RegulusPipeline researchPHMSA Guidance, Pipeline Safety: Standards for Direct Assessment of Gas and Hazardous Liquid Pipelines
Portal detail 1Pipeline Safety: Standards for Direct Assessment of Gas and Hazardous Liquid Pipelines 05-21233.pdf (169.08 KB) Under current regulations governing integrity management of gas transmission lines, if an operator uses direct assessment to evaluate corrosion risks, it must carry out the direct assessment according to PHMSA standards. In response to a statutory directive, this Final Rule prescribes similar standards operators must meet when they use direct assessment on certain other onshore gas, hazardous liquid, and carbon dioxide pipelines. PHMSA believes broader application of direct assessment standards will enhance public confidence in the use of direct assessment to assure pipeline safety.#
Portal detail 2Effective Date: Tuesday, October 25, 2005#
Attachment 1, passage 1Federal Register/ Vol. 70, No. 205/Tuesday, October 25, 2005/ Rules and Regulations 61571 area(s) which result from a CERCLA administrative order, a CERCLA or RCRA 1552.229-70 [Removed and reserved] * consent decree or a court order. 1552.229-70. • 11. Remove and reserve section on pipelines made primarily of steel or collection, indirect inspection, direct iron. The process involves data (Start) (Apr 2004) Limitation of Future Contracting Alternate II 1552.237-73 [Removed and reserved] examination, and evaluation. Operators existing corrosion defects but also to use direct assessment not only to find • 12. Remove and reserve section including any options, the Contractor agrees (d) During the life of this contract, 1552.237-73. prevent future corrosion problems. [FR Doc. 05-21196 Filed 10-24-05; 8:45 am] using direct assessment on U.S Congress recognized the advantages of that unless otherwise authorized by the Contracting Officer: BILLING CODE 6560-50-P Department of Transportation (DOT) services (e.g., Emergency and Rapid (1) It will not provide to EPA cleanup carbon dioxide pipeline facilities. regulated gas, hazardous liquid, and Response Services (ERRS) contracts) within DEPARTMENT OF TRANSPORTATION Improvement Act of 2002 (Pub. L. 107- Section 14 of the Pipeline Safety the Contractor's START assigned geographical area(s), either as a prime Safety Administration Pipeline and Hazardous Materials Contractor, subcontractor, or consultant. 355; Dec. 17, 2002) directs DOT to issue has been prepared by a third party, it will not (2) Unless an individual design for the site pressure testing, and direct assessment regulations on using internal inspection, 49 CFR Parts 192 and 195 subcontractor or consultant any remedial provide to EPA as a prime contractor, [Docket No. RSPA-04-16855; Amdt. 192- facilities in high consequence areas. In to manage the risks to gas pipeline performed or plans to perform START work. construction services at a site where it has 101 and 195-85] addition, Section 23 directs DOT to contractors from performing construction This clause will not preclude START RIN 2137—AD97 for inspecting pipeline facilities by issue regulations prescribing standards management services under other EPA Assessment of Gas and Hazardous Pipeline Safety: Standards for Direct direct assessment. directive, Section 14, DOT's Research In response to the first statutory type activities contracts for sites within its (3) It will be ineligible for award of ERRS Liquid Pipelines respective START assigned geographical Materials Safety Administration AGENCY: Pipeline and Hazardous (RSPA) 1 published regulations in 49 and Special Programs Administration administrative order, a CERCLA or RCRA area(s) which result from a CERCLA (PHMSA), DOT. operators to follow detailed programs to CFR part 192, subpart O, that require consent decree or a court order. ACTION: Final rule. manage the integrity of gas transmission governing integrity management of gas SUMMARY: Under current regulations areas. Subpart O also requires an line segments in high consequence Limitation of Future Contracting Alternate * III (ESAT) (Apr 2004) * transmission lines, if an operator uses operator electing to use direct risks, it must carry out the direct direct assessment to evaluate corrosion program, to carry out the direct assessment in its integrity management IV (TES) (Apr 2004) Limitation of Future Contracting Alternate assessment according to PHMSA 192.927, and 192.929, as appropriate.2 assessment according to SS 192.925, * standards. In response to a statutory directive, this Final Rule prescribes 192.929 cross-reference the American Sections 192.925, 192.927, and Limitation of Future Contracting Alternate V when they use direct assessment on similar standards operators must meet (Headquarters Support) (Apr 2004) (ASME), ASME B31.8S-2001, Society of Mechanical Engineers' certain other onshore gas, hazardous contract, will be ineligible to enter into a (c) The Contractor, during the life of this PHMSA believes broader application of liquid, and carbon dioxide pipelines. Pipelines. "Managing System Integrity of Gas describes a comprehensive process to " ASME B31 8S_2001| work (e.g., Response Action Contract (RAC), contract with EPA to perform response action enhance public confidence in the use of direct assessment standards will assess and mitigate the likelihood and (ERRS), Superfund Technical Assistance and Emergency and Kapid Response Services direct assessment to assure pipeline addition, $ 192.925 cross-references a consequences of gas pipeline risks. In Support Services (ESS) contracts), unless Removal Team (START), and Enforcement otherwise authorized by the Contracting DATES: This Final Rule takes effect reference of NACE Standard RP0502- November 25, 2005. Incorporation by Programs Improvement Act (Pub. L. 108-426, 118; 1 The Norman Y. Mineta Research and Special November 30, 2004) reorganized RSPA into two 2002 in this rule is approved by the Hazardous