Pipeline Safety: Design and Construction Standards To Reduce Internal Corrosion in Gas Transmission Pipelines, 74262-74265 [05-24063]

Download as PDF 74262 Federal Register / Vol. 70, No. 240 / Thursday, December 15, 2005 / Proposed Rules standards (VCS), EPA has no authority to disapprove a SIP submission for failure to use VCS. It would thus be inconsistent with applicable law for EPA, when it reviews a SIP submission, to use VCS in place of a SIP submission that otherwise satisfies the provisions of the Clean Air Act. Thus, the requirements of section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) do not apply. This rule does not impose an information collection burden under the provisions of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.) List of Subjects in 40 CFR Part 52 Environmental protection, Air pollution control, Ozone, Reporting and recordkeeping requirements, Volatile organic compounds. Authority: 42 U.S.C. 7401 et seq. Dated: December 5, 2005. Robert W. Varney, Regional Administrator, EPA New England. [FR Doc. 05–24076 Filed 12–14–05; 8:45 am] BILLING CODE 6560–50–P DEPARTMENT OF TRANSPORTATION Pipeline and Hazardous Materials Safety Administration 49 CFR Part 192 [Docket No. PHMSA–2005–22642; Notice 1] RIN 2137–AE09 Pipeline Safety: Design and Construction Standards To Reduce Internal Corrosion in Gas Transmission Pipelines Pipeline and Hazardous Materials Safety Administration (PHMSA), Department of Transportation. ACTION: Notice of proposed rulemaking. AGENCY: SUMMARY: This document proposes regulations on the control of internal corrosion when designing and constructing new and replaced gas transmission pipelines. The proposed rule would require an operator to take steps in design and construction to reduce the risk that liquids collecting within the pipeline could result in failures because of internal corrosion. These changes would ease steps an operator must take in operating and maintaining the pipeline to minimize internal corrosion. DATES: Anyone interested in filing written comments on the rule proposed in this document must do so by VerDate Aug<31>2005 14:18 Dec 14, 2005 Jkt 208001 February 13, 2006. PHMSA will consider late filed comments so far as practicable. Comments should reference Docket No. PHMSA–2005–22642 and may be submitted in the following ways: • DOT Web Site: https://dms.dot.gov. To submit comments on the DOT electronic docket site, click ‘‘Comment/ Submissions,’’ click ‘‘Continue,’’ fill in the requested information, click ‘‘Continue,’’ enter your comment, then click ‘‘Submit.’’ • Fax: 1–202–493–2251. • Mail: Docket Management System: U.S. Department of Transportation, 400 Seventh Street, SW., Nassif Building, Room PL–401, Washington, DC 20590– 0001. • Hand Delivery: DOT Docket Management System; Room PL–401 on the plaza level of the Nassif Building, 400 Seventh Street, SW., Washington, DC between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. • E-Gov Web Site: https:// www.Regulations.gov. This site allows the public to enter comments on any Federal Register notice issued by any agency. Instructions: You should identify the docket number, PHMSA–2005–22642, at the beginning of your comments. If you submit your comments by mail, you should submit two copies. If you wish to receive confirmation that PHMSA received your comments, you should include a self-addressed stamped postcard. Internet users may submit comments at https:// www.regulations.gov, and may access all comments received by DOT at https:// dms.dot.gov by performing a simple search for the docket number. Note: All comments will be posted without changes or edits to https://dms.dot.gov including any personal information provided. Please see the Privacy Act heading in the Regulatory Analyses and Notices section of the Supplemental Information. ADDRESSES: FOR FURTHER INFORMATION CONTACT: Barbara Betsock by phone at (202) 366– 4361 or by fax at (202) 366–4566, or by e-mail at barbara.betsock@dot.gov. SUPPLEMENTARY INFORMATION: Background Internal Corrosion Corrosion can occur on the interior wall of a steel pipeline when liquid gathers within the pipeline. Whether corrosion occurs in these circumstances depends on the nature and amount of contaminants inside the pipeline and the operating conditions of the pipeline. PO 00000 Frm 00048 Fmt 4702 Sfmt 4702 Current Regulations Current pipeline safety regulations found in 49 CFR part 192 require an operator to take actions to address internal corrosion in operating and maintaining a gas transmission pipeline. An operator must include the details of its corrosion program in procedural manuals and carry out the program. Among the actions that an operator must take to prevent corrosion are the use of inhibitors in the gas, the use of cleaning pigs, the removal of liquids and solids from drips, and monitoring the contaminants. When an operator discovers internal corrosion, an operator must take extra steps such as using coupons to check for corrosion to prevent internal corrosion-induced failure. Besides these operation and maintenance (O&M) requirements, an operator must design and construct pipe installed since 1994 to allow the passage of internal inspection tools, commonly known as ‘‘pigs’’. Therefore, all pipeline installed since 1994 allow the use of cleaning pigs. On December 15, 2003, we issued regulations on integrity management programs for gas transmission pipelines. These regulations are found at 68 FR 69816. Specifically, an operator must include within its integrity management program a means to discover whether internal corrosion impacts the integrity of its pipeline. The means may include internal inspection or hydrostatic testing. Where pipeline design does not allow the use of pigs, internal corrosion direct assessment (ICDA) is the likely choice. The operator must then address any corrosion found. To prepare for ICDA, an operator must evaluate whether the design and construction of the pipeline contributes to the risk of internal corrosion. These design and construction features include low points in which liquids may gather, such as sags, drips, inclines, valves, manifolds, dead-legs, and traps; elevation profile; and pipe diameter. An operator combines information about design and construction with O&M history such as places where cleaning pigs have not been used, patterns of gas quality, and the range of expected gas velocities. An operator uses this analysis to decide where to excavate and examine the line for internal corrosion. Reasons for Regulation Internal corrosion has been one of the three leading causes of reportable incidents in gas transmission pipelines for the past five years, both in percentage of incidents and their consequences. In fact, in 2003 and 2004, E:\FR\FM\15DEP1.SGM 15DEP1 Federal Register / Vol. 70, No. 240 / Thursday, December 15, 2005 / Proposed Rules internal corrosion caused more property damage than the other two most frequent causes, third-party excavation damage and external corrosion, combined. Specifically, internal corrosion caused $14.9 million in property damage in 2003 versus $11.9 million in damage attributable to external corrosion or third-party excavation damage. In 2004, internal corrosion caused $4.9 million in damage versus $4.0 million for the other two causes combined. There is an increasing demand for natural gas. As producers tap new sources, there is a possibility the nature and amount of contaminants in the gas will vary. To ensure safe and reliable delivery of gas, pipeline operators must be vigilant in preventing internal corrosion and monitoring its impact when it occurs. Early planning for corrosion control at the design and construction stage would simplify the O&M actions needed later for corrosion control. The integrity management regulations require added O&M steps to control internal corrosion. Designing and constructing pipelines with internal corrosion control in mind would ease integrity management assessments whether done by internal inspection or ICDA. Planning at the design and construction stage would also simplify actions needed to address internal corrosion during O&M. There are two industry standards for considering internal corrosion control during design and construction. These are the American Society of Mechanical Engineers (ASME) code for gas piping (ASME B31.8, Gas Transmission and Distribution Piping Systems) and the American Gas Association’s Guide for Gas Transmission and Distribution Piping Systems. These standards already provide guidance to operators. However, clear performance-based design and construction standards for internal corrosion control will aid operators in complying with the recent integrity management regulations as well as the existing O&M requirements. Finally, in its report on the gas transmission pipeline accident that occurred in 2000 near Carlsbad, New Mexico, the National Transportation Safety Board (NTSB) described physical features that promoted internal corrosion of the line. There were low points just upstream of where the pipeline crossed the Pecos River. The original construction of the line included a drip installed upstream of these low points to prevent liquid from gathering in the low points. At some point, the operator modified the line to allow the use of cleaning pigs upstream VerDate Aug<31>2005 14:18 Dec 14, 2005 Jkt 208001 of the Pecos River. The operator placed the equipment used to remove cleaning pigs at the valve upstream of the drip. The NTSB concluded residue clogged the drip allowing liquids to flow past the drip and settle in the low points at the river crossing. The NTSB investigation after the pipeline ruptured at the low points revealed severe internal corrosion at the site. The line where the cleaning pigs had been used upstream did not experience internal corrosion needing repair. Noting the lack of Federal design and construction standards aimed at internal corrosion, the NTSB recommended the Department change its regulations: Revise 49 Code of Federal Regulations part 192 to require that new or replaced pipelines be designed and constructed with features to mitigate internal corrosion. At a minimum, such pipelines should (1) be configured to reduce the opportunity for liquids to accumulate, (2) be equipped with effective liquid removal features, and (3) be able to accommodate corrosion monitoring devices at locations with the greatest potential for internal corrosion. (P–03–1). We agree there should be Federal standards to address internal corrosion at the design and construction stage. Statutory Considerations PHMSA has broad authority to issue safety standards on the design, construction, operation, replacement, and maintenance of gas transmission pipelines. This authority is in 49 U.S.C. 60102(a). Under 49 U.S.C. 60104, a design and construction standard may not apply to a pipeline existing when we issue the standard. Therefore, this proposal imposes design and construction requirements only on new and replaced pipe and components. The proposal does require an operator to evaluate the potential impact on existing pipelines by upstream changes made to the pipeline and take actions to address the impact. However, evaluating and addressing impacts is an O&M need rather than a design and construction standard. The statute allows PHMSA to regulate O&M for existing pipelines. Under 49 U.S.C. 60102(b), a gas pipeline safety standard must be practicable and designed to meet the need for gas pipeline safety and for protection of the environment. To do this, PHMSA must consider several factors in issuing a safety standard. These factors include the relevant available pipeline safety and environmental information, the appropriateness of the standard for the type of pipeline, the reasonableness of the standard, and reasonably identifiable or estimated costs and benefits. PHMSA has considered these PO 00000 Frm 00049 Fmt 4702 Sfmt 4702 74263 factors in developing this proposed rule and provides its analysis in the preamble. PHMSA must also consider any comments received from the public and any comments and recommendations of the Technical Pipeline Safety Standards Committee (Committee). The Committee discussed the ideas for this proposal following a briefing at its meeting on June 15, 2005. The transcript of, and briefing materials for, the meeting are in the DOT DMS Docket RSPA–98–4470. PHMSA considered the Committee discussion in developing this proposed rule. This document seeks public comment on the proposed rule; the Committee will formally consider it in a future meeting. PHMSA will address the public comments and the Committee’s recommendations when the agency prepares a final rule. The Proposed Rule The proposed rule would add a new section to subpart I—Requirements for Corrosion Control in 49 CFR part 192. The new section, § 192.476 would require an operator to address internal corrosion risk when designing and constructing gas transmission pipelines. Proposed paragraph (a) provides a performance test for internal corrosion prevention measures in design and construction. The test is whether the design and construction choices include measures to reduce the risk that liquid will collect inside the pipe. The proposed rule would require an operator to use measures that include, at the least, arrangement to avoid collection of liquids and the use of effective liquid removal equipment. If an operator is unable to avoid low spots, an operator would explain why and identify the alternative measures to reduce the risk. There may be cases in which the design avoids low spots, but during construction the operator finds that it cannot avoid