# Controlling Corrosion on Hazardous Liquid and Carbon Dioxide Pipelines

- **operation:** document
- **citation:** 65 FR 76968
- **title:** Controlling Corrosion on Hazardous Liquid and Carbon Dioxide Pipelines
- **source type:** rulemaking
- **agency:** Research and Special Programs Administration
- **status:** proposed
- **official:** true
- **published on:** 2000-12-08
- **effective on:** Not available
- **summary:** We are proposing to change some of the corrosion control standards for hazardous liquid and carbon dioxide pipelines. The proposed 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 proposed 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/2000/12/08/00-31224/controlling-corrosion-on-hazardous-liquid-and-carbon-dioxide-pipelines
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Federal Register, Volume 65 Issue 237 (Friday, December 8, 2000) [Federal Register Volume 65, Number 237 (Friday, December 8, 2000)] [Proposed Rules] [Pages 76968-76982] From the Federal Register Online via the Government Publishing Office [ www.gpo.gov ] [FR Doc No: 00-31224] ======================================================================= ----------------------------------------------------------------------- DEPARTMENT OF TRANSPORTATION Research and Special Programs Administration 49 CFR Part 195 [Docket No. RSPA-97-2762; Notice 3] RIN 2137-AD24 Controlling Corrosion on Hazardous Liquid and Carbon Dioxide Pipelines AGENCY: Research and Special Programs Administration (RSPA), DOT. ACTION: Notice of proposed rulemaking. ----------------------------------------------------------------------- SUMMARY: We are proposing to change some of the corrosion control standards for hazardous liquid and carbon dioxide pipelines. The proposed 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 proposed changes are intended to improve the clarity and effectiveness of the present standards and reduce the potential for pipeline accidents due to corrosion. DATES: Persons interested in submitting written comments on the proposed rules must do so by February 6, 2001. Late filed comments will be considered so far as practicable. ADDRESSES: You may submit written comments by mailing or delivering an original and two copies to the Dockets Facility, U.S. Department of Transportation, Room PL-401, 400 Seventh Street, SW., Washington, DC 20590-0001. The Dockets Facility is open from 10:00 a.m. to 5:00 p.m., Monday through Friday, except on Federal holidays when the facility is closed. Or you may submit written comments to the docket electronically at the following web address: http://dms.dot.gov . See the SUPPLEMENTARY INFORMATION section for additional filing information. 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: Filing Information, Electronic Access, and General Program Information All written comments should identify the docket and notice numbers stated in the heading of this notice. Anyone who wants confirmation of mailed comments must include a self-addressed stamped postcard. To file written comments electronically, after logging onto http://dms.dot.gov , click on ``Electronic Submission.'' You can read comments and other material in the docket at this Web address: http://dms.dot.gov . General information about our pipeline safety program is available at this address: http://ops.dot.gov . Background We have reviewed the corrosion control standards in 49 CFR part 195 for hazardous liquid and carbon dioxide pipelines to see if any standards need to be made clearer, more effective, or consistent with acceptable safety practices. Although the likelihood of corrosion- caused accidents harming people or the environment is relatively low, we undertook the review because corrosion is the second leading cause of reported accidents on hazardous liquid pipelines, and improving the standards has the potential to reduce the number of future accidents.\1\ --------------------------------------------------------------------------- \1\ For the period 1986 through 1999, corrosion caused 25 percent of all incidents reported under Part 195; 3 percent of all deaths; 2 percent of all injuries; and 19 percent of all property damage. --------------------------------------------------------------------------- The review began September 8, 1997, when we held a public meeting on how the 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). To attract participation by corrosion experts, we held the public meeting in Oakbrook, Illinois, in conjunction with meetings of NACE International, a professional technical society dedicated to corrosion control. [[Page 76969]] The Oakbrook meeting focused on whether we should incorporate by reference NACE Standard RP0169-96, ``Control of External Corrosion on Underground or Submerged Metallic Piping Systems,'' as a substitute for all or some of the part 192 and part 195 standards. Two other significant topics were whether part 192 and part 195 corrosion control standards need to be updated to ensure safety, and whether gas, hazardous