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Pipeline and Hazardous Materials Safety Administration (PHMSA), DOT.
This action modifies the integrity management regulations for hazardous liquid and natural gas transmission pipelines. The modifications include adding an eight-month window to the period for reassessing hazardous liquid pipelines; modifying notification requirements for operators of hazardous liquid and natural gas pipelines; repealing a requirement for gas operators to notify local authorities; and allowing alternatives in calculating pressure reduction when making an immediate repair on a hazardous liquid pipeline. This action is intended to improve pipeline safety by clarifying the integrity management regulations and providing operators with increased flexibility in implementing their integrity management (IM) programs.
This rule is effective August 16, 2007.Start Further Info
FOR FURTHER INFORMATION CONTACT:
Mike Israni by phone at (202) 366-4571 or by e-mail at firstname.lastname@example.org.End Further Info End Preamble Start Supplemental Information
Statutory and Regulatory Requirements
PHMSA is the Federal regulatory agency responsible for promoting the safe, reliable, and environmentally sound operation of over two million miles of natural gas and hazardous liquid pipelines in the United States. PHMSA has broad authority under 49 U.S.C. 60102 to issue regulations establishing standards for pipeline facility design, installation, inspection, emergency planning and response, testing, construction, extension, operation, replacement, and maintenance. By law, PHMSA pipeline safety standards must be both practicable and designed to meet the need for environmental safety and protection, taking account of specified criteria (49 U.S.C. 60102(b)(1-2)). Our rulemaking actions are reviewed by one or both of two statutorily-mandated advisory committees—the Technical Pipeline Safety Standards Committee, and the Technical Hazardous Liquid Pipeline Safety Standards Committee—which provide peer review of all proposed pipeline safety rules to assure technical feasibility, reasonableness, cost-effectiveness, and practicability.
Integrity Management Program
Since 2000, PHMSA has issued IM requirements for pipeline operators. PHMSA's pipeline IM regulations require operators of hazardous liquid and gas transmission pipelines to assess, evaluate, repair, and validate through comprehensive analyses the integrity of pipeline segments in areas where a leak or failure would do the most damage. These areas are referred to as “High Consequence Areas” and include populated, unusually sensitive environmental areas, and other areas defined by the IM regulations.
On December 1, 2000, PHMSA issued IM program regulations at 49 CFR 195.452 for operators with more than 500 miles of hazardous liquid pipeline (65 FR 75378). On January 14, 2002, PHMSA issued IM program repair criteria (67 FR 1650). On January 16, 2002, the IM program regulations were extended to operators with less than 500 miles of hazardous liquid pipeline (67 FR 2136). On December 15, 2003, PHMSA issued IM program regulations for gas transmission pipelines at 49 CFR Part 192, Subpart O (68 FR 69778).
Petition for Rulemaking
The American Petroleum Institute (API) and the Association of Oil Pipelines (AOPL) represent members who operate more than 85 percent of the U.S hazardous liquid infrastructure. On June 18, 2004, API and AOPL jointly submitted a petition for rulemaking seeking changes to the hazardous liquid pipeline IM regulations.
API and AOPL requested the rule changes to benefit pipeline safety and provide operators additional flexibility in the following three areas: Adding flexibility to reassessment intervals; adding flexibility to scheduling repairs, and providing for notification to PHMSA when an operator is unable to make a repair because of permitting or other problems.
An important concept in IM is that an operator's program is to evolve into a more detailed and comprehensive program as the operator gains information about its pipeline system. An operator is required to continually improve its IM program. Similarly, as Start Printed Page 39013PHMSA gains experience in enforcing the IM regulations, we see ways that the regulations can be clarified and improved. Based on our experience and the operators' experience with IM, PHMSA considers how the IM regulations can be improved to benefit public safety and provide operators the flexibility they need in carrying out effective IM programs.