low spots. In this case, the operator would document the ‘‘as built’’ condition and the alternative measures used. Proposed paragraph (b) provides a performance test for design and construction measures to check any internal corrosion that occurs. The test is whether the design and construction choices include measures to reduce the risk of internal corrosion. The design must allow for use of corrosion detection equipment. These design and construction requirements would apply to all new construction and to replaced pipe and components. With one limited exception, application to replaced pipe would be the same as the rule on designing to allow the passage of E:\FR\FM\15DEP1.SGM 15DEP1 74264 Federal Register / Vol. 70, No. 240 / Thursday, December 15, 2005 / Proposed Rules instrumented internal inspection tools. PHMSA clarified the meaning of replaced pipe in the final rule published in the Federal Register on June 28, 2004 (69 FR 36024). The exception occurs when replaced pipe changes the physical features of an existing downstream pipeline. Proposed paragraph (c) clarifies that an operator must consider the impact of line changes on internal corrosion risks and plan for these. Proposed paragraph (c) would not require an operator to rebuild the downstream pipeline to remove low points, but would require an operator to consider whether it should install liquid removal equipment or tools to monitor corrosion. After analysis, an operator may decide O&M measures would adequately address the impacts of the changes upstream. Paragraph (d) would require an operator to record the decisions it makes about internal corrosion control when designing and constructing pipelines. The operator would have to explain its reasons for the decisions and justify variance. For example, if an operator did not use equipment to remove liquids in designing a pipeline, the operator would have to explain why the use of the equipment would be impracticable. Recording reasons for decisions fosters better decisionmaking and will provide needed information about safety features of the line in the future. Regulatory Analyses and Notices Privacy Act Statement Anyone may search the electronic form of all comments received for any of our dockets. You may review DOT’s complete Privacy Act Statement in the Federal Register published on April 11, 2000 (65 FR19477) or you may visit https://dms.dot.gov. Executive Order 12866 and DOT Policies and Procedures This proposed rule is not a significant regulatory action under section 3(f) of Executive Order 12866 (58 FR 51735) and, therefore, was not subject to review by the Office of Management and Budget. This proposed rule is not significant under the Regulatory Policies and Procedures of the Department of Transportation (44 FR 11034). Regulatory Flexibility Act Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.), PHMSA must consider whether rulemaking actions would have a significant economic impact on a substantial number of small entities. This proposed rule would affect operators of gas transmission pipelines VerDate Aug<31>2005 14:18 Dec 14, 2005 Jkt 208001 and onshore gas gathering pipelines. There is not a substantial number of small entities which operate these lines. PHMSA expects the costs of compliance with the proposed rule would be small. PHMSA concludes that this proposed rule would not have a significant economic impact on any small entity. PHMSA invites public comment on the number of small entities this proposed rule would impact. Executive Order 13175 PHMSA has analyzed this proposed rulemaking according to Executive Order 13175, ‘‘Consultation and Coordination with Indian Tribal Governments.’’ Because the proposed rulemaking would 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 This proposed rule would affect information collection that OMB has approved under Control Numbers 2137– 0049 (recordkeeping under 49 CFR part 192). Operators of gas transmission pipelines must keep records to show the adequacy of corrosion control measures. In addition, they must keep construction records to make them available to individuals operating and maintaining the pipeline. The proposed rule may require some added effort to document decisions about internal corrosion made during design and construction. Because of existing recordkeeping needs and prudent business practice, PHMSA estimates the added burden hours will be nominal. PHMSA invites comments on this estimate. Unfunded Mandates Reform Act of 1995 This proposed 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 proposed rulemaking. National Environmental Policy Act PHMSA has analyzed the proposed rulemaking for purposes of the National Environmental Policy Act (42 U.S.C. 4321 et seq.). Because the proposed rulemaking would require limited physical change or other work that would disturb pipeline rights-of-way, PHMSA has preliminarily determined the proposed rulemaking is unlikely to PO 00000 Frm 00050 Fmt 4702 Sfmt 4702 affect the quality of the human environment significantly. An environmental assessment document is available for review in the docket. PHMSA will make a final determination on environmental impact after reviewing the comments to this proposal. Executive Order 13132 PHMSA has analyzed the proposed rulemaking according to Executive Order 13132 (‘‘Federalism’’). The proposed rule does not have a substantial direct effect 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. The proposed rule does not impose substantial direct compliance costs on State and local governments. The pipeline safety law prohibits State safety regulation of interstate pipelines. This proposed regulation would not preempt state law for intrastate pipelines. Therefore, the consultation and funding requirements of Executive Order 13132 do not apply. Executive Order 13211 Transporting gas impacts the nation’s available energy supply. However, this proposed rulemaking is not a ‘‘significant energy action’’ under Executive Order 13211. It also 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, the Administrator of the Office of Information and Regulatory Affairs has not identified this proposed rule as a significant energy action. List of Subjects in 49 CFR Part 192 Internal corrosion, design and construction, pipeline safety. For the reasons provided in the preamble, PHMSA proposes to amend 49 CFR Part 192 as follows: PART 192—TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: MINIMUM FEDERAL SAFETY STANDARDS 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. 