to mitigate corrosion that might result in structural failure,'' creates confusion. It could be interpreted to require protection only against severe external corrosion. Moreover, since it is clear that existing Sec. 195.242(a) requires cathodic protection against all external corrosion, the phrase seems superfluous. Therefore, we did not use it in final Sec. 195.563(a). Equilon and NACE also commented on the Sec. 195.559(b) proposed requirement that a cathodic protection system be installed not later than 1 year after completing construction. They believe cathodic protection should be in effective operation at the end of 1 year, to guard against significant corrosion that could be caused by stray currents or galvanic long-line currents. We believe effective operation is implicit in the existing and proposed standards on installation of cathodic protection. Nevertheless, to avoid confusion on this point, in final Sec. 195.563(a) we replaced ``installed'' with ``in operation.'' This change is consistent with the comparable standard for gas pipelines in Sec. 192.455(a)(2). Under final Sec. 195.571, when the cathodic protection system is placed in operation, it would have to comply with one or more of the applicable criteria and other considerations for cathodic protection contained in paragraphs 6.2 and 6.3 of NACE Standard RP0169-96. Subsequent electrical tests and other steps required by final Sec. 195.573(a) will assure that adequate protection is maintained. WUTC raised the concern that under proposed Sec. 195.559(b) corrosion could go uncontrolled on some facilities for up to 2 years. Based on a Washington State administrative rule, WUTC recommended that Sec. 195.559(b) require that facilities be cathodically protected within 90 days after they are buried or submerged. We did not propose to change the currently required time limit (1 year after completing construction) because our review of the corrosion control standards and the comments from the San Antonio meeting did not indicate any need to reduce the installation time limit. After considering [[Page 66997]] WUTC's comment, we still believe 1 year after construction is acceptable as a generally applicable time limit considering that soil conditions may need time to stabilize in order to support cathodic protection. Final Sec. 195.563(b) requires cathodic protection on certain converted pipelines. This requirement does not differ substantively from the cathodic protection aspect of the corrosion control requirement of Sec. 195.5(b). Therefore, we are modifying Sec. 195.5(b) to cross-reference the new subpart H standards. Under final Sec. 195.563(c), which is based on proposed Sec. 195.563, all buried or submerged pipelines, that have an effective external coating must have cathodic protection. This requirement does not apply to breakout tanks. This requirement is substantially the same as existing Sec. 195.414(a), which requires that all effectively coated pipelines must be cathodically protected, except for breakout tank areas and buried pumping station piping. However, Equilon and NACE each stated it saw no need to except buried piping in breakout tank areas and pumping stations from the requirement to cathodically protect effectively coated pipelines. We agree that the exception seems to lack a sound safety basis. For example, NACE Standard RP0169-96 does not have a similar exception from cathodic protection. Also, we believe it is now common practice in the hazardous liquid pipeline industry to cathodically protect effectively coated buried piping in breakout tank areas and pump stations. So, in view of the Equilon and NACE comments, and our further consideration, we decided to terminate the exception for buried piping in breakout tank areas and pumping stations. Therefore, the final rule keeps the exception in effect only until December 29, 2003. This period will give operators time to install cathodic protection on any effectively coated piping in breakout tank areas and pumping stations where it is not already installed. Also, since no one commented on application of the proposed rule to the bottoms of breakout tanks and there may not be many older breakout tanks that have effectively coated bottoms, the final rule does not change the present exception for breakout tank bottoms. Initially, we did not propose regulations similar to Secs. 195.414(b) and (c), which require cathodic protection in areas of active corrosion found through electrical inspections previously required on bare pipelines, breakout tank areas, and buried pumping station piping. We reasoned that Secs. 195.414(b) and (c) are no longer necessary because the inspection deadlines had expired. However, we now recognize that the cathodic protection provisions of Secs. 195.414(b) and (c) are continuing requirements, and so we included them in subpart H as final Sec. 195.563(d). Section 195.565. This section, concerning the installation of cathodic protection on breakout tanks, is the same as proposed Sec. 195.559(c). There were no comments on proposed Sec. 195.559(c). Section 195.567. In this section concerning test leads, paragraphs (a) and (b) are based on proposed Sec. 195.561 and existing Sec. 195.244. The existing test lead standards in Sec. 195.244 apply to onshore pipelines constructed, replaced, relocated, or otherwise changed after certain past dates; and to onshore converted pipelines if required by Sec. 195.5(b). The NPRM did not propose to vary this application. However, upon further consideration of the importance of test leads in determining the adequacy of cathodic protection, we are applying final Sec. 195.567 to all onshore pipelines that must have cathodic protection under subpart H. This increased coverage will affect pipelines or segments of pipelines that must have cathodic protection under existing Secs. 195.414 and 195.416(d) (i.e., effectively coated pipelines and places on bare pipelines, breakout tank areas, and pumping station piping where active corrosion is found through electrical inspection). The increased coverage will also affect converted pipelines that were not substantially in compliance with existing