Materials Safety Administration new DOT administrations: the Pipeline and VI (Site Specific) (Apr 2004) Limitation of Future Contracting Alternate November 25, 2005. Director of the Federal Register as of (PHMSA) and the Research and Innovative * * Technology Administration. RSPA's regulatory Furrow by phone at 202-366-4559, by FOR FURTHER INFORMATION CONTACT: L.M. safety was transferred to PHMSA. authority over pipeline and hazardous materials including any options, the Contractor agrees (d) During the life of this contract, Department of Transportation, 400 fax at 202-366-4566, by mail at U.S. assessment $ 192.925) requires operators to 2 The standard on external corrosion direct Contracting Officer: that unless otherwise authorized by the integrate data on physical characteristics and Technical Assistance and Removal Team (1) It will not provide any Superfund Seventh Street, SW., Washington, DC inspections, directly examine pipe surfaces, and operating history, conduct indirect aboveground buck.furrow@dot.gov. 20590, or by e-mail at (START) type activities (e.g., START Under the standard for direct assessment of internal evaluate the effectiveness of the assessment process. contractor, subcontractor, or consultant. contracts) to EPA on the site either as a prime SUPPLEMENTARY INFORMATION: corrosion (§ 192.927), operators must predict locations where electrolytes may accumulate in * I. Background normally dry-gas pipelines, examine those assessment, a process of managing the This Final Rule concerns direct standard for direct assessment of stress corrosion locations, and validate the assessment process. The 1552.215-76 [Removed and reserved] relevant to stress corrosion cracking, assessing the cracking (§ 192.929) involves collecting data 1552.215-76. • 10. Remove and reserve section effects of external corrosion, internal corrosion, or stress corrosion cracking evaluating segments at risk. risk of pipeline segments, and examining and#
Attachment 1, passage 261572 Federal Register / Vol. 70, No. 205 / Tuesday, October 25, 2005 / Rules and Regulations NACE International (NACE) standard, NACE Standard RP0502–2002, ‘‘Pipeline External Corrosion Direct Assessment Methodology.’’ NACE Standard RP0502–2002 describes a step- by-step process for identifying and addressing external corrosion activity, repairing defects, and taking remedial action. Other parts of § § 192.925, 192.927, and 192.929 ensure operators use appropriate criteria in making direct assessment decisions. II. Proposed Rules In response to the second statutory directive, Section 23, PHMSA published a notice of proposed rulemaking (NPRM) (69 FR 61771; Oct. 21, 2004). The NPRM proposed standards for using direct assessment on any onshore gas pipeline made primarily of steel or iron and regulated by 49 CFR part 192 or onshore steel hazardous liquid or carbon dioxide pipeline regulated by 49 CFR part 195. Under proposed § 192.490, if an operator chooses to use direct assessment to evaluate the threat of external corrosion, internal corrosion, or stress corrosion cracking on a regulated onshore gas pipeline, the direct assessment would have to be done according to § § 192.925, 192.927, or 192.929, as appropriate. For regulated hazardous liquid and carbon dioxide pipelines, proposed § 195.588 would require similar action, except compliance with § 192.927 would not be required, because § 192.927 requirements are only suitable for dry gas pipelines. III. Advisory Committee Recommendations The Technical Pipeline Safety Standards Committee (TPSSC) and the Technical Hazardous Liquid Pipeline Safety Standards Committee (THLPSSC) considered the NPRM at meetings in Washington, DC, on December 14 and 15, 2004. The TPSSC, a statutorily mandated advisory committee, advises PHMSA on proposed safety standards and other policies concerning gas pipelines. The THLPSSC is a similar committee that provides advice about hazardous liquid and carbon dioxide pipelines. Each committee has an authorized membership of 15 persons with membership evenly divided between government, industry, and the public. Each member is qualified to consider the technical feasibility, reasonableness, cost-effectiveness, and practicability of proposed pipeline safety standards. A transcript of each committee’s meeting is available in Docket No. PHMSA–98–4470. After careful consideration of the NPRM, the THLPSSC voted unanimously to recommend the State pipeline safety agency ................................................... Gas pipeline operators ............................................................ following: (1) Adopt a single definition of direct assessment for use by hazardous liquid pipeline operators inside and outside high consequence areas; (2) state direct assessment standards directly in part 195, rather than by cross-referencing part 192 standards; (3) consider adopting the consensus standard under development by NACE for direct assessment of stress corrosion cracking; and (4) amend the integrity management rule (§ 195.452) to allow use of direct assessment without prior notice. As a result of its deliberation, the TPSSC voted unanimously that proposed § 192.490 should not be applied to gas distribution lines. It also voted unanimously that the Final Rule should distinguish direct assessment from similar methods of assessing corrosion. Such a distinction would identify situations where similar methods of addressing corrosion are appropriate but are not regulated under the proposed direct assessment standard. IV. Disposition of Comments and Advisory Committee Recommendations on Proposed Rules We received written comments on the proposed rules from 19 sources. These sources are categorized as follows: Pennsylvania Public Utility Commission. Duke Energy Gas Transmission (Duke), El Paso Corporation (El Paso), Nicor Gas (Nicor), NiSource Corporate Services Company (Nisource), Pacific Gas & Electric Company (PG&E), Paiute Pipeline Company (Paiute), Puget Sound Energy (Puget), Southwest Gas Corporation (SWGas). American Public Gas Association (APGA), American Gas Association (AGA), Interstate Natural Gas Association of America (INGAA), Northeast Gas Asso- ciation (NGA). Gas Piping Technology Committee (GPTC). American Petroleum Institute (API), Association of Oil Pipe Lines (AOPL). Cook Inlet Regional Citizens Advisory Council, Pipeline Safety Trust Glen F. Armstrong. Gas pipeline trade associations .............................................. Gas pipeline industry committee ........................................... Hazardous liquid pipeline trade associations ....................... Nonprofit organizations .......................................................... Consultant ................................................................................ Only one commenter, the Cook Inlet Regional Citizens Advisory Council (Council), created by the Oil Pollution Act of 1990, supported the proposed rules without change. The Council welcomed the additional Federal standards because of the need to control pipeline corrosion. The remaining commenters’ issues are stated below along with our disposition of those issues and the advisory committee’s recommendations. Is this rulemaking necessary? AGA, Duke, El Paso, GPTC, INGAA, NiSource, and Puget claimed the integrity management regulations for gas transmission lines (subpart O of part 192) satisfy the statutory directive to prescribe direct assessment standards. Taking a similar position, AOPL and API contended that Congress did not intend direct assessment standards to apply outside integrity management regulations. To support this position, these commenters stated that Congress did not require operators to use direct assessment on pipelines outside integrity management regulations. They also pointed out that direct assessment was developed for use in integrity management programs. Because the legislative history does not support the commenter’s argument that direct assessment standards should apply only to pipelines subject to integrity management rules, PHMSA believes this rulemaking is necessary. It is reasonable to conclude Congress did not intend to restrict direct assessment standards to pipelines covered by integrity management regulations. Unlike the first statutory directive concerning direct assessment, which applies only to pipeline facilities in high consequence areas, the second directive applies to pipeline facilities regardless of location. Also, the first and second directives appear in separate sections of the statute (Sections 14 and 23 of Pub. L. 107–355), with no apparent connection. Had Congress wanted to restrict direct assessment standards to pipelines covered by integrity management regulations, it could have expressly linked the second directive to the first or included the second directive in the same section as the first. Is proposed § 192.490 appropriate for gas distribution lines? AGA, APGA, VerDate Aug<31>2005 15:21 Oct 24, 2005 Jkt 208001 PO 00000 Frm 00026 Fmt 4700 Sfmt 4700 E:\FR\FM\25OCR1.SGM 25OCR1#
Attachment 1, passage 3Federal Register / Vol. 70, No. 205 / Tuesday, October 25, 2005 / Rules and Regulations 61573 Duke, El Paso, GPTC, INGAA, NGA, Nicor, NiSource, Paiute, and PG&E argued direct assessment was developed for gas transmission integrity management and has not been shown to be appropriate for gas distribution lines. They said the relevant technical data and experience do not show direct assessment would be effective on gas distribution lines. In addition, some of these commenters thought because gas distribution lines differ from gas transmission lines in design, operation, configuration, and location, direct assessment may be impractical on gas distribution lines. The many aboveground and belowground utility facilities—both in-service and abandoned—were thought to pose significant technical hurdles. The Pennsylvania Public Utility Commission and the Pipeline Safety Trust also questioned the suitability of direct assessment for gas distribution lines. These comments came as a surprise to PHMSA because the two documents that are the mainstays of the proposed direct assessment standards, ASME B31.8S–2001 and NACE Standard RP0502–2002, can be interpreted to cover gas distribution lines. Each document states that it applies to onshore pipelines. Although neither document defines ‘‘pipeline,’’ ASME’s B31.8 Code, to which ASME B31.8S– 2001 is a supplement, defines ‘‘pipeline’’ as ‘‘all parts of physical facilities through which gas moves in transportation.’’ And ‘‘transportation of gas’’ is defined as the ‘‘gathering, transmission, or distribution of gas.’’ No matter how ASME B31.8S–2001 and NACE Standard RP0502–2002 are interpreted, the comments persuaded us that direct assessment, as depicted by these two documents, is not appropriate for gas distribution lines. Both ASME B31.8S–2001 and NACE Standard RP0502–2002, were developed during the rulemaking proceeding on gas transmission integrity management and in furtherance of that proceeding. Consequently, neither document was developed with a focus on gas distribution lines. Furthermore, although both documents apply to pipelines, they do not take full account of gas distribution line features as comments suggest they should to treat gas distribution lines appropriately. Given these considerations and the TPSSC’s unanimous recommendation that we not apply the proposed direct assessment standards to gas distribution lines, we decided to exclude distribution lines from final § 192.490. Removing ‘‘pipeline’’ from the proposed wording and adding ‘‘transmission line’’ in its place accomplishes this change. Would the proposed standards discourage the voluntary use of corrosion control methods? AGA, Armstrong, Duke, El Paso, GPTC, INGAA, NGA, Nicor, NiSource, Paiute, PG&E, Puget, and SWGas