2. Add § 192.476 to read as follows: § 192.476 Internal corrosion control: Design and construction. (a) Avoiding liquids. An operator must design and construct each new transmission line and each replacement E:\FR\FM\15DEP1.SGM 15DEP1 Federal Register / Vol. 70, No. 240 / Thursday, December 15, 2005 / Proposed Rules of line pipe, valve, fitting, or other line component in a transmission line to reduce the risk that liquids will collect in the line. At a minimum, unless an operator shows that it is impracticable or unnecessary to do so, an operator must: (1) Configure new pipeline or replacement of line pipe, valve, fitting, or other line component to reduce the risk that liquids will collect in the line; and (2) Equip the new pipeline or replacement pipe with effective liquid removal features. (b) Monitoring. An operator must design and construct each new transmission line and each replacement of line pipe, valve, fitting, or other line component in a transmission line to reduce the risk of internal corrosion. At a minimum, unless an operator shows that it is impracticable or unnecessary to do so, an operator must use pipeline design and construction that allows use of corrosion monitoring devices at locations with significant potential for internal corrosion. (c) Change to existing system. An operator must evaluate the impact that new or replaced line pipe, valve, fitting, or other line component may have on internal corrosion risk to the downstream portion of an existing pipeline and use equipment to remove liquids and to monitor corrosion as appropriate. (d) Records. An operator must document the design and construction decisions related to internal corrosion. Documentation must include the reasons, and any engineering analysis, for each decision. Issued in Washington, DC, on December 12, 2005. Stacey L. Gerard, Associate Administrator for Pipeline Safety. [FR Doc. 05–24063 Filed 12–12–05; 1:29 pm] BILLING CODE 4910–60–P DEPARTMENT OF TRANSPORTATION Pipeline and Hazardous Materials Safety Administration 49 CFR Parts 192 and 195 [Docket No. PHMSA–04–18938] RIN 2137–AE07 Integrity Management: Program Modifications and Clarifications— Request for Comments Pipeline and Hazardous Materials Safety Administration (PHMSA), DOT. ACTION: Notice of proposed rulemaking. AGENCY: VerDate Aug<31>2005 14:18 Dec 14, 2005 Jkt 208001 SUMMARY: PHMSA proposes revisions to the current Pipeline Safety Regulations for Pipeline Integrity Management in High Consequence Areas. The revisions address a petition from the hazardous liquid pipeline industry. The revisions are to: allow more flexibility in reassessment intervals for hazardous liquid pipelines by adding an eightmonth window to the five-year time frame for operators to complete reassessment; and require both hazardous liquid pipeline and gas transmission pipeline operators to notify PHMSA whenever they reduce pipeline pressure to make a repair and to provide reasons for pressure reduction. Another notification, including reasons for repair delay, would be required when a pressure reduction exceeds 365 days. Also, PHMSA proposes to correct existing provisions for calculating a pressure reduction when making an immediate repair on a hazardous liquid pipeline. The proposed correction would allow operators to use another acceptable method to calculate reduced operating pressure when a specified formula is not applicable or results in a calculated pressure higher than operating pressure. Finally, PHMSA seeks the submittal of engineering analyses and technical data. These submittals are to provide the basis for modifying the required time periods for remediating certain conditions found during a hazardous liquid pipeline integrity assessment. PHMSA will use this data to evaluate the scope and scale of repair issues to develop an accurate basis for determining if any additional flexibility is needed in the repair schedules. DATES: Interested persons may submit written comments on the proposed regulatory changes by February 13, 2006. Interested persons may submit written engineering analysis and technical data by April 14, 2006. Latefiled comments will be considered to the extent possible. ADDRESSES: Comments should reference Docket No. PHMSA–04–18938 and may be submitted in the following ways: • DOT Web site: https://dms.dot.gov. To submit comments on the DOT electronic docket site, click ‘‘Comment/ Submissions,’’ click ‘‘Continue,’’ fill in the requested information, click ‘‘Continue,’’ enter your comment, then click ‘‘Submit.’’ • Fax: 1–202–493–2251. • Mail: Docket Management System: U.S. Department of Transportation, 400 Seventh Street, SW., Nassif Building, Room PL–401, Washington, DC 20590– 0001. PO 00000 Frm 00051 Fmt 4702 Sfmt 4702 74265 • Hand Delivery: DOT Docket Management System, Room PL–401 on the plaza of the Nassif Building, 400 Seventh Street, SW., Washington, DC between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. • E-Gov Web site: https:// www.Regulations.gov. This site allows the public to enter comments on any Federal Register notice issued by any agency. Instructions: You should identify docket number PHMSA–04–18938 at the beginning of your comments. If you submit your comments by mail, you should send two copies. If you wish to receive PHMSA’s confirmation receipt of your comments, you should include a self-addressed stamped postcard. Internet users may submit comments at https://www.regulations.gov, and may access all comments received by DOT at https://dms.dot.gov by performing a simple search for the docket number. Note: All comments will be posted without changes or edits to https:// dms.dot.gov including any personal information provided. Please see the Privacy Act heading under Section V, Regulatory Analyses and Notices, of the SUPPLEMENTARY INFORMATION. Privacy Act Statement: Anyone may search the electronic form of all comments received for any of our dockets. You may review DOT’s complete Privacy Act Statement in the Federal Register published on April 11, 2000 (70 FR 19477) or you may visit https://dms.dot.gov. FOR FURTHER INFORMATION CONTACT: Shauna Turnbull by phone at (202) 366– 3731 or via e-mail at shauna.turnbull@dot.gov. For questions on technical issues, contact Mike Israni at (202) 366–4571 or via e-mail at mike.israni@dot.gov. SUPPLEMENTARY INFORMATION: I. Background Statutory and Regulatory Requirements The Nation’s existing pipeline infrastructure, much of which is over 50 years old, requires regular safety and environmental reviews to ensure its reliability. To address several statutory mandates and National Transportation Safety Board (NTSB) recommendations on actions to improve pipeline safety, PHMSA 1 issued Integrity Management 1 The former Research and Special Programs Administration (RSPA) was the entity responsible for issuing the hazardous liquid pipeline and gas transmission pipeline integrity management program regulations. RSPA divided into two new agencies on February 20, 2005. The newly formed PHMSA assumed responsibility for pipeline safety and hazardous materials management regulatory oversight. E:\FR\FM\15DEP1.SGM 15DEP1