liquid, and carbon dioxide pipelines should be subject to the same corrosion control standards. For technical and other reasons, including the document's non- mandatory style, most meeting participants and subsequent commenters opposed incorporating the entire NACE Standard RP0169-96 by reference. But 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 be generally the same. Toward this end, we began to consider whether the more comprehensive part 192 standards, possibly with some changes, would be appropriate for hazardous liquid and carbon dioxide pipelines. For technical input, we met from time to time with representatives of NACE, the pipeline industry, and state pipeline safety agencies. At these meetings, we also examined whether the part 192 standards need to be more effective or clearer. As guidance for this assessment, the meeting participants developed the following principles: Evaluate existing data and use the evaluation to assess the need to change standards. Continue to improve public safety and environmental protection. Assess the need for corrosion control standards throughout the national pipeline system based on the risk associated with different parts of the system. Upgrade regulations to allow for future changes in pipeline industry technology and operating practices as appropriate. Strive for uniform interpretation/enforcement. To the extent practicable, involve all interested parties in assessing the need to change standards. Use the new cost/benefit policy framework being developed for RSPA's pipeline safety advisory committees in determining the costs and benefits of potential changes to standards. Achieve balance between performance and prescriptive language. Develop performance measures to assess the effectiveness of corrosion control programs. Focus on managing corrosion to maintain pipeline integrity. Provide adequate regulatory flexibility to allow operators to implement alternative measures that meet the performance requirements of the corrosion regulations. The meetings left us with various concerns about the total effectiveness and clarity of the part 192 corrosion control standards and the suitability of applying those standards to hazardous liquid and carbon dioxide pipelines. We also knew that the National Association of Pipeline Safety Representatives (NAPSR), the Gas Piping Technology Committee (GPTC), and the National Transportation Safety Board (NTSB) had at various times recommended changes to part 192 and part 195 corrosion control standards. So, to get public comment on our concerns and the recommended changes, we held another public meeting on April 28, 1999, in San Antonio, Texas (64 FR 16885; April 7, 1999). We also invited comments on the idea of allowing operators to follow their own corrosion management plans or NACE Standard RP0169-96 as an alternative to all or part of the part 192 or part 195 corrosion control standards. San Antonio Meeting At least 180 persons attended the San Antonio public meeting. However, only a few persons made oral statements, which are summarized as follows: The Interstate Natural Gas Association of America (INGAA) said that based on the record of low numbers of deaths and injuries, not much change in the part 192 standards is needed, even if corrosion is the second leading cause of reported pipeline incidents. INGAA attributed the good safety record to proper management of risk, saying it would be nonproductive if changes to generally applicable safety standards caused operators to shift their limited resources away from higher risk areas. INGAA emphasized the use of cost/benefit assessment in determining the need for new or revised standards. At least two other meeting participants (Enron and Columbia Gulf) expressed support for INGAA's views. The American Gas Association (AGA) and American Public Gas Association (APGA) jointly made a statement similar to INGAA's and pointed out that DOT safety statistics do not justify changes in the present standards. AGA/APGA further noted that corrosion is not the second leading cause of incidents on gas distribution lines, but the last cause, resulting in about 4 percent of all reported incidents. The views of AGA/APGA were supported by at least one other meeting participant (Columbia Gulf) and by a majority of the persons who submitted written comments to the docket after the meeting. These subsequent written comments are condensed below under the ``Comments after San Antonio'' subheading. Another participant, Global Cathodic Protection, submitted a statement, backed by 72 corrosion control practitioners, that cathodic protection criteria in appendix D of part 192 are preferred to the criteria in NACE Standard RP0169-96. Equilon Enterprises, an operator of petroleum pipelines, did not support the alternative of corrosion management plans, because of the burden of review by government and the possibility that government reviewers and operator personnel may not be equally qualified to evaluate the plans. In addition, Equilon said