were concerned the proposed standards (§ § 192.490 and 195.588) would discourage operators from voluntarily using corrosion control methods related to direct assessment on pipelines not subject to the integrity management regulations. Their concern stemmed from the difficulty of recognizing when direct assessment is being used. They said performance of any one of the four steps that constitute direct assessment could imply use of direct assessment and lead to disagreements with government inspectors over whether direct assessment is being used. For example, some commenters said performing a close interval electrical survey resembled the indirect examination step of direct assessment. Others thought examining buried pipe for corrosion could be considered the direct examination step. El Paso, INGAA, Nicor, and Armstrong suggested the Final Rule clarify that operators may use corrosion control methods related to direct assessment without having to meet the proposed direct assessment standards. We recognize disagreements could arise over whether the use of a corrosion control method is part of the direct assessment process. However, we do not think such disagreements are likely to be serious enough to discourage operators from continuing to use such methods separately from direct assessment. To minimize potential disagreements, operators may explain in their corrosion control procedures the situations in which they use methods related to direct assessment separately from direct assessment. In view of the commenters’ concern, PHMSA has added provisions to final § § 192.490 and 195.588 to clarify application of the direct assessment standards. The statement provides that the direct assessment standards do not apply to methods related to direct assessment, such as close interval surveys, voltage gradient surveys, or examination of exposed pipelines, when used separately from the direct assessment process. This change is consistent with the TPSSC’s second recommendation. Are the gas pipeline standards cross- referenced in proposed § 195.588 suitable for hazardous liquid and carbon dioxide pipelines? In their comments on proposed § 195.588, AOPL and API opposed cross-referencing § § 192.925 and 192.929 primarily because these standards refer to ASME B31.8S–2001. They argued ASME B31.8S–2001 was developed for natural gas transmission lines and without the involvement of hazardous liquid pipeline operators. They were also concerned that cross-referencing part 192 gas pipeline standards could lead to misunderstandings by hazardous liquid pipeline operators. The THLPSSC similarly opposed cross-referencing part 192 standards. In developing the NPRM, we assumed the cross-referenced part 192 standards and their cross-references to ASME B31.8S–2001 would be suitable for hazardous liquid and carbon dioxide pipelines. However, the AOPL and API comments and the THLPSSC’s recommendation have caused us to doubt that assumption. In addition, we are concerned that application of the part 192 direct assessment standards to hazardous liquid and carbon dioxide pipelines could present compliance problems. Contributing to this concern is the comment that ASME B31.8S–2001 was not developed with an eye to hazardous liquid pipelines. In fact, paragraph 1.1 of ASME B31.8S–2001 specifically states that the scope of ASME B31.8S–2001 is limited to ‘‘onshore pipeline systems * * * that transport gas.’’ Therefore, we decided not to include cross-references to part 192 standards or to ASME B31.8S–2001 in final § 195.588. Instead, final § 195.588 includes a complete statement of direct assessment standards, with cross- references only to NACE Standard RP0502–2002. Should the integrity management regulations for hazardous liquid and carbon dioxide pipelines allow use of direct assessment without advance notice? The integrity management regulations for hazardous liquid and carbon dioxide pipelines (§ 195.452) prescribe three ways to assess pipeline integrity: internal inspection via a smart pig, pressure testing, and any other technology the operator demonstrates can provide an equivalent understanding of pipe conditions. However, before another technology, such as direct assessment may be used, the operator must notify PHMSA at least 90 days in advance (§ § 195.452(c)(1)(i)(C) and 195.452(j)(5)(iii)). In contrast to § 195.452, the proposed direct assessment standards do not include a requirement to give 90 days’ advance notice as a precondition to using direct assessment. We see no need to propose such a requirement since the current Part 192 direct assessment standards do not require operators to VerDate Aug<31>2005 15:21 Oct 24, 2005 Jkt 208001 PO 00000 Frm 00027 Fmt 4700 Sfmt 4700 E:\FR\FM\25OCR1.SGM 25OCR1#
Attachment 1, passage 461574 Federal Register / Vol. 70, No. 205 / Tuesday, October 25, 2005 / Rules and Regulations give advance notice before using direct assessment. In their comments on proposed § 195.588, AOPL and API suggested direct assessment of external corrosion should be listed directly in § 195.452 as a permissible method of integrity assessment. They believe that when external corrosion direct assessment is performed according to NACE Standard RP0502–2002, it is an acceptable use of ‘‘other technology’’ for which 90 days advance notice is no longer necessary. As discussed above under Advisory Committee Recommendations, the THLPSSC also favored listing direct assessment directly in § 195.452 as a recognized assessment method that would bypass the 90-day advance notice requirement. The purpose of the 90 days advance notice requirement in § 195.452 is to provide time for PHMSA and State pipeline safety agencies to review technology other than pigging and pressure testing to learn what information the technology provides about pipe conditions. According to information on a PHMSA Web site (http://primis.phmsa.dot.gov/iim/ notifications.imd), several