PHMSA published a notice of proposed rulemaking (NPRM) on December 15, 2005 (70 FR 74265), proposing to revise its pipeline IM regulations to address the API and AOPL petition to improve the IM regulations and to get additional information about reasons for repair delays. In the NPRM, PHMSA proposed four revisions. First, we proposed to allow more flexibility in the integrity reassessment intervals for hazardous liquid pipelines by adding an eight-month window to the five-year time frame for operators to complete reassessments. Second, we proposed to require hazardous liquid pipeline and gas transmission pipeline operators to notify us of repair-related reductions in operating pressure. The proposal would require operators to notify us whenever they reduce pipeline pressure to make a repair, to provide reasons for any pressure reduction, and to provide further notice and explanation when a pressure reduction exceeds 365 days. Third, we proposed to repeal as unnecessary an existing regulation requiring gas operators to provide notice of pressure reductions to local authorities. Lastly, PHMSA proposed to amend an existing provision for calculating a pressure reduction when making an immediate repair on a hazardous liquid pipeline. The proposal would allow use of an alternative method to calculate reduced operating pressure when the prescribed formula is not applicable or results in a calculated pressure higher than the operating pressure.
II. Disposition of NPRM Comments
PHMSA received comments from 12 parties: API and AOPL; the American Gas Association; Texas Pipeline Association; Kinder Morgan Energy Partners, L.P.; Southwest Gas Corporation; Paiute Pipeline Company; Orange and Rockland Utilities, Inc.; Duke Energy Gas Transmission Corporation; Magellan Midstream Partners, L.P.; Panhandle Energy; Puget Sound Energy; and Enbridge Energy Company, Inc.—Liquids Transportation Segment.
(1) Flexibility in Reassessment Intervals
Current regulations require hazardous liquid pipeline operators to set up intervals not to exceed five years for continually assessing pipeline integrity (§ 195.452(j)(3)). The NPRM proposed adding an eight-month window to the five-year time frame for operators to complete reassessments.
Comment: No commenter opposed this proposal. Commenters supported the proposed revision, stating they would benefit from flexibility to allow for unforeseeable events that could affect intervals. Commenters asserted added flexibility would not materially affect pipeline safety. They noted that adding the proposed window to the prescribed reassessment interval would comport with similar latitude provided in other periodic intervals under the pipeline safety regulations (e.g., for patrolling). One commenter suggested PHMSA develop an approach for extending reassessment intervals based on sound engineering, technical studies, and IM principles. Commenters also recognized operators may establish shorter reassessment intervals as a result of risk prioritization.
A commenter also requested that PHMSA extend similar flexibility to gas transmission pipeline operators, maintaining that the current reassessment time frames on gas transmission pipelines do not have a technical basis. The commenter offered RSTRENG, a means of predicting the effects of metal loss on the remaining strength of the corroded pipe, and other industry-accepted methods as alternatives that could be useful in setting reassessment time frames on gas transmission pipelines.
PHMSA Response: Adding an eight-month window to the hazardous liquid pipeline five-year reassessment interval in § 195.452(j)(3) gives operators flexibility in scheduling and completing reassessments without compromising pipeline safety. Operators must allow time in their schedules for unforeseen problems or contingencies that could delay assessments. In practice, operators must thus schedule their assessments on intervals of less than five years in order to assure compliance with a five-year regulatory requirement. This was never PHMSA's intent. This final rule maintains a nominal five-year interval while recognizing that unexpected contingencies can arise. This change is consistent with other pipeline safety regulations specifying compliance intervals.
PHMSA agrees that reassessment intervals should be adjusted over time based on engineering, technical studies, and integrity management principles. At this point, we do not have sufficient scientific and technical data to support modifying the five-year interval in regulation.
Nevertheless, section § 195.452(j)(4) of the IM regulations allows hazardous liquid operators to seek a variance from the five-year interval for particular pipeline facilities based on engineering data or if needed technology is not available. In these instances, operators notify PHMSA and provide scientific and technical justifications and alternate intervals for variation requests. PHMSA (and States where pipelines are under State jurisdiction) reviews the documentation to ensure sufficient justification has been provided for the proposed interval. This approach has been adequate to cover situations in which longer intervals are needed.