that removing unnecessary differences between part 192 and part 195 standards would minimize confusion and disagreements between operators and government inspectors. On other points raised in the meeting notice, Equilon preferred that part 195 not refer to NACE Standard RP0169-96. But, Equilon did support the need for qualification requirements for bosses who lead corrosion control programs, and it thought the part 192 standards should disallow the use of bare unprotected pipe. An engineering consultant said the ``instant-off'' approach to measuring cathodic protection was excessive. Similarly, the Equilon representative said that across-the-board use of the negative 850 mV criterion with instant-off readings is not productive, and that the 100 mV criterion is more cost-effective in many cases. A university professor said that corrosion control technicians do not do instant-off tests the same way. But another engineering consultant noted that NACE has a companion standard that covers instant-off tests: TM0497-97, Measurement Techniques Related to Criteria for Cathodic Protection on Underground or Submerged Metallic Piping Systems. Comments Submitted After the San Antonio Meeting Following the San Antonio public meeting, the docket remained open to receive written comments on the matters addressed in the meeting notice. Sixty-two persons filed written comments. These commenters included pipeline safety agencies in Arizona and Iowa, two corrosion control firms (Corrosion Control International and Global Cathodic Protection), two [[Page 76970]] operators of petroleum pipelines (Mobil Corporation and Tosco Refining Company), seven pipeline trade associations (American Gas Association (AGA), American Public Gas Association (APGA), Interstate Natural Gas Association of America, New England Gas Association, New York Gas Group, Ohio Gas Association, and American Petroleum Institute), six operators of interstate gas pipelines (CMS Energy, Columbia Energy Group, Duke Energy, Enron Gas Pipeline Group, KN Energy, and Phillips Pipe Line Company), and 43 local gas distribution companies. General Comments. Most of the written comments specifically address RSPA concerns and other topics in the San Antonio meeting notice. Still, there were some general comments: Two gas distribution operators said that requiring operators to cathodically protect cast iron or ductile iron pipe would have a big impact on the distribution industry. These operators also suggested that small fittings made of copper or brass and steel fittings with a corrosion resistant coating should be exempt from cathodic protection requirements. Other rule changes they suggested were intended to yield savings by specifying that electronic or remote data collection can be used to meet the monitoring requirements and by extending the interval for monitoring rectifiers from every 2 months to twice a year, particularly for newly manufactured devices. AGA/APGA welcomed minor rule changes that address clarity, consistency, technology, but said that sweeping changes are not justified by the safety data. They advised us to use cost/benefit assessment and non-regulatory approaches to perceived problems. Of the 62 commenters, 42 expressed support for the joint comments of AGA/APGA. Others, such as Mobil Corporation, Enron, and the New England Gas Association, similarly expressed doubt that substantial changes to the standards were warranted in view of the incident record. One commenter, Kansas Gas Service, backed up its claim that the present standards are adequate by referring to its own record: no reported incidents for the period 1989-98. Tosco Refining stated that making the corrosion control maintenance requirements in Parts 192 and 195 alike would mitigate compliance difficulties for companies that operate both gas and petroleum pipelines. Comments on RSPA Concerns: This section of the preamble includes summaries of comments that specifically address RSPA's concerns about whether certain provisions of Part 192 corrosion control standards need to be improved. The AGA/APGA comments are identified because many commenters supported the AGA/APGA views. Summaries of comments on changes recommended by NAPSR, GPTC, and NTSB, on alternatives, and on topics included in the ``Public Participation'' section of the meeting notice are discussed afterward. Section 192.453 Personnel Qualification RSPA Concern: In view of the proposed rules on qualification of pipeline personnel (63 FR 57269; Oct. 27, 1998) \2\, are more specific qualification standards needed for individuals who direct or carry out corrosion control procedures? --------------------------------------------------------------------------- \2\ After the San Antonio meeting, RSPA adopted final rules on personnel qualification that closely paralleled the proposed rule (64 FR 46853; Aug. 27, 1999). --------------------------------------------------------------------------- Comments: All 23 comments on this concern opposed changing Sec. 192.453. They said either