operators have submitted notices of their intent to use direct assessment on hazardous liquid or carbon dioxide pipelines. In a majority of cases, there were no PHMSA or State government objections to the use of direct assessment. Objections were raised where the notification lacked information explaining how the direct assessment was to be performed. When applied to direct assessment, we believe the 90-day advance notice requirement of § 195.452 is no longer useful and is inconsistent with the proposed rules. Direct assessment is now being used under the part 192 integrity management regulations without advance notice. As a result, government inspectors are fully aware of the direct assessment technology and the situations for which it is suited, making advance case-by-case review under § 195.452 unnecessary. In addition, requiring operators to follow prescribed standards when using direct assessment will remove the primary objection previously raised about operators’ advance notices—insufficient information to explain the method of assessment. Therefore, we are changing § § 195.452(c)(1)(i)(C) and 195.452(j)(5)(iii) to allow use of direct assessment in accordance with final § 195.588 without 90 days advance notice. What standard should apply to direct assessment of stress corrosion cracking on hazardous liquid and carbon dioxide pipelines? The NPRM proposed that § 192.929 be the standard for direct assessment of stress corrosion cracking on hazardous liquid and carbon dioxide pipelines. This standard relies largely on cross-references to ASME B31.8S– 2001. Besides their objections to cross- referencing part 192 standards and particularly ASME B31.8S–2001, AOPL and API suggested that we not adopt any standard for the direct assessment of stress corrosion cracking on hazardous liquid pipelines. They said because methods of detecting stress corrosion cracking are developing rapidly, direct assessment may not be the optimum technology for hazardous liquid pipelines. The THLPSSC recommended we consider adopting the consensus standard that NACE International was developing for direct assessment of stress corrosion cracking. As explained above, we decided not to cross-reference directly or indirectly ASME B31.8S–2001 in final § 195.588, because the document is closely identified with gas pipelines. Consequently, since provisions of ASME B31.8S–2001 are an important part of the proposed stress corrosion standard, we have not included a direct assessment standard for stress corrosion cracking in final § 195.588. As the THLPSSC recommended, we will consider the recently published NACE Standard RP0204–2004, Stress Corrosion Cracking (SCC) Direct Assessment Methodology, for possible future rulemaking action. By removing the proposed cross-reference to § 192.929, final § 195.588 consists of the text of § 192.925 without its cross- references to ASME B31.8S–2001. V. Editorial Changes • Final § § 192.490 and 195.588 do not include the proposed phrase ‘‘or to meet any requirement of this Subpart regarding that threat.’’ The phrase was used in the proposed rules to draw attention to situations in which operators might choose to use direct assessment. However, the phrase appears to be unnecessary and, according to comments, possibly confusing. • Final § 192.490 clarifies that ‘‘direct assessment’’ means direct assessment as defined in § 192.903.3 This definition applies to ‘‘direct assessment’’ as it is 3 Section 192.903 defines ‘‘direct assessment’’ as ‘‘an integrity assessment method that utilizes a process to evaluate certain threats (i.e., external corrosion, internal corrosion and stress corrosion cracking) to a covered pipeline segment’s intergrity. The process includes the gathering and integration of risk factor data, indirect examination or analysis to identify areas of suspected corrosion, direct examination of the pipeline in these areas, and post assessment evaluation.’’ used in subpart O of part 192, including § § 192.925, 192.927, and 192.929—the bases of the proposed direct assessment standards. Also, in final § 192.490, instead of using the proposed term ‘‘ferrous’’ to limit pipelines to which the direct assessment standards apply, we used ‘‘made primarily of steel or iron.’’ This change removes the possibility of confusion over the meaning of ferrous. • We added a similar definition of ‘‘direct assessment’’ to § 195.553, which contains definitions applicable to subpart H of part 195, including final § 195.588. This addition satisfies the first THLPSSC recommendation. The definition of ‘‘external corrosion direct assessment,’’ which was proposed through the cross-reference to § 192.925, is also added to § 195.553. • In final § 195.588, we substituted ‘‘pipeline segment’’ for the terms ‘‘covered segment’’ and ‘‘covered pipeline segment’’ to avoid the possibility that the definition of these terms in § 192.903—a segment of transmission pipeline located in a high consequence area—would unintentionally constrain the scope of final § 195.588. A footnote resolves a similar problem in final § 192.490. • Section 192.925(b) provides that if coating damage is detected by external corrosion direct assessment, the operator must integrate that information with data gathered and integrated under certain other requirements (§ § 192.917(b) and 192.917(e)(1)). These other requirements, which involve evaluating and addressing risks besides corrosion, including third-party damage, apply only to gas transmission lines subject to the integrity management regulations in subpart O of part 192. Although the proposed direct assessment standards for other pipelines included cross-references to § 192.925, the NPRM did not address extending § § 192.917(b) and 192.917(e)(1) to pipelines outside subpart O by virtue of the cross-references. The focus of the NPRM was strictly on using direct assessment to evaluate and address corrosion risks. Using direct assessment data to evaluate non-corrosion risks to pipeline integrity was not discussed. So it would be inappropriate to infer that the proposed references to § 192.925 meant that operators who voluntarily use external corrosion direct assessment on pipelines outside subpart O would also have to comply with § § 192.917(b) and 192.917(e)(1). To ensure this possible inference does not affect the Final Rules, final § § 192.490 and 195.588 exclude pipelines outside subpart O from the § 192.925(b) requirement related to integrating coating damage data. Nevertheless, for VerDate Aug<31>2005 15:21 Oct 24, 2005 Jkt 208001 PO 00000 Frm 00028 Fmt 4700 Sfmt 4700 E:\FR\FM\25OCR1.SGM 25OCR1#
