Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines); Correction

AGENCY:

Office of Pipeline Safety (OPS), Research and Special Programs Administration (RSPA), DOT.

ACTION:

Final rule; correction & petition for reconsideration.

SUMMARY:

This document corrects a final rule published in the Federal Register on December 15, 2003 (68 FR 69778). That rule requires operators to develop integrity management programs for gas transmission pipelines located where a leak or rupture could do the most harm, i.e., could impact high consequence areas (HCAs). The rule requires gas transmission pipeline operators to perform ongoing assessments of pipeline integrity, to improve data collection, integration, and analysis, to remediate the pipeline as necessary, and to implement additional preventive and mitigative actions. This document makes minor editorial corrections and clarifies the intent of several provisions in the rule. This document also addresses a petition for reconsideration filed by the Interstate Natural Gas Association of America (INGAA).

EFFECTIVE DATE:

The effective date is April 6, 2004.

FOR FURTHER INFORMATION CONTACT:

Mike Israni by phone at (202) 366-4571, by fax at (202) 366-4566, or by e-mail at mike.israni@rspa.dot.gov, regarding the subject matter of the final rule.

SUPPLEMENTARY INFORMATION:

Background

On December 15, 2003, RSPA/OPS published a final rule (68 FR 69778) that requires operators of gas transmission pipelines to develop and implement a comprehensive integrity management program for pipeline segments where a failure would have the greatest impact to the public or property.

Errors and Language in the Rule Needing Correction or Clarification

OPS has identified errors in the published final rule (68 FR 69778; December 15, 2003), such as incorrect reference numbers, editorial errors, incorrect terms and misspellings. OPS has also identified language in several provisions of the rule that is confusing and needs clarification. Thus, this document either corrects the rule because of mistakes found since the rule was published or clarifies the language and intent of the rule. None of these substantively changes any requirement in the rule.

Petition for Reconsideration

On January 15, 2004, the Interstate Natural Gas Association of America (INGAA) filed a petition for reconsideration of the final rule on gas integrity management identifying corrections INGAA believed were needed in the rule. This document addresses that petition. This document addresses mistakes the petitioner has identified in the rule and clarifies ambiguous language the petitioner identified. However, this document does not address what INGAA identified as mistakes but that would substantively change the rule. (See section below titled “Recommended changes not made”).

Corrections and Clarifications

Section 192.901 states that the integrity management program regulations apply to gas transmission pipelines. In the Preamble to the final rule, we stated our intent that the integrity management program requirements apply to gas transmission pipelines and not to gas gathering or distribution lines. However, § 192.9 provides that except for the requirements in §§ 192.1 and 192.150, operators of gathering lines must follow the requirements for transmission pipelines. We have clarified in § 192.9 that gathering lines are not subject to the requirements of subpart O. This clarification is to ensure that there is no misunderstanding about which gas pipelines the integrity management program requirements are intended to apply.

The final rule includes a definition for identified sites in § 192.903. One component of this definition is any building that is occupied by 20 or more persons for specified periods and that meets other specified criteria. The rule language is correct. However, in the preamble of the final rule, we incorrectly described the component as “buildings housing 50 or more people.” The preamble discussion should have said “buildings housing 20 or more people” to match the rule requirement.

Section 192.903 included allowed an operator to choose one of two methods for identifying a high consequence area. Method 1 involves designating all class 3 and 4 areas as high consequence areas, and was intended to relieve operators from the need to calculate and evaluate potential impact circles in these areas. We intended, however, that an operator would have to calculate and evaluate potential impact circles on any transmission pipeline not in a class 3 or class 4 area. We used the phrase “outside a Class 3 or Class 4 location” to describe these high consequence areas. However, this phrase could be interpreted to include areas more than 660 feet from a pipeline where the pipeline is in a class 3 or 4 area. We did not intend for an operator to evaluate any areas further than 660 feet from the pipeline in these areas, since the pipeline is already in a high consequence area under the criteria of method 1. We replaced this phrase with “in a Class 1 or Class 2 location” to make it clear that we are referring to an evaluation of pipeline segments not already classified as high consequence areas.

In addition, another criterion under method 1 refers to potential impact circles containing an identified site, which again could be interpreted as requiring operators to calculate potential impact circles within existing class 3 and 4 areas. We have revised this criterion (paragraph (1)(iv)) to clarify that the evaluation need only be performed in class 1 and 2 areas, where the existence of an identified site might require that the area be considered a high consequence area.

Several provisions in the rule require notification to OPS and in some instances to a State pipeline safety authority when a State acts as an interstate agent on a covered segment of transmission pipeline or the State regulates a covered segment on an intrastate transmission pipeline. The language requiring the state notification was confusing. We have clarified the language.

The Preamble discussed the necessity of keeping state regulators informed versus the need to keep an operator's information about its system secure. Where security of information was a concern, we limited the information submission to OPS or to an interstate agent, as the statute required. Where security was not an issue, the rule included state notification on an intrastate transmission line regulated by the State. However, in two provisions on notification when an operator uses other technology to assess a covered segment for the baseline or reassessment (§§ 192.921(a)(4) and 192.937(c)(4)), we inadvertently left out the notification to a State when it is either an interstate agent or regulates an intrastate transmission covered segment. We have corrected these omissions.

Section 192.913 of the final rule establishes conditions under which an operator may deviate from specific provisions of the rule, by establishing a performance-based program. One of the required criteria is that an operator have completed at least two integrity assessments on all covered pipeline segments (§ 192.913(b)(2)(i)). This was a mistake. The rule should have limited the prior integrity assessment to those segments the operator wants to include under the performance-based option. We have revised the criterion to require that at least two assessments must have been completed on all segments to be included in the operator's performance-based program. This change clarifies that an operator may establish a performance-based program covering only a portion of its pipeline segments subject to the final rule. The remaining covered segments would still be subject to the more prescriptive approach.

In § 192.917, paragraph (a) lists the types of threats an operator is to consider in its threat identification. We have revised the paragraph to clarify that the threats listed in the rule restate the threats listed in the ASME/ANSI B31.8S standard, and are not in addition to those in the standard.

In § 192.917, paragraph (b) requires an operator to gather and integrate data from its entire pipeline system that could be relevant to identifying potential threats to the covered pipeline segment. Although it seems self-evident that an operator must only gather and integrate existing data about its pipeline system, industry has expressed concern that an operator will be required to create data. We have revised the paragraph to clarify that the data has to exist before it is gathered and integrated for analysis.

In § 192.917, paragraph (e) requires an operator to analyze its pipeline to identify specific potential threats to the pipeline. This document revises two paragraphs in this section (paragraphs (e)(1) and (e)(3)) to provide additional clarity on information that must be included in these analyses. Paragraph (e)(1) now specifies that an operator is to use information from a direct assessment to help define where third party damage may exist. Similarly, paragraph (e)(3) now specifies that an operator is to use information from prior integrity assessments to determine the risk of failure in the covered segment from manufacturing and construction defects.

In § 192.917, paragraph (e)(3) also establishes requirements specific to pipe for which an operator