Both PHMSA and the U.S. General Accountability Office have testified that assessment intervals for natural gas transmission pipelines should be established based on technical data, risk factors, and engineering analyses. However, making those changes to the gas IM regulations in this action is outside the scope of the NPRM.
(2) Scheduling Repairs
In the NPRM, PHMSA requested submission of data and comments on operators' experience with identification of defect characteristics needing short-term (60 and 180-day) remediation. The NPRM allowed a longer period to submit these analyses, and API and AOPL responded to this request by submitting engineering analysis produced by Kiefner and Associates, Inc. on April 13, 2006. This analysis required detailed technical review.
PHMSA contracted with Oak Ridge National Laboratory to review the API/AOPL analysis. The Oak Ridge review documented which of the proposed changes in the API analysis could lead to improvements in safety and which could lead to reduced safety. It attempted neither to evaluate the significance to safety of each proposed change, nor to describe the composite impact on safety of the group of proposed changes. The Oak Ridge review did identify the technical factors that a comprehensive evaluation of the proposed changes should consider. PHMSA is currently evaluating operator treatment of many of these factors in ongoing IMP inspections.
DOT's Inspector General issued an audit in September 2006 addressing, among other issues, uncertainties in the characterization of defects using in-line inspection (ILI). Although uncertainties, Start Printed Page 39014both modest under-sizing and over-sizing of defects, in ILI readings are a fact of life, improvements in technology are continuing to reduce these uncertainties. ILI vendors and pipeline operators must account for potential inaccuracies in tool indications in their evaluation of ILI results. PHMSA inspections are evaluating approaches being used by operators to assure prudent decisions are made in the light of these uncertainties. The PHMSA inspection approach has been evaluated by the IG, and the issue closed satisfactorily. PHMSA is collecting additional data to better characterize the extent to which ILI has mischaracterized actual pipeline defects. PHMSA's ongoing inspection process is providing the necessary assurance that operators are addressing in a responsible way the impact of various sources of uncertainty on key decisions, including whether to excavate, timing of repairs, and timing of reassessment interval PHMSA will address potential changes to repair schedules in a future rulemaking action.
(3) Notification of Special Circumstances—Pressure Reduction
Both the hazardous liquid (§ 195.452(h)) and gas transmission (§ 192.933) pipeline IM remediation criteria require operators to reduce pressure or to shut down the pipeline until they can remediate all anomalous conditions. The IM regulations do not require notification when an operator reduces pressure unless the operator cannot meet its schedule for evaluating and remediating conditions and cannot provide safety through a temporary decrease in operating pressure. If a pressure reduction exceeds 365 days, a gas transmission pipeline operator must provide technical justification that the continued pressure reduction will not jeopardize the pipeline's integrity, and a hazardous liquid pipeline operator must take further remedial action to ensure the safety of the pipeline.
PHMSA proposed amending its regulations to require an operator of a gas transmission or hazardous liquid pipeline to notify PHMSA when it reduces pressure on an IM program segment (to remediate a defect), and to provide a justification for the pressure reduction. If a repair was not completed within 365 days, the operator would again be required to notify PHMSA and provide an explanation for the delay. PHMSA intended the proposed notification to provide better information on what causes schedule delays (permitting, scheduling, other); and where and under what circumstances PHMSA would be in a position to help streamline the permit process.
For gas transmission pipeline operators, PHMSA proposed repealing the requirement for notification of local pipeline safety authorities. PHMSA is not aware of any instance where an intrastate gas transmission pipeline is regulated by a local, rather than a State or Federal, authority.
Comment: The commenters supported efforts to better understand repair delays and supported efforts to improve pipeline IM. Nevertheless, the commenters opposed the notifications as proposed, stating that PHMSA needs to provide a clear statement of issues, analysis of possible solutions, and the expected costs and benefits of such a regulatory solution. Commenters contended the proposed notifications would impose a significant, undue, and problematic administrative burden on industry. Commenters said many discretionary pressure reductions are part of voluntary, normal, and circumstantial events unrelated to remediation scheduling requirements.