Agencies

[Federal Register Volume 70, Number 240 (Thursday, December 15, 2005)]
[Proposed Rules]
[Pages 74262-74265]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 05-24063]


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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Part 192

[Docket No. PHMSA-2005-22642; Notice 1]
RIN 2137-AE09


Pipeline Safety: Design and Construction Standards To Reduce 
Internal Corrosion in Gas Transmission Pipelines

AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA), 
Department of Transportation.

ACTION: Notice of proposed rulemaking.

-----------------------------------------------------------------------

SUMMARY: This document proposes regulations on the control of internal 
corrosion when designing and constructing new and replaced gas 
transmission pipelines. The proposed rule would require an operator to 
take steps in design and construction to reduce the risk that liquids 
collecting within the pipeline could result in failures because of 
internal corrosion. These changes would ease steps an operator must 
take in operating and maintaining the pipeline to minimize internal 
corrosion.

DATES: Anyone interested in filing written comments on the rule 
proposed in this document must do so by February 13, 2006. PHMSA will 
consider late filed comments so far as practicable.

ADDRESSES: Comments should reference Docket No. PHMSA-2005-22642 and 
may be submitted in the following ways:
     DOT Web Site: https://dms.dot.gov. To submit comments on 
the DOT electronic docket site, click ``Comment/Submissions,'' click 
``Continue,'' fill in the requested information, click ``Continue,'' 
enter your comment, then click ``Submit.''
     Fax: 1-202-493-2251.
     Mail: Docket Management System: U.S. Department of 
Transportation, 400 Seventh Street, SW., Nassif Building, Room PL-401, 
Washington, DC 20590-0001.
     Hand Delivery: DOT Docket Management System; Room PL-401 
on the plaza level of the Nassif Building, 400 Seventh Street, SW., 
Washington, DC between 9 a.m. and 5 p.m., Monday through Friday, except 
Federal holidays.
     E-Gov Web Site: https://www.Regulations.gov. This site 
allows the public to enter comments on any Federal Register notice 
issued by any agency.
    Instructions: You should identify the docket number, PHMSA-2005-
22642, at the beginning of your comments. If you submit your comments 
by mail, you should submit two copies. If you wish to receive 
confirmation that PHMSA received your comments, you should include a 
self-addressed stamped postcard. Internet users may submit comments at 
https://www.regulations.gov, and may access all comments received by DOT 
at https://dms.dot.gov by performing a simple search for the docket 
number. Note: All comments will be posted without changes or edits to 
https://dms.dot.gov including any personal information provided. Please 
see the Privacy Act heading in the Regulatory Analyses and Notices 
section of the Supplemental Information.