Attachment 1, passage 5Federal Register / Vol. 70, No. 205 / Tuesday, October 25, 2005 / Rules and Regulations 61575 hazardous liquid and carbon dioxide pipelines that are subject to the integrity management regulations in § 195.452, the detection of coating damage is an important factor to consider in the information analysis required by § 195.452(g) and the continual integrity evaluation required by § 195.452(j)(2). VI. Regulatory Analyses and Notices Executive Order 12866 and DOT Policies and Procedures. PHMSA does not consider this rulemaking to be a significant regulatory action under Section 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 the Final Rule to review. PHMSA also does not consider this rulemaking to be significant under DOT regulatory policies and procedures (44 FR 11034: February 26, 1979). PHMSA has evaluated the costs and benefits of this Final Rule and a copy of the evaluation is in the docket. The evaluation concludes operators will incur only minimal costs to comply with the Final Rule. Regulatory Flexibility Act. Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.), PHMSA must consider whether rulemaking actions have a significant economic impact on a substantial number of small entities. Based on the facts available about the anticipated impacts of this rulemaking, I certify that this rulemaking will not have a significant impact on a substantial number of small entities. Executive Order 13175. PHMSA has analyzed this rulemaking according to the principles and criteria contained in Executive Order 13175, ‘‘Consultation and Coordination with Indian Tribal Governments.’’ Because the Final Rule will not significantly or uniquely affect the communities of the Indian Tribal Governments nor impose substantial direct compliance costs, the funding and consultation requirements of Executive Order 13175 do not apply. Paperwork Reduction Act. Operators have just recently begun to use direct assessment to assess the effects of corrosion on onshore gas transmission lines subject to the integrity management regulations in subpart O of part 192. The use of direct assessment on other pipelines regulated by part 192 or part 195 is voluntary. This Final Rule does not change this voluntary use status. It merely sets standards for performing direct assessment if operators choose to use it. Pipeline operators covered by the Final Rule who choose to use direct assessment would have to prepare appropriate plans and procedures and keep records as required by Section 7 of NACE Standard RP0502–2002. To help estimate the paperwork burden these operators would face, the NPRM invited comments on how many operators plan to use direct assessment voluntarily and what the burden hours and cost would be. None of the commenters foresaw any voluntary use of direct assessment or commented on the potential paperwork burden. This result was not a surprise, for direct assessment is a new process and so far its use is mostly limited to gas transmission lines subject to subpart O of part 192. Under these circumstances, it is reasonable to expect that few, if any, operators will be affected by the Final Rule. So no net increase in paperwork burdens is likely from this Final Rule. For this reason, we believe that submitting an analysis of the burdens to OMB under the Paperwork Reduction Act is unnecessary. Unfunded Mandates Reform Act of 1995. This Final Rule does not impose unfunded mandates under the Unfunded Mandates Reform Act of 1995. It does not result in costs of $100 million or more to either State, local, or tribal governments, in the aggregate, or to the private sector, and is the least burdensome alternative that achieves the objective of the rulemaking. National Environmental Policy Act. PHMSA has analyzed the Final Rule for purposes of the National Environmental Policy Act (42 U.S.C. 4321 et seq.). Because the Final Rule affects only those operators that voluntarily use direct assessment and because it largely involves processes of data collection and evaluation, we have determined that it is unlikely to significantly affect the quality of the human environment. An Environmental Assessment is available for review in the docket. Executive Order 13132. PHMSA has analyzed the Final Rule according to the principles and criteria contained in Executive Order 13132, ‘‘Federalism.’’ No part of the rule (1) has substantial direct effects on the States, the relationship between the national government and the States, or the distribution of power and responsibilities among the various levels of government; (2) imposes substantial direct compliance costs on State and local governments; or (3) preempts State law. Therefore, the consultation and funding requirements of Executive Order 13132 do not apply. Executive Order 13211. This Final Rule is not a ‘‘Significant Energy Action’’ under Executive Order 13211. It is not a significant regulatory action under Executive Order 12866 and is not likely to have a significant adverse effect on the supply, distribution, or use of energy. Further, this rulemaking has not been designated by the Administrator of the Office of Information and Regulatory Affairs as a significant energy action. List of Subjects 49 CFR Part 192 Natural gas, Pipeline safety, Reporting and recordkeeping requirements. 