the existing rule is adequate or the proposed rules on personnel qualification are sufficient. Most of these commenters also opposed establishing specific technical qualifications for company managers. They said these personnel need more business than technical knowledge to assure that corrosion and other maintenance problems are handled economically. AGA/APGA suggested that any remaining qualification issues be addressed in a non-regulatory way through ongoing discussions with industry training representatives at DOT's Transportation Safety Institute. Section 192.455 External Corrosion: New Pipelines RSPA Concern: Should a cathodic protection system be installed on offshore pipelines in less than one year after the pipeline is constructed, for example, 60 days, because of the strong corrosiveness of salt water? Comments: The two comments on this concern favored a 60-day installation period. RSPA Concern: Is it in the interest of safety to exempt pipelines in particular environments and temporary pipelines from the coating and cathodic protection requirements? Comments: Three commenters opposed the present exemptions, either because corrosion leaks can happen rapidly or because the installations are so varied they should be handled by waivers rather than general exemption. At the same time, three commenters supported the exemptions, contending that corrosion is usually a long term problem, many environments are not conducive to corrosion, and required monitoring would detect incipient problems. AGA/APGA said that safety data do not suggest the present exemptions have been detrimental to safety. Section 192.457 External Corrosion: Existing Pipelines RSPA Concern: Should existing compressor, regulator, and measuring station piping continue to be excluded from the requirement to cathodically protect effectively coated transmission line pipe? Comments: Five commenters said the piping should not be excluded, arguing that it does not differ from pipe that must be protected and that failures at these locations may have serious consequences. Three other commenters said they cathodically protect all their compressor, regulator, and measuring station piping. RSPA Concern: Is the present requirement to cathodically protect certain older existing pipelines only in areas of ``active corrosion'' adequate for public safety? If not, what would be a cost-effective alternative standard? Comments: Only one commenter opposed the present rule. This commenter contended that the entire pipeline needs protection because spot protection moves the corrosion problem to other places on the line. However, 13 commenters, including AGA/APGA, supported the present rule, saying that it is a cost-effective approach to protecting older lines, particularly since not all corrosion is detrimental to safety. Another commenter thought that adding cathodic protection to old bare lines in mildly corrosive or non-corrosive soils could accelerate the rate of any localized corrosion that might exist. RSPA Concern: Is the meaning of ``active corrosion'' clear and technically sound? If not, how should it be changed? Comments: None of the 12 comments advocated changing the present definition of ``active corrosion.'' Five commenters, including AGA/ APGA, thought that possible changes would be more prescriptive, less flexible, or not appropriate for all areas. Section 192.461 External Corrosion: Coating RSPA Concern: Should the implicit requirement to coat field joints and repairs be expressly stated? Comments: Four commenters said this requirement should be expressly stated. But four other commenters worried that singling out any item would raise questions about items not listed. [[Page 76971]] Similarly, another commenter thought the implicit requirement was adequate for field joints. RSPA Concern: Does coating need to be compatible with the anticipated service conditions, including the effects of temperature? Comments: Four commenters agreed that such service compatibility is necessary. And one of these commenters suggested that a performance standard would improve the effectiveness of the existing rule in this regard. However, another commenter said the existing rule is adequate because service compatibility is implied. RSPA Concern: For offshore pipelines, during installation, are special measures necessary to protect against damage to coating, including field joint coating; and, to avoid mechanical damage, are special coatings needed on J-tubes, I-tubes and pipelines installed by the bottom tow method? Comments: There were no comments on this concern. Section 192.463 External Corrosion: Cathodic Protection Criteria RSPA Concern: Are the cathodic protection system criteria in appendix D of part 192, 300 mV shift and E-log-I, obsolete, since they are not in section 6 of NACE Standard RP0169-96? If so, should operators be allowed to continue to use them on existing pipe, but not new pipe? Comments: Three commenters favored dropping these two criteria or at least E-log-I from appendix D. Six other