FOR FURTHER INFORMATION CONTACT: Barbara Betsock by phone at (202) 366-
4361 or by fax at (202) 366-4566, or by e-mail at 
barbara.betsock@dot.gov.

SUPPLEMENTARY INFORMATION:

Background

Internal Corrosion

    Corrosion can occur on the interior wall of a steel pipeline when 
liquid gathers within the pipeline. Whether corrosion occurs in these 
circumstances depends on the nature and amount of contaminants inside 
the pipeline and the operating conditions of the pipeline.

Current Regulations

    Current pipeline safety regulations found in 49 CFR part 192 
require an operator to take actions to address internal corrosion in 
operating and maintaining a gas transmission pipeline. An operator must 
include the details of its corrosion program in procedural manuals and 
carry out the program. Among the actions that an operator must take to 
prevent corrosion are the use of inhibitors in the gas, the use of 
cleaning pigs, the removal of liquids and solids from drips, and 
monitoring the contaminants. When an operator discovers internal 
corrosion, an operator must take extra steps such as using coupons to 
check for corrosion to prevent internal corrosion-induced failure. 
Besides these operation and maintenance (O&M) requirements, an operator 
must design and construct pipe installed since 1994 to allow the 
passage of internal inspection tools, commonly known as ``pigs''. 
Therefore, all pipeline installed since 1994 allow the use of cleaning 
pigs.
    On December 15, 2003, we issued regulations on integrity management 
programs for gas transmission pipelines. These regulations are found at 
68 FR 69816. Specifically, an operator must include within its 
integrity management program a means to discover whether internal 
corrosion impacts the integrity of its pipeline. The means may include 
internal inspection or hydrostatic testing. Where pipeline design does 
not allow the use of pigs, internal corrosion direct assessment (ICDA) 
is the likely choice. The operator must then address any corrosion 
found.
    To prepare for ICDA, an operator must evaluate whether the design 
and construction of the pipeline contributes to the risk of internal 
corrosion. These design and construction features include low points in 
which liquids may gather, such as sags, drips, inclines, valves, 
manifolds, dead-legs, and traps; elevation profile; and pipe diameter. 
An operator combines information about design and construction with O&M 
history such as places where cleaning pigs have not been used, patterns 
of gas quality, and the range of expected gas velocities. An operator 
uses this analysis to decide where to excavate and examine the line for 
internal corrosion.

Reasons for Regulation

    Internal corrosion has been one of the three leading causes of 
reportable incidents in gas transmission pipelines for the past five 
years, both in percentage of incidents and their consequences. In fact, 
in 2003 and 2004,

[[Page 74263]]

internal corrosion caused more property damage than the other two most 
frequent causes, third-party excavation damage and external corrosion, 
combined. Specifically, internal corrosion caused $14.9 million in 
property damage in 2003 versus $11.9 million in damage attributable to 
external corrosion or third-party excavation damage. In 2004, internal 
corrosion caused $4.9 million in damage versus $4.0 million for the 
other two causes combined.
    There is an increasing demand for natural gas. As producers tap new 
sources, there is a possibility the nature and amount of contaminants 
in the gas will vary. To ensure safe and reliable delivery of gas, 
pipeline operators must be vigilant in preventing internal corrosion 
and monitoring its impact when it occurs. Early planning for corrosion 
control at the design and construction stage would simplify the O&M 
actions needed later for corrosion control.
    The integrity management regulations require added O&M steps to 
control internal corrosion. Designing and constructing pipelines with 
internal corrosion control in mind would ease integrity management 
assessments whether done by internal inspection or ICDA. Planning at 
the design and construction stage would also simplify actions needed to 
address internal corrosion during O&M. There are two industry standards 
for considering internal corrosion control during design and 
construction. These are the American Society of Mechanical Engineers 
(ASME) code for gas piping (ASME B31.8, Gas Transmission and 
Distribution Piping Systems) and the American Gas Association's Guide 
for Gas Transmission and Distribution Piping Systems. These standards 
already provide guidance to operators. However, clear performance-based 
design and construction standards for internal corrosion control will 
aid operators in complying with the recent integrity management 
regulations as well as the existing O&M requirements.
    Finally, in its report on the gas transmission pipeline accident 
that occurred in 2000 near Carlsbad, New Mexico, the National 
Transportation Safety Board (NTSB) described physical features that 
promoted internal corrosion of the line. There were low points just 
upstream of where the pipeline crossed the Pecos River. The original 
construction of the line included a drip installed upstream of these 
low points to prevent liquid from gathering in the low points. At some 
point, the operator modified the line to allow the use of cleaning pigs 
upstream of the Pecos River. The operator placed the equipment used to 
remove cleaning pigs at the valve upstream of the drip. The NTSB 
concluded residue clogged the drip allowing liquids to flow past the 
drip and settle in the low points at the river crossing. The NTSB 
investigation after the pipeline ruptured at the low points revealed 
severe internal corrosion at the site. The line where the cleaning pigs 
had been used upstream did not experience internal corrosion needing 
repair. Noting the lack of Federal design and construction standards 
aimed at internal corrosion, the NTSB recommended the Department change 
its regulations:

    Revise 49 Code of Federal Regulations part 192 to require that 
new or replaced pipelines be designed and constructed with features 
to mitigate internal corrosion. At a minimum, such pipelines should 
(1) be configured to reduce the opportunity for liquids to 
accumulate, (2) be equipped with effective liquid removal features, 
and (3) be able to accommodate corrosion monitoring devices at 
locations with the greatest potential for internal corrosion. (P-03-
1).