Some commenters recommended a demonstration project and suggested PHMSA collect and review the proposed notification data over a two-year period before making a final determination on the need for continued notification. Commenters also suggested collecting the information through annual reporting for any case where operators could not meet the remediation schedule requirements of § 195.452(h).
Other commenters suggested pressure reduction notifications should apply where remediation requirements cannot be met due to circumstances beyond the operator's control, when events impact energy supply, or when the operator cannot meet the remediation time limits and the pressure reduction exceeds 365 days. Notifications in these situations would provide PHMSA with more information on conditions interfering with repair attempts and help PHMSA recognize patterns potentially affecting pipeline safety.
Commenters also requested PHMSA clarify that the notifications requested are for pressure reductions related to IM remediation and not for other situations, such as pressure reductions done as safety precautions.
PHMSA Response: After analyzing the comments, PHMSA agrees that adding a requirement to notify PHMSA (and States, when applicable) of every pressure reduction would add a significant burden and likely would not result in commensurate useful information. Temporary pressure reductions add extra safety margin and serve to mitigate the safety impacts of repair delays, making early notifications unnecessary. PHMSA believes the current notification requirements address most cases where, for safety reasons, notification is important—those instances when an operator is unable to make repairs within the required time frames and cannot provide safety through pressure reductions. Thus, this existing notification requirement will remain unchanged.
In addition to the existing requirement, PHMSA has added a requirement for notification when a pressure reduction exceeds 365 days. PHMSA believes that notification of extended delay, with justification for the pressure reduction, will provide important information on conditions interfering with the operator's ability to complete defect remediation without placing an undue burden on the operator. This notification will enable PHMSA to intervene if necessary in order to facilitate needed repairs (e.g., by assisting in resolving permitting delays) and to evaluate the necessity for additional safety measures until remediation can be completed.
PHMSA expects that greater understanding of the causes of repair delays will help identify where extra actions can help. We are particularly interested in whether any delays are due to permitting problems. We also agree that periodic information collection, as part of the annual report, would reduce the paperwork burden without compromising safety. In the future, PHMSA will consider revising requirements for annual reports to include the number of times repairs required by IM regulations are delayed, beyond required repair times, because of permitting issues.
PHMSA has clarified that the notification requirements apply to certain pressure reductions made for purposes of IM remediation requirements. We have also modified the wording in §§ 192.933(c) and 195.452(h)(3) to make it clearer and consistent with wording in the IM notification requirements. There is no change in the requirement. With the revised wording, this section will now require an operator to explain why it cannot meet its schedule for evaluation and remediation of a condition and that the changed schedule will not jeopardize public safety (gas transmission) or public safety or environmental protection (hazardous liquid).
We received favorable comments on the proposal to eliminate the notification provisions for local pipeline safety authorities. Accordingly, we are Start Printed Page 39015repealing this requirement as proposed. For gas transmission pipeline operators, State notification requirements will continue for intrastate pipelines regulated by that State or for interstate gas transmission pipelines in States where PHMSA has an interstate agent agreement.
(4) Formula for Reducing Operating Pressure
Section 195.452(h)(4) requires a hazardous liquid pipeline operator to calculate a temporary reduction in operating pressure using the formula in section 451.7 of ASME/ANSI B 31.4 when making an immediate repair. The requirement is to ensure an extra safety margin. However, this formula only applies to metal loss anomalies, not to all immediate repair conditions, and can result in a calculated pressure higher than the original operating pressure.
PHMSA proposed revising the provision by allowing hazardous liquid pipeline operators to use the ASME/ANSI B 31.4 formula, if applicable. If not applicable to the anomaly, or if the formula results in a calculated pressure higher than the original operating pressure, operators could use an alternative acceptable method to calculate pressure reductions.
Comment: Commenters supported PHMSA's proposal to allow operators to use alternative methods to address anomalies and pipeline operating conditions. No commenter opposed the proposal.
PHMSA Response: We are adopting the proposal with minor wording changes. This final rule provides flexibility in methods an operator may use to calculate a pressure reduction when making immediate repairs on a hazardous liquid pipeline.