commenters said they would support dropping the criteria only if the criteria were known to be ineffective or no longer in use. One commenter acknowledged using E- log-I and two others said the two criteria are adequate and should be allowed. AGA/APGA and one other commenter said the NACE standard recognizes the use of other successful criteria, such as those in appendix D, and that safety data do not show that the 300 mV shift and E-log-I criteria result in higher leak rates or incidents. Section 192.465 External Corrosion: Monitoring RSPA Concern: Does the sampling basis prescribed for inspecting short sections of mains or transmission lines not in excess of 100 feet and separately protected service lines provide effective corrosion control, particularly as it applies to service lines that supply gas to public buildings? Comments: Two commenters thought the present rule is ineffective, asserting that a single inspection is not enough to assess safety over a 10-year period, no matter if public buildings are involved. However, four commenters argued that because corrosion is slow, there has been no problem in sampling pipe to detect corrosion before it becomes critical. And two commenters said sampling is a cost-effective way to monitor scattered sites. AGA/APGA and two other commenters said that safety data do not show that sampled pipe has more corrosion-caused leaks than other pipe. Several commenters foresaw difficulties in defining a ``public building.'' Only one commenter thought that more frequent monitoring is needed for lines leading to public buildings because of the increased potential for serious consequences. Section 192.467 External Corrosion: Electrical Isolation RSPA Concern: What remedial action is needed when an electrical short in a casing results in inadequate cathodic protection of the pipeline outside the casing? Comments: Five commenters said these shorts should be cleared because other options are ineffective and imposing more current to offset the short could have adverse effects. But two other commenters said that clearing shorts can be costly if the line must be taken out of service or replaced, and that there is no consensus on adequate remediation. Another observation by one commenter was that the electrical isolation requirements are not needed since cathodic protection has to meet the criteria for adequacy. RSPA Concern: Should newly constructed offshore pipelines be electrically isolated from bare steel platforms unless both are protected as a single unit? Comments: The lone commenter who addressed this concern said that isolation is needed, yet concluded that a rule change was not needed because annual surveys will identify any problem. RSPA Concern: Is electrical isolation needed where contact with aboveground structures would adversely affect cathodic protection? Comments: One commenter said we should require isolation in all such cases. Three commenters argued that while isolation is needed a rule change is not, because annual surveys will identify any problem. Three other commenters argued that isolation is not needed if the alternative of sufficient local protection is applied. Section 192.471 External Corrosion: Test Leads RSPA Concern: Are accessible test leads needed on offshore risers that are electrically isolated and not accessible for testing? Comments: The two commenters who addressed this concern said the present rule is adequate because operators must demonstrate adequate cathodic protection, which necessitates test leads. RSPA Concern: For aluminum pipelines, should all test leads be insulated aluminum conductors and installed to avoid harm to the pipe? Comments: There were two comments on this concern. One said test leads and connection material must be compatible with aluminum. The other said test leads must be insulated aluminum conductors and installed to avoid harm to the pipe. Section 192.473 External Corrosion: Interference Currents RSPA Concern: Where light rail systems exist, should operators specifically be required to identify and test for stray currents and keep records of the test results? Comments: Four commenters said such a specific requirement was needed for light rail. But three commenters disagreed, arguing the present rule is adequate because it requires operators to test for all sources of stray current, including large junk yard magnets and electric cranes. Section 192.475 Internal Corrosion RSPA Concern: Are special requirements needed to deal with the problem of internal corrosion in storage field piping, as evidenced by piping leaks in West Virginia and several Midwestern states? Comments: Three commenters felt the present rule is adequate for all situations and specific requirements for storage fields are not needed. In contrast, one commenter thought the rule should specifically recognize the problems posed by such piping and require more coupons or traps where liquid might collect, pipe design that avoids liquid collection, use of lined pipe, periodic pigging, or dehydration. Another commenter thought operators should have to prepare a procedure and follow it to minimize internal corrosion. Section 192.479 Atmospheric Corrosion: General RSPA Concern: Should new and existing pipelines be subject to the same protection requirements? Comments: One commenter saw no need to change the distinction between new and existing pipelines.