Sec. 195.244 when placed in service, as Sec. 195.5(b) now permits. To ease the burden of compliance on existing cathodically protected pipelines or pipeline segments on which test leads are not now required by existing Sec. 195.244 or Sec. 195.5(b), final Sec. 195.567(a) allows operators 3 years to identify these pipelines or pipeline segments and install test leads as necessary to meet Sec. 195.567(b). On existing unprotected pipelines, any newly identified segment that must have cathodic protection as a result of an electrical survey under final Sec. 195.573(b), must have test leads in time to carry out the annual monitoring test under final Sec. 195.573(a). Final Sec. 195.567 is consistent with acceptable practices. The practices recommended for test leads in NACE Standard RP0169-96 and in ASME B31.4 are not limited to new, relocated or replaced pipelines. Also, our gas pipeline regulations in 49 CFR 192.469 and 192.471 for test stations and test leads, apply to all gas pipelines that must be cathodically protected under 49 CFR part 192. Moreover, existing Sec. 195.416(a) requires annual testing of each cathodically protected pipeline to determine the adequacy of cathodic protection; and operators normally comply with this requirement by obtaining electrical measurements through test leads. So we believe Sec. 195.567 will have only a minimal impact on hazardous liquid pipeline companies. Based on existing Sec. 195.244(b)(1), we proposed in Sec. 195.561(b)(1) that operators install test leads with enough looping or slack to prevent the leads from being unduly stressed or broken during backfilling. Equilon and NACE suggested that to assure test lead wires remain effective, we should add the phrase ``to remain mechanically secure and electrically conductive.'' We believe the objective of this phrase is within the purpose of the existing rule, and therefore, added the phrase to final Sec. 195.567(b)(2) for emphasis. The long term integrity of test leads is also covered by final Sec. 195.567(c). Based on proposed Sec. 195.573, this standard requires maintenance of test leads. There were no comments on the proposed rule, however we edited the final rule for clarity. Equilon and NACE also commented on testing cathodic protection of offshore pipelines. They contended that test lead readings at platforms or at shore locations may be of little benefit in determining the adequacy of cathodic protection of offshore pipelines. As an alternative to such readings, they suggested we require operators to analyze or inspect each cathodic protection system before the end of its design life. In our experience, test leads for offshore pipelines normally are installed only on platforms or on shore because of the difficulty of accessing leads at underwater locations. For this reason, Sec. 195.567 does not apply to buried or submerged portions of offshore pipelines. Since pipeline corrosion in an offshore environment generally occurs at a uniform rate, we believe readings taken by operators at offshore platforms or on shore are used satisfactorily to determine the adequacy of protection over the entire pipeline. Moreover, this test method is acceptable for offshore gas pipelines under paragraph A862.15 of the ASME B31.8 Code. Because there is no information to support the need to require the use of an alternative testing method, we chose not to take action on the commenters' suggestion. WUTC commented that because the proposed standard does not prescribe the number or precise location of test leads, government inspectors may disagree with operators over whether [[Page 66998]] test readings are sufficient to determine the adequacy of cathodic protection. To ameliorate this situation, WUTC suggested that we require operators to conduct close-interval electrical surveys every 5 years. Although final Sec. 195.567 does not specify the number or precise location of test leads, it does provide a performance standard for the location of test leads. Under Sec. 195.567(b)(1) test leads must be installed at sufficiently frequent intervals to obtain electrical measurements indicating the adequacy of cathodic protection. Section 4.5 of NACE Standard RP0169-96, which lists many customary test lead locations, may be used as a guide to comply with Sec. 195.567(b)(1). Additionally, the final rule on monitoring external corrosion control, Sec. 195.573, will require operators to use close- interval surveys in some situations and install additional test leads where warranted. Section 195.569. This section, which is based on proposed Sec. 195.565, provides that whenever an operator learns that any portion of a buried pipeline is exposed, the exposed portion must be examined for external corrosion if the pipe is bare or has deteriorated coating. Further, if external corrosion requiring remedial action is found, the operator must investigate pipe in the vicinity of the exposed portion (by visual examination, indirect method, or both) to determine if there is any additional external corrosion requiring remedial action. Phillips requested more flexibility in the proposed requirement to look for additional corrosion. Phillips commented that the extent of further investigation should depend on the type of corrosion found and whether the corrosion 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 finding similar corrosion in the vicinity of the exposed pipe to justify limits on the requirement for additional investigation. Pipe and soil conditions are generally too variable to make such predictions with accuracy. Therefore, we did not adopt Phillips' comment. WUTC believed subpart H should include additional requirements for operators to do more to determine the condition of coating than just visually examine it whenever pipelines are exposed. WUTC stated that the standards should require operators to conduct surveys to identify areas with coating defects and take remedial measures such as re- coating the pipeline. Although the final rules do not specifically require pipe coating surveys, operators must conduct electrical tests periodically to determine the adequacy of corrosion control on their buried