III. Advisory Committee Recommendations
The amendments adopted in this final rule have been reviewed and approved by both of our pipeline safety standards advisory committees, the Technical Pipeline Safety Standards Committee, and the Technical Hazardous Liquid Pipeline Safety Standards Committee. On June 28, 2006, PHMSA held a joint meeting of the Committees and two concurrent public workshops in Alexandria, VA. PHMSA presented the proposed changes to the committees for a vote. Following a brief discussion, the committee members unanimously carried a motion to accept the rule changes.
IV. Regulatory Analyses and Notices
A. Privacy Act
Anyone can search the electronic form of all comments received in response to any of our dockets by the name of the individual submitting the comment (or signing the comment, if submitted on behalf of an association, business, labor union, etc.). DOT's complete Privacy Act Statement was published in the Federal Register on April 11, 2000 (65 FR 19477) and is available on the Web at http://dms.dot.gov.
B. Executive Order 12866 and DOT Regulatory Policies and Procedures
This final rule is not considered a significant regulatory action under section 3(f) of Executive Order 12866 (58 FR 51735; Oct. 4, 1993) or the Regulatory Policies and Procedures of the Department of Transportation (44 FR 11034; Feb. 26, 1979). A final regulatory evaluation is in the docket for this rulemaking.
The rule's provision concerning scheduling continued integrity assessments will yield benefits in the form of additional flexibility, and will have no cost effects. PHMSA believes the change to the notification requirement for pressure reductions exceeding 365 days will add minimally to the annual average cost to each operator, and to the number of operators affected. PHMSA expects the benefits will offset costs. Together, PHMSA expects these changes to IM regulations for hazardous liquid and gas transmission pipelines to create positive net benefits.
C. Regulatory Flexibility Act and Executive Order 13272
The Regulatory Flexibility Act (5 U.S.C. 601-611) requires agencies to review each new regulation and assess its impact on small businesses and other small entities to determine whether the final rule will have a significant impact on a substantial number of small entities. This rule imposes minimal new costs of compliance on the regulated community. The requirements do not apply to a substantial number of small entities. The revisions to the IM rules will affect hazardous liquid pipeline operators and gas transmission pipeline operators. PHMSA expects notification costs per operator to be significantly less than $3.04 annually, a non-significant burden on any pipeline operator, large or small. The changes to add scheduling flexibility to the integrity reassessments will create positive benefits and impose minimal additional costs. The changed notification requirements for pressure reductions exceeding 365 days will also create benefits, and negligible added costs. Together, PHMSA expects these changes to the IM regulations for hazardous liquid and gas transmission pipelines to create positive net benefits to the affected industry. Based on the cost benefit analysis the regulatory changes will not have a significant impact on a substantial number of small entities.
PHMSA developed this final rule in accordance with Executive Order 13272 (“Proper Consideration of Small Entities in Agency Rulemaking”) and DOT's procedures and policies to promote compliance with the Regulatory Flexibility Act to ensure that the potential impact of rules on small entities are properly considered. The Small Business Administration's small business definition is either $6 million in revenue (for natural gas pipelines under North American Industry Classification System (NAICS) 486210) or 1,500 employees (for crude oil and refined petroleum product pipelines under NAICS 486110 and 486910). Based on a review of data collected from the hazardous liquid pipeline industry, PHMSA estimates there are 10-20 small entities. PHMSA does not have an estimate of the number of gas transmission pipeline operators that meet the small business definition. Information collection determining pipeline operator staffing or revenue would require separate Office of Management and Budget (OMB) approval. However, as stated above, compliance with this regulation requires a trivial expenditure and imposes a minimal burden on small businesses.
I certify this final rule would not have a significant economic impact on a substantial number of small entities. The costs associated with this final rule will be offset with benefits such as increased flexibility for operators. The changed notification requirements for pressure reductions exceeding 365 days would create benefits and negligible added costs.