\3\ Six others [[Page 76972]] supported treating all aboveground pipelines alike regardless of age, but two of these commenters said the rule should apply only to ``active corrosion,'' not to all corrosion. --------------------------------------------------------------------------- \3\ For new aboveground pipelines, protection is required everywhere the pipeline is exposed to the atmosphere, unless the operator can demonstrate that a corrosive atmosphere does not exist. For old pipelines, protection is required only where harmful corrosion is found. --------------------------------------------------------------------------- RSPA Concern: Is protection needed where corrosion is a light surface oxide or where corrosion will not likely affect the safe operation of the pipeline before the next scheduled inspection? Comments: Six commenters thought the rule should be changed to exclude surface oxide because it does not affect pipe integrity. However, one commenter thought surface oxide indicates a coating problem that operators should identify and track through continuing surveillance. One other commenter said that even if corrosion is more than superficial, if there is no question of safety before the next inspection, then there is no present need for remedial action. Another commenter recommended limiting the rule to ``active corrosion'' to exclude both superficial corrosion and corrosion that would not likely advance to an unacceptable stage before the next inspection. RSPA Concern: Is special protection needed in the splash zone of offshore pipelines and at soil to air interfaces of onshore pipelines? Comments: Three of the four comments on this concern thought the existing corrosion rules for buried and aboveground protection are adequate. The fourth commenter said any need for special protection would be recognized during required inspections. Section 192.481 Atmospheric Corrosion: Monitoring RSPA Concern: Should the inspection interval for onshore pipelines be extended beyond 3 years in view of the generally low incidence of serious problems on protected pipelines? Comments: Two commenters said the present 3-year monitoring cycle is not too burdensome. In contrast, seven commenters recommended extending the inspection period beyond 3 years, saying that atmospheric corrosion is a long-term process. Six of these commenters recommended inspection every 5 years, an interval coincident with the interval of gas leakage surveys. One other commenter suggested the rule let operators determine what inspection intervals are appropriate for the pipelines involved. RSPA Concern: For onshore pipelines, are more frequent inspections needed at soil-to-air interfaces, under thermal insulation, at disbonded coatings, and at pipe supports? Comments: The consensus of the four comments on this concern was that no more frequent inspections than annual are needed at these locations. Two commenters said the corrosion problem at these locations is too site-specific for a general inspection rule requiring removal of coating or jackets. RSPA Concern: For offshore pipelines, are more frequent inspections needed under poorly bonded coatings and at splash zones, support clamps, and deck penetrations? Comments: There were no comments on this concern. Section 192.491 Records RSPA Concern: Should operators keep records of findings of non- corrosive conditions if Section 192.455 Is Changed To Remove the Benefit of Such Findings? Comments: Two commenters agreed that if records of non-corrosive conditions no longer have a purpose, the recordkeeping requirement should be removed. But another commenter thought records of exposed pipe inspections under Sec. 192.459 should be kept even if no corrosion is found. This commenter thought such records would be useful in surveillance under Sec. 192.613 and in evaluating the significance of damaged pipe or coating. RSPA Concern: Is the period for keeping corrosion control monitoring records, ``as long as the pipeline remains in service,'' necessary for safety or accident investigation? If not, what is an appropriate period? Comments: One commenter believed the present retention period is needed to provide a very helpful general history of pipelines. But another commenter said that old records are never used once adverse conditions are corrected. Two commenters suggested the retention period could be reduced to 5 years or two inspection cycles, whichever is longer. A similar comment was 5 years or the next inspection cycle, whichever is longer. Recommendations To Change Standards National Association of Pipeline Safety Representatives Recommendation: With regard to Secs. 192.457 and 192.465, NAPSR recommended changes to clarify the meaning of an ``electrical survey'' and where alternatives to electrical surveys may be used. Comments: Three commenters reported that the State-Industry Regulatory Review Committee (SIRRC) had reached a consensus on ``electrical survey'' and alternatives. SIRRC was formed by NAPSR and industry representatives to work out differences of opinion over NAPSR's 1992 recommendations to revise part 192.