pipelines. Low cathodic protection potential readings obtained during these tests often are a sign of coating defects. So, in areas with low potential readings, many operators supplement cathodic protection tests with coating surveys to help them identify places where the pipeline must be excavated to look for corrosion cells or to determine where additional cathodic protection must be applied. The need to mandate the use of coating surveys in addition to electrical tests for corrosion, was not evident from our review of the regulations. Section 195.571. This standard, proposed as Sec. 195.567, incorporates by reference the criteria and other considerations in section 6 of NACE Standard RP0169-96, as standards for the adequacy of cathodic protection. Environmental Defense and Iowa argued that because cathodic protection criteria are fundamental to safety, the criteria should be stated in part 195 rather than incorporated by reference. Iowa believed that acquiring and maintaining a separate document is arbitrary and unnecessarily burdensome. In considering these comments, we reviewed OMB Circular A119 and the National Technology Transfer and Advancement Act of 1995. Both documents direct Federal agencies to use consensus standards where practical to meet their policy objectives rather than develop government-unique standards. We also reviewed the rules of the Federal Register on incorporation by reference. In light of these Federal policies, we think it is appropriate for us to incorporate the NACE criteria and other considerations by reference, as proposed. Enron, Environmental Defense, and L. A. (Roy) Bash urged us to adopt the criteria in Appendix D of part 192 instead of the NACE criteria. Enron commented that many operators are successfully using Appendix D for hazardous liquid pipelines; and Environmental Defense viewed Appendix D as more specific and therefore more enforceable. Roy Bash submitted technical documentation in support of two Appendix D criteria, 300 mV shift and E-log-I. In the NPRM we discussed our reluctance to propose Appendix D as the new standard for hazardous liquid pipelines because the Appendix D 300 mV shift and E-log-I criteria are not incorporated in the NACE Standard. Furthermore, we explained that under paragraph 6.2.1 of the NACE Standard, operators may use any criteria which they can demonstrate achieves corrosion control comparable to section 6 criteria. Also, operators may continue to use criteria which they have successfully applied to existing pipelines, on these pipelines. While this provision may satisfy Enron, and should satisfy Roy Bash's concern about the continued use of the 300 mV shift and E-log-I criteria, the lack of specificity in paragraph 6.2.1 may be indicative of Environmental Defense's concern. Yet, we do not believe the performance wording of paragraph 6.2.1 alone is sufficient reason not to reference section 6 of the NACE Standard. On the contrary, we generally favor performance standards over specification standards because they encourage operators to develop and apply better alternatives. If however, an operator chooses to use alternative criteria, we will carefully examine the operator's rationale for determination that the criteria met the ``comparable to'' or ``successfully applied'' tests of paragraph 6.2.1 of the NACE Standard. WUTC was concerned that the criteria in section 6 of the NACE Standard would not be mandatory because paragraph 6.1.1 refers to paragraph 1.2, which states that the Standard is a guide; and also refers to paragraph 1.4, which allows deviations from the Standard. Proposed Sec. 195.567 refers solely to the criteria and other consideration provisions of section 6, which are contained in paragraphs 6.2 and 6.3 of the NACE Standard. We did not intend to allow operators to treat section 6 as a guide or to deviate from the criteria and other considerations in section 6. Therefore, the final rule refers to paragraphs 6.2 and 6.3, instead of section 6. WUTC was also concerned about special conditions, such as elevated temperatures, disbonded coatings, thermal insulating coatings, shielding, bacterial attack, and unusual contaminants in the electrolyte, which may cause cathodic protection to be ineffective. WUTC believed the rules on coating and cathodic protection should address these special conditions. The theory behind final Sec. 195.571 is that if all external surfaces of a pipeline are cathodically protected according to the criteria and other considerations in paragraphs 6.2 and 6.3 of the NACE Standard, external corrosion will be controlled successfully. In practice, if an operator learns though in- line inspection or other means that because of a special condition external corrosion is not being controlled successfully, the operator must take corrective action. The operator could either remedy the condition or adjust the cathodic protection system to assure the adequacy of cathodic protection in the [[Page 66999]] area of the special condition. We believe this requirement is implicit in final Sec. 195.571. Section 195.573(e) also would require corrective action if the condition is detected by monitoring under Sec. 195.573. In addition, WUTC was concerned that the proposed rules did not specify how long the cathodic protection current may be shut off when measuring polarization decay under the minimum 100 mV criterion. WUTC suggested that the limit be no more than 48 hours, unless a recording chart shows continuing significant decay beyond that time. To satisfy the100 mV criterion by the decay method, operators must determine that a negative polarization voltage shift of at least 100 mV occurs after the immediate voltage shift caused by shutting off the cathodic protection current. Whether this minimum negative voltage shift occurs in minutes or hours after the current is cut off, it is irrelevant to satisfying the criterion. We recognize that the longer the current remains off, the greater the opportunity for the pipeline to corrode. However, in our experience decay tests have not posed a serious problem in this regard t
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