PHMSA analyzed this rule under the principles and criteria contained in Executive Order 13132 (Federalism). None of the changes in this final rule: (1) Have a substantial direct effect on States, relationships between the Federal government and the States, or on distribution of power and responsibilities among various levels of government; (2) imposes substantial direct compliance costs on States and local governments; or (3) preempts State law. Therefore, the consultation and funding requirements of Executive Start Printed Page 39016Order 13132 (64 FR 43255; August 10, 1999) do not apply.
PHMSA analyzed this rule under the principles and criteria contained in Executive Order 13175 (“Consultation and Coordination with Indian Tribal Governments”) (63 FR 27655; November 9, 2000). Because this rule will not significantly or uniquely affect the communities of the Indian tribal governments, the funding and consultation requirements of this Executive Order do not apply.
This rule is not a “significant energy action” under Executive Order 13211 (Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use). It is not likely to have a significant adverse effect on energy supply, distribution, or use. This rule does not change the pressure reduction restrictions in the IM regulations. It only changes the notification requirements associated with those pressure reductions.
G. Unfunded Mandates
This rule does not impose unfunded mandates under the 1995 Unfunded Mandates Reform Act. It does not result in costs of $100 million or more to either State, local, or tribal governments, in aggregate, or to the private sector, and is the least burdensome alternative for achieving the objectives.
H. Paperwork Reduction Act
PHMSA evaluated the rule, as required by the Paperwork Reduction Act of 1995 (44 U.S.C. 3507(d)), and believes the rule will impose no significant paperwork burden on industry or individual operators. Industry commenters to the rule supported the revised notification requirements. As required, PHMSA presented a separate paperwork analysis to OMB for review and will file a copy of the analysis in the docket.
This rule imposes minimal information collection requirements. Based on information currently available to PHMSA, 26 operators filed 74 pressure reduction notifications over the last three years. The revised notification requirements will likely result in minimal additional paperwork burden. The estimated average time to prepare a notification request is 30 minutes. PHMSA does not know how many more notifications will result from the requirement but estimates, on average, less than $3.04 per affected operator per year. Therefore, there should be no significant cost or hourly burden on individual operators or the industry because of the notification requirement in this rule.
I. National Environmental Policy Act
PHMSA analyzed this rule under section 102(2)(c) of the National Environmental Policy Act (42 U.S.C. 4332), the Council on Environmental Quality regulations (40 CFR 1500-1508), and DOT Order 5610.1C, and determined this action will not significantly affect the quality of the human environment. PHMSA did not receive comments on the environmental assessment prepared on the proposed rule. The final environmental assessment is in the Docket.Start List of Subjects
List of Subjects
End List of Subjects Start Amendment Part
For the reasons set forth in the preamble, PHMSA amendsEnd Amendment Part Start Part
PART 192—TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: MINIMUM FEDERAL SAFETY STANDARDSEnd Part Start Amendment Part
1. The authority citation for part 192 continues to read as follows:End Amendment Part Start Amendment Part
2. Amend § 192.933 by revising paragraphs (a) and (c), to read as follows:End Amendment Part
(a) General requirements. An operator must take prompt action to address all anomalous conditions the operator discovers through the integrity assessment. In addressing all conditions, an operator must evaluate all anomalous conditions and remediate those that could reduce a pipeline's integrity. An operator must be able to demonstrate that the remediation of the condition will ensure the condition is unlikely to pose a threat to the integrity of the pipeline until the next reassessment of the covered segment.
(1) Temporary pressure reduction. If an operator is unable to respond within the time limits for certain conditions specified in this section, the operator must temporarily reduce the operating pressure of the pipeline or take other action that ensures the safety of the covered segment. An operator must determine any temporary reduction in operating pressure required by this section using ASME/ANSI B31G (incorporated by reference, see § 192.7) or AGA Pipeline Research Committee Project PR-3-805 (“RSTRENG,” incorporated by reference, see § 192.7) or reduce the operating pressure to a level not exceeding 80 percent of the level at the time the condition was discovered. (See appendix A to this part for information on availability of incorporation by reference information.) An operator must notify PHMSA in accordance with § 192.949 if it cannot meet the schedule for evaluation and remediation required under paragraph (c) of this section and cannot provide safety through temporary reduction in operating pressure or other action. An operator must also notify a State pipeline safety authority when either a covered segment is located in a State where PHMSA has an interstate agent agreement, or an intrastate covered segment is regulated by that State.