    We agree there should be Federal standards to address internal 
corrosion at the design and construction stage.

Statutory Considerations

    PHMSA has broad authority to issue safety standards on the design, 
construction, operation, replacement, and maintenance of gas 
transmission pipelines. This authority is in 49 U.S.C. 60102(a). Under 
49 U.S.C. 60104, a design and construction standard may not apply to a 
pipeline existing when we issue the standard. Therefore, this proposal 
imposes design and construction requirements only on new and replaced 
pipe and components. The proposal does require an operator to evaluate 
the potential impact on existing pipelines by upstream changes made to 
the pipeline and take actions to address the impact. However, 
evaluating and addressing impacts is an O&M need rather than a design 
and construction standard. The statute allows PHMSA to regulate O&M for 
existing pipelines.
    Under 49 U.S.C. 60102(b), a gas pipeline safety standard must be 
practicable and designed to meet the need for gas pipeline safety and 
for protection of the environment. To do this, PHMSA must consider 
several factors in issuing a safety standard. These factors include the 
relevant available pipeline safety and environmental information, the 
appropriateness of the standard for the type of pipeline, the 
reasonableness of the standard, and reasonably identifiable or 
estimated costs and benefits. PHMSA has considered these factors in 
developing this proposed rule and provides its analysis in the 
preamble. PHMSA must also consider any comments received from the 
public and any comments and recommendations of the Technical Pipeline 
Safety Standards Committee (Committee). The Committee discussed the 
ideas for this proposal following a briefing at its meeting on June 15, 
2005. The transcript of, and briefing materials for, the meeting are in 
the DOT DMS Docket RSPA-98-4470. PHMSA considered the Committee 
discussion in developing this proposed rule. This document seeks public 
comment on the proposed rule; the Committee will formally consider it 
in a future meeting. PHMSA will address the public comments and the 
Committee's recommendations when the agency prepares a final rule.

The Proposed Rule

    The proposed rule would add a new section to subpart I--
Requirements for Corrosion Control in 49 CFR part 192. The new section, 
Sec.  192.476 would require an operator to address internal corrosion 
risk when designing and constructing gas transmission pipelines.
    Proposed paragraph (a) provides a performance test for internal 
corrosion prevention measures in design and construction. The test is 
whether the design and construction choices include measures to reduce 
the risk that liquid will collect inside the pipe. The proposed rule 
would require an operator to use measures that include, at the least, 
arrangement to avoid collection of liquids and the use of effective 
liquid removal equipment. If an operator is unable to avoid low spots, 
an operator would explain why and identify the alternative measures to 
reduce the risk. There may be cases in which the design avoids low 
spots, but during construction the operator finds that it cannot avoid 
low spots. In this case, the operator would document the ``as built'' 
condition and the alternative measures used.
    Proposed paragraph (b) provides a performance test for design and 
construction measures to check any internal corrosion that occurs. The 
test is whether the design and construction choices include measures to 
reduce the risk of internal corrosion. The design must allow for use of 
corrosion detection equipment.
    These design and construction requirements would apply to all new 
construction and to replaced pipe and components. With one limited 
exception, application to replaced pipe would be the same as the rule 
on designing to allow the passage of

[[Page 74264]]

instrumented internal inspection tools. PHMSA clarified the meaning of 
replaced pipe in the final rule published in the Federal Register on 
June 28, 2004 (69 FR 36024). The exception occurs when replaced pipe 
changes the physical features of an existing downstream pipeline. 
Proposed paragraph (c) clarifies that an operator must consider the 
impact of line changes on internal corrosion risks and plan for these. 
Proposed paragraph (c) would not require an operator to rebuild the 
downstream pipeline to remove low points, but would require an operator 
to consider whether it should install liquid removal equipment or tools 
to monitor corrosion. After analysis, an operator may decide O&M 
measures would adequately address the impacts of the changes upstream.
    Paragraph (d) would require an operator to record the decisions it 
makes about internal corrosion control when designing and constructing 
pipelines. The operator would have to explain its reasons for the 
decisions and justify variance. For example, if an operator did not use 
equipment to remove liquids in designing a pipeline, the operator would 
have to explain why the use of the equipment would be impracticable. 
Recording reasons for decisions fosters better decisionmaking and will 
provide needed information about safety features of the line in the 
future.

Regulatory Analyses and Notices

Privacy Act Statement

    Anyone may search the electronic form of all comments received for 
any of our dockets. You may review DOT's complete Privacy Act Statement 
in the Federal Register published on April 11, 2000 (65 FR19477) or you 
may visit https://dms.dot.gov.