\4\ In a report transmitted to RSPA by a letter dated May 3, 1999, SIRRC concludes that electrical surveys are seldom used on distribution systems, so there is no advantage to requiring electrical surveys as a preferred corrosion inspection method on distribution systems. SIRRC further concludes that if electrical surveys are not used, all available information should be used to determine if active corrosion exists. Set out below are SIRRC's suggested revisions of Sec. 192.457(b)(3) and Sec. 192.465(e). SIRRC also said that in the suggested revision, ``pipeline environment'' refers to whether soil resistivity is high or low, wet or dry, contains contaminants that may promote corrosion, or has any other known condition that might influence the probability of active corrosion. \4\ NAPSR's recommendations were published in Notice 2 of Docket No. PS-124 (58 FR 59431; Nov. 9, 1993). --------------------------------------------------------------------------- [192.457(b)(3)] Bare or coated distribution lines. The operator shall determine the areas of active corrosion by electrical survey or by analysis and review of the pipeline condition. Analysis and review shall include, but is not limited to, leak repair history, exposed pipe condition reports, and the pipeline environment. For the purpose of this section, an electrical survey is a series of closely spaced pipe-to-soil readings over a pipeline which are subsequently analyzed to identify any locations where a corrosive current is leaving the pipe. [192.465(e)] (i) For transmission pipelines, after the initial evaluation required by paragraphs (b) and (c) of Sec. 192.455 and paragraph (b) of Sec. 192.457, each operator shall, not less than every 3 years at intervals not exceeding 39 months, reevaluate its unprotected pipelines and cathodically protect them in accordance with this subpart in areas in which active corrosion is found. The operator shall determine the areas of active corrosion by electrical survey, or where an electrical survey is impractical, by analysis and review of the pipeline condition. Analysis and review shall include, but is not limited to, leak repair history, exposed pipe condition reports, and the pipeline environment. (ii) For distribution pipelines, after the initial evaluation required by paragraphs (b) and (c) of Sec. 192.455 and paragraph (b) of Sec. 192.457, each operator shall, not less than every 3 years at intervals not exceeding 39 months, reevaluate its unprotected pipelines and cathodically protect them in accordance with this subpart in areas in which active corrosion is found. The operator shall determine the areas of active corrosion by electrical survey or by analysis and review of [[Page 76973]] the pipeline condition. Analysis and review shall include, but is not limited to, leak repair history, exposed pipe condition reports, and the pipeline environment. (iii) For the purpose of this section, an electrical survey is a series of closely spaced pipe-to-soil readings over a pipeline which are subsequently analyzed to identify any locations where a corrosive current is leaving the pipe. Recommendation: With regard to Sec. 192.459, NAPSR recommended we require operators to record the condition of protective coatings whenever they inspect exposed portions of buried pipeline, arguing the records would provide a useful history of the condition of the pipelines as well as evidence that exposed pipe had been inspected as required. Comments: Three commenters reported that SIRRC reached a consensus on recording the condition of coating when inspecting exposed pipe. SIRRC said that coating condition is important in evaluating the overall condition of a pipeline, and that this information helps meet continuing surveillance and active corrosion rules. SIRRC's suggested revision of Sec. 192.459 follows: Whenever an operator has knowledge that any portion of a buried pipeline is exposed, the exposed portion must be examined to determine the condition of the coating, or if the pipeline is bare or the coating is deteriorated, the exterior condition of the pipe. A record of the examination results shall be made in accordance with Sec. 192.491(c). If external corrosion is found, remedial action must be taken to the extent required by Sec. 192.483 and the applicable paragraphs of Secs. 192.485, 192.487, or 192.489. Recommendation: With regard to Sec. 192.467(d), NAPSR recommended changes that would require operators to test pipeline casings annually for electrical isolation, and to clarify what must be done to minimize pipeline corrosion if