49 CFR Part 195 Ammonia, Carbon dioxide, Incorporation by reference, Petroleum, Pipeline safety, Reporting and recordkeeping requirements. s In consideration of the foregoing, PHMSA amends 49 CFR parts 192 and 195 as follows: PART 192—TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: MINIMUM FEDERAL SAFETY STANDARDS s 1. The authority citation for part 192 continues to read as follows: Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 60113, and 60118; and 49 CFR 1.53. s 2. Add § 192.490 to read as follows: § 192.490 Direct assessment. Each operator that uses direct assessment as defined in § 192.903 on an onshore transmission line made primarily of steel or iron to evaluate the effects of a threat in the first column must carry out the direct assessment according to the standard listed in the second column. These standards do not apply to methods associated with direct assessment, such as close interval surveys, voltage gradient surveys, or examination of exposed pipelines, when used separately from the direct assessment process. Threat External corrosion ................... Internal corrosion in pipelines that transport dry gas. Stress corrosion cracking ....... Standard 1 § 192.925 2 § 192.927 § 192.929 1 For lines not subject to subpart O of this part, the terms ‘‘covered segment’’ and ‘‘cov- ered pipeline segment’’ in §§ 192.925, 192.927, and 192.929 refer to the pipeline segment on which direct assessment is per- formed. 2 In § 192.925(b), the provision regarding de- tection of coating damage applies only to pipe- lines subject to subpart O of this part. PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE s 3. The authority citation for part 195 continues to read as follows: VerDate Aug<31>2005 15:21 Oct 24, 2005 Jkt 208001 PO 00000 Frm 00029 Fmt 4700 Sfmt 4700 E:\FR\FM\25OCR1.SGM 25OCR1#
Attachment 1, passage 661576 Federal Register/ Vol. 70, No. 205/Tuesday, October 25, 2005/ Rules and Regulations 60108, 60109, 60118; and 49 CFR 1.53. Authority: 49 U.S.C. 5103, 60102, 60104, inspection, direct examination, and post-assessment to evaluate the threat of assessment tools; (A) The known sensitivities of • 4. In § 195.3(c), amend the table of external corrosion to the integrity of a tool; and (B) The procedures for using each referenced material by adding item G.(2) to read as follows: pipeline. * * decreasing the physical spacing of (C) The approach to be used for whole or in part. Matter incorporated by reference in • 7. Add § 195.588 to read as follows: § 195.588 What standards apply to direct indirect assessment tool readings when (c)** * assessment? the presence of a defect is suspected during the indirect examination, criteria (iii) For each indication identified onshore pipeline to evaluate the effects (a) If you use direct assessment on an for- G. (2) NACE Standard RP0502- Corrosion Direct Assess- 2002 "Pipeline External § 195.588 the requirements of this section for of external corrosion, you must follow excavation and direct examination of (A) Defining the urgency of assessment. This section does not apply performing external corrosion direct the indication; and ment Methodology" (2002). immediate, scheduled, or monitored; (B) Defining the excavation urgency as to methods associated with direct • a. Redesignate paragraph (c)(1)(i)(C) as • 5. Amend § 195.452 as follows: assessment, such as close interval examination of exposed pipelines, when surveys, voltage gradient surveys, or excavations of indications in each (iv) Criteria for scheduling (c)(1)(i)(D); • b. Remove "or" from the end of used separately from the direct urgency level paragraph (c)(1)(i)(B); assessment process. the requirements in Section 5 of NACE (4) Direct examination. In addition to (j)(5)(iv); • c. Redesignate paragraph (j)(5)(iii) as external corrosion direct assessment are (b) The requirements for performing for direct examination of indications Standard RP0502-2002, the procedures • d. Remove "or" from the end of as follows: paragraph (j)(5)(ii); and requirements of NACE Standard (1) General. You must follow the from the indirect examination must (j)(5)(iii) to read as follows: • e. Add new paragraphs (c)(1)(i)(C) and reference, see § 195.3). Also, you must RP0502-2002 (incorporated by restrictive criteria when conducting (i) Provisions for applying more high consequence areas. § 195.452 Pipeline integrity management in that includes procedures addressing develop and implement an ECDA plan ECDA for the first time on a pipeline * (c) * direct examination, and post- pre-assessment, indirect examination, should be taken if either: (ii) Criteria for deciding what action (1)* that exceed allowable limits (Section (A) Corrosion defects are discovered (C) External corrosion direct (i) * * requirements in Section 3 of NACE (2) Pre-assessment. In addition to the 5.5.2.2 of NACE Standard RP0502-2002 §195.588; or assessment in accordance with procedures for pre-assessment must Standard RP0502-2002, the ECDA plan provides guidance for criteria); or conditions for which ECDA is not (B) Root cause analysis reveals (i) * * * * include restrictive criteria when conducting (i) Provisions for applying more suitable (Section 5.6.2 of NACE (5)*** guidance for criteria); Standard RP0502-2002 provides assessment in accordance with (iii) External corrosion direct ECDA for the first time on a pipeline procedures for any changes in the ECDA (iii) Criteria and notification 8195.588; or least two different, but complementary, (ii) The basis on which you select at severity classification, the priority of plan, including changes that affect the • 6. In § 195.553, add definitions for "direct assessment" and "external indirect assessment tools to assess each ECDA region; and for direct examination of indications; direct examination, and the time frame corrosion direct assessment (ECDA)" as