Executive Order 12866 and DOT Policies and Procedures

    This proposed rule is not a significant regulatory action under 
section 3(f) of Executive Order 12866 (58 FR 51735) and, therefore, was 
not subject to review by the Office of Management and Budget. This 
proposed rule is not significant under the Regulatory Policies and 
Procedures of the Department of Transportation (44 FR 11034).

Regulatory Flexibility Act

    Under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.), PHMSA 
must consider whether rulemaking actions would have a significant 
economic impact on a substantial number of small entities. This 
proposed rule would affect operators of gas transmission pipelines and 
onshore gas gathering pipelines. There is not a substantial number of 
small entities which operate these lines. PHMSA expects the costs of 
compliance with the proposed rule would be small. PHMSA concludes that 
this proposed rule would not have a significant economic impact on any 
small entity.
    PHMSA invites public comment on the number of small entities this 
proposed rule would impact.

Executive Order 13175

    PHMSA has analyzed this proposed rulemaking according to Executive 
Order 13175, ``Consultation and Coordination with Indian Tribal 
Governments.'' Because the proposed rulemaking would 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

    This proposed rule would affect information collection that OMB has 
approved under Control Numbers 2137-0049 (recordkeeping under 49 CFR 
part 192). Operators of gas transmission pipelines must keep records to 
show the adequacy of corrosion control measures. In addition, they must 
keep construction records to make them available to individuals 
operating and maintaining the pipeline. The proposed rule may require 
some added effort to document decisions about internal corrosion made 
during design and construction. Because of existing recordkeeping needs 
and prudent business practice, PHMSA estimates the added burden hours 
will be nominal. PHMSA invites comments on this estimate.

Unfunded Mandates Reform Act of 1995

    This proposed 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 proposed rulemaking.

National Environmental Policy Act

    PHMSA has analyzed the proposed rulemaking for purposes of the 
National Environmental Policy Act (42 U.S.C. 4321 et seq.). Because the 
proposed rulemaking would require limited physical change or other work 
that would disturb pipeline rights-of-way, PHMSA has preliminarily 
determined the proposed rulemaking is unlikely to affect the quality of 
the human environment significantly. An environmental assessment 
document is available for review in the docket. PHMSA will make a final 
determination on environmental impact after reviewing the comments to 
this proposal.

Executive Order 13132

    PHMSA has analyzed the proposed rulemaking according to Executive 
Order 13132 (``Federalism''). The proposed rule does not have a 
substantial direct effect 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. The proposed 
rule does not impose substantial direct compliance costs on State and 
local governments. The pipeline safety law prohibits State safety 
regulation of interstate pipelines. This proposed regulation would not 
preempt state law for intrastate pipelines. Therefore, the consultation 
and funding requirements of Executive Order 13132 do not apply.

Executive Order 13211

    Transporting gas impacts the nation's available energy supply. 
However, this proposed rulemaking is not a ``significant energy 
action'' under Executive Order 13211. It also 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, the Administrator of the Office of Information and 
Regulatory Affairs has not identified this proposed rule as a 
significant energy action.

List of Subjects in 49 CFR Part 192

    Internal corrosion, design and construction, pipeline safety.

    For the reasons provided in the preamble, PHMSA proposes to amend 
49 CFR Part 192 as follows:

PART 192--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: 
MINIMUM FEDERAL SAFETY STANDARDS

    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.

    2. Add Sec.  192.476 to read as follows:


Sec.  192.476  Internal corrosion control: Design and construction.

    (a) Avoiding liquids. An operator must design and construct each 
new transmission line and each replacement

[[Page 74265]]

of line pipe, valve, fitting, or other line component in a transmission 
line to reduce the risk that liquids will collect in the line. At a 
minimum, unless an operator shows that it is impracticable or 
unnecessary to do so, an operator must:
    (1) Configure new pipeline or replacement of line pipe, valve, 
fitting, or other line component to reduce the risk that liquids will 
collect in the line; and
    (2) Equip the new pipeline or replacement pipe with effective 
liquid removal features.
    (b) Monitoring. An operator must design and construct each new 
transmission line and each replacement of line pipe, valve, fitting, or 
other line component in a transmission line to reduce the risk of 
internal corrosion. At a minimum, unless an operator shows that it is 
impracticable or unnecessary to do so, an operator must use pipeline 
design and construction that allows use of corrosion monitoring devices 
at locations with significant potential for internal corrosion.
    (c) Change to existing system. An operator must evaluate the impact 
that new or replaced line pipe, valve, fitting, or other line component 
may have on internal corrosion risk to the downstream portion of an 
existing pipeline and use equipment to remove liquids and to monitor 
corrosion as appropriate.
    (d) Records. An operator must document the design and construction 
decisions related to internal corrosion. Documentation must include the 
reasons, and any engineering analysis, for each decision.

    Issued in Washington, DC, on December 12, 2005.
Stacey L. Gerard,
Associate Administrator for Pipeline Safety.
[FR Doc. 05-24063 Filed 12-12-05; 1:29 pm]
BILLING CODE 4910-60-P