(2) Long-term pressure reduction. When a pressure reduction exceeds 365 days, the operator must notify PHMSA under § 192.949 and explain the reasons for the remediation delay. This notice must include a technical justification that the continued pressure reduction will not jeopardize the integrity of the pipeline. The operator also must notify a State pipeline safety authority when either a covered segment is located in a State where PHMSA has an interstate agent agreement, or an intrastate covered segment is regulated by that State.
(c) Schedule for evaluation and remediation. An operator must complete remediation of a condition according to a schedule prioritizing the conditions for evaluation and remediation. Unless a special requirement for remediating certain conditions applies, as provided in paragraph (d) of this section, an operator must follow the schedule in ASME/ANSI B31.8S (incorporated by reference, see § 192.7), section 7, Figure 4. If an operator cannot meet the schedule for any condition, the operator must explain the reasons why it cannot meet the schedule and how the changed schedule will not jeopardize public safety.
PART 195—TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINEEnd Part Start Amendment Part
3. The authority citation for part 195 continues to read as follows:End Amendment Part Start Amendment Part
4. Amend § 195.452 by revising paragraphs (h)(1), (h)(3), (h)(4), and (j)(3) to read as follows:End Amendment Part
(h) * * * (1) General requirements. An operator must take prompt action to address all anomalous conditions the operator discovers through the integrity assessment or information analysis. In addressing all conditions, an operator must evaluate all anomalous conditions and remediate those that could reduce a pipeline's integrity. An operator must be able to demonstrate that the remediation of the condition will ensure the condition is unlikely to pose a threat to the long-term integrity of the pipeline. An operator must comply with § 195.422 when making a repair.
(i) Temporary pressure reduction. An operator must notify PHMSA, in accordance with paragraph (m) of this section, if the operator cannot meet the schedule for evaluation and remediation required under paragraph (h)(3) of this section and cannot provide safety through a temporary reduction in operating pressure.
(ii) Long-term pressure reduction. When a pressure reduction exceeds 365 days, the operator must notify PHMSA in accordance with paragraph (m) of this section and explain the reasons for the delay. An operator must also take further remedial action to ensure the safety of the pipeline.
(3) Schedule for evaluation and remediation. An operator must complete remediation of a condition according to a schedule prioritizing the conditions for evaluation and remediation. If an operator cannot meet the schedule for any condition, the operator must explain the reasons why it cannot meet the schedule and how the changed schedule will not jeopardize public safety or environmental protection.
(4) Special requirements for scheduling remediation. (i) Immediate repair conditions. An operator's evaluation and remediation schedule must provide for immediate repair conditions. To maintain safety, an operator must temporarily reduce the operating pressure or shut down the pipeline until the operator completes the repair of these conditions. An operator must calculate the temporary reduction in operating pressure using the formula in section 451.7 of ASME/ANSI B31.4 (incorporated by reference, see § 195.3), if applicable. If the formula is not applicable to the type of anomaly or would produce a higher operating pressure, an operator must use an alternative acceptable method to calculate a reduced operating pressure. An operator must treat the following conditions as immediate repair conditions:
(3) Assessment intervals. An operator must establish five-year intervals, not to exceed 68 months, for continually assessing the line pipe's integrity. An operator must base the assessment intervals on the risk the line pipe poses to the high consequence area to determine the priority for assessing the pipeline segments. An operator must establish the assessment intervals based on the factors specified in paragraph (e) of this section, the analysis of the results from the last integrity assessment, and the information analysis required by paragraph (g) of this section.
Issued in Washington, DC, on July 6, 2007.
Thomas J. Barrett,
[FR Doc. E7-13772 Filed 7-16-07; 8:45 am]
BILLING CODE 4910-60-P