isolation is not achieved. Comments: Three commenters reported that SIRRC did not agree on whether shorted casings are a problem or on the need to test casings, but agreed that Sec. 192.483 should be amended to include options for dealing with shorted casings. SIRRC said its suggested options are consistent with common industry practice. SIRRC also recognized that the options were not intended as a substitute for proper cathodic protection of pipe under Sec. 192.463. SIRRC's suggested revision of Sec. 192.483 follows: (d) If it is determined that a casing is electrically shorted to a pipeline, the operator shall: (1) clear the short, if practical; (2) fill the casing with a corrosion inhibiting material; (3) monitor for leakage with leak detection equipment at least once each calendar year at intervals not exceeding 15 months; or (4) conduct an initial inspection with an internal inspection device capable of detecting external corrosion in a cased pipeline, and repeat at least every 5 years at intervals not to exceed 63 months. Recommendation: With regard to Sec. 192.479(b), NAPSR recommended that regardless of the date of installation, all aboveground pipelines or portions of a pipeline that are exposed to the atmosphere be cleaned and either coated or jacketed with a material suitable for the prevention of atmospheric corrosion, unless the pipeline is in a non- corrosive atmosphere. Comments: Two commenters reported that SIRRC reached a consensus that all aboveground pipe should be subject to the same protection requirement. SIRRC's suggested revision of Sec. 192.479, which would remove the present distinction between pipelines installed before and after particular dates, is set forth below. SIRRC also explained that the term ``active corrosion'' does not include non-damaging corrosive films. [192.479] (a) Each aboveground pipeline or portion of a pipeline that is exposed to the atmosphere must be cleaned and either coated or jacketed with a material suitable for the prevention of atmospheric corrosion. An operator need not comply with this paragraph, if the operator can demonstrate by test, investigation, or experience in the area of application that active corrosion does not exist. (b) If active corrosion is found on an aboveground pipeline or portion of pipeline, the operator shall (1) take prompt remedial action consistent with the severity of the corrosion to the extent required by the applicable paragraphs of Secs. 192.485, 192.487, or 192.489; and (2) clean and either coat or jacket the areas of atmospheric corrosion with a material suitable for the prevention of atmospheric corrosion. Recommendation: With regard to the provision in Sec. 192.487(a) that permits general corrosion in distribution line pipe to be repaired instead of replaced, NAPSR recommended that the provision refer to generally accepted guidelines for determining what corroded areas may be repaired. Comments: Two commenters reported that SIRRC did not address this issue. In addition, these commenters suggested we allow operators to assess the serviceability of distribution line pipe that has wall thickness less than 30 percent of nominal wall thickness instead of requiring the replacement of such pipe. Recommendation: With regard to Sec. 192.489(b), NAPSR recommended that we clarify that internal sealing is not an appropriate method of strengthening graphitized pipe. Comments: Two commenters reported that SIRRC agreed to drop this recommendation, since advances in technology may produce strength enhancing liners. Gas Piping Technology Committee The following recommendations are from an April 1995, rulemaking petition by GPTC: Recommendation: Remove from Sec. 192.467 the requirement that pipe be electrically isolated from metallic casings. GPTC argued there are no safety benefits from clearing shorted casings. Comments: There were no comments on this recommendation. But see the comments above on Sec. 192.467. Recommendation: Amend Secs. 192.465 and 192.481 to allow operators to take up to 39 months to carry out inspections of unprotected pipelines that must be done at 3-year intervals. GPTC said the extra time would add flexibility to the standards, with no reduction in safety. Comments: The one comment on this recommendation supported the 39- month period but preferred a 5-year interval to match the interval of leakage surveys. Also, see the comments above on Secs. 192.465 and 192.481. National Transportation Safety Board As a result of a 1996 accident on a butane pipeline operated by Koch Pipeline Company near Lively, Texas, NTSB recommended two changes to the Part 195 corrosion control standards: Recommendation: Revise Part 195 to require pipeline operators to determine the condition of pipeline coating whenever pipe is exposed and, if degradation is found, to evaluate the coating condition of the pipeline. (P-98-35) Comments: There were no comments on this recommendation. But see the SIRRC comment above on Sec. 192.459. Re
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