inspection method not described in (iii) If you utilize an indirect RP0502-2002, you must demonstrate Appendix A of NACE Standard what basis you will reclassify and re- (iv) Criteria that describe how and on this Subpart? § 195.553 What special definitions apply to equipment used, application procedure, the applicability, validation basis, in Section 5.9 of NACE Standard prioritize any of the provisions specified process to evaluate certain threats (i.e., assessment method that utilizes a Direct assessment means an integrity and utilization of data for the inspection RP0502-2002. (5) Post assessment and continuing to the requirements in Section 4 of (3) Indirect examination. In addition requirements in Section 6 of NACE evaluation. In addition to the and stress corrosion cracking) to a external corrosion, internal corrosion procedures for indirect examination of NACE Standard RP0502-2002, the for post assessment of the effectiveness Standard UP 0502-2002, the procedures pipeline segment's integrity. The integration of risk factor data, indirect process includes the gathering and the ECDA regions must include- of the ECDA process must include- restrictive criteria when conducting (i) Provisions for applying more term effectiveness of ECDA in (i) Measures for evaluating the long- of suspected corrosion, direct examination or analysis to identify areas ECDA for the first time on a pipeline pipeline segments; and addressing external corrosion in examination of the pipeline in these * areas, and post assessment evaluation. documenting those indications that (ii) Criteria for identifying and conditions discovered by direct (ii) Criteria for evaluating whether (ECDA) means a four-step process that External corrosion direct assessment direct examination, including at least must be considered for excavation and examination of indications in each ECDA region indicate a need for combines pre-assessment, indirect the following: an interval less than that specified in reassessment of the pipeline segment at#
Attachment 1, passage 7Federal Register / Vol. 70, No. 205 / Tuesday, October 25, 2005 / Rules and Regulations 61577 Sections 6.2 and 6.3 of NACE Standard RP0502–2002 (see Appendix D of NACE Standard RP0502–2002). Issued in Washington, DC, on October 19, 2005. Brigham A. McCown, Acting Administrator, PHMSA. [FR Doc. 05–21233 Filed 10–24–05; 8:45 am] BILLING CODE 4910–60–P DEPARTMENT OF COMMERCE National Oceanic and Atmospheric Administration 50 CFR Part 648 [Docket No. 031015257-3308-02 ; I.D. 101705B] Fisheries of the Northeastern United States; Atlantic Surfclam and Ocean Quahog Fisheries; Suspension of Minimum Atlantic Surfclam Size Limit for Fishing Year 2006 AGENCY: National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce. ACTION: Temporary rule; suspension of the Atlantic surfclam minimum size limit. SUMMARY: NMFS suspends the minimum size limit of 4.75 inches (120 mm) for Atlantic surfclams for the 2006 fishing year. This action is taken under the authority of the implementing regulations for this fishery, which allow for the annual suspension of the minimum size limit based upon set criteria. The intended effect is to relieve the industry from a regulatory burden that is not necessary, as the majority of surfclams harvested are larger than the minimum size limit. DATES: Effective January 1, 2006, through December 31, 2006. ADDRESSES: Written inquiries may be sent to Patricia A. Kurkul, Regional Administrator, National Marine Fisheries Service, Northeast Regional Office, One Blackburn Drive, Gloucester, MA 01930–2298. FOR FURTHER INFORMATION CONTACT: Brian R. Hooker, Fishery Policy Analyst, (978) 281-9220; fax (978) 281–9135. SUPPLEMENTARY INFORMATION: Section 648.72(c) of the regulations implementing the Fishery Management Plan (FMP) for the Atlantic Surfclam and Ocean Quahog Fisheries allows the Administrator, Northeast Region, NMFS (Regional Administrator) to suspend annually, by publication of a notification in the Federal Register, the minimum size limit for Atlantic surfclams. This action may be taken unless discard, catch, and biological sampling data indicate that 30 percent of the Atlantic surfclam resource is smaller than 4.75 inches (120 mm) and the overall reduced size is not attributable to harvest from beds where growth of the individual clams has been reduced because of density-dependent factors. At its June 2004 meeting, the Mid- Atlantic Fishery Management Council (Council) voted to recommend that the Regional Administrator suspend the minimum size limit for the 2005, 2006, and 2007 fishing years. In accordance with the provisions of the FMP, the Regional Administrator will publish the suspension of the surfclam minimum size if the proportion of undersized surfclams is under 30 percent of the total surfclam landings for each fishing year. Commercial surfclam data for 2005 were analyzed to determine the percentage of surfclams that were smaller than the minimum size requirement. The analysis indicated that 6.8 percent of the overall commercial landings were composed of surfclams that were less than 4.75 inches (120 mm). Based on these data, the Regional Administrator adopts the Council’s recommendation and suspends the minimum size limit for Atlantic surfclams from January 1, 2006, through December 31, 2006. Classification This action is authorized by 50 CFR part 648 and is exempt from review under Executive Order 12866.Authority: 16 U.S.C. 1801 et seq. Dated: October 20, 2005. Alan D. Risenhoover, Acting Director, Office of Sustainable Fisheries, National Marine Fisheries Service. [FR Doc. 05–21302 Filed 10–24–05; 8:45 am] BILLING CODE 3510–22–S VerDate Aug<31>2005 15:21 Oct 24, 2005 Jkt 208001 PO 00000 Frm 00031 Fmt 4700 Sfmt 4700 E:\FR\FM\25OCR1.SGM 25OCR1#
This material provides agency context. It does not replace binding regulatory text, and its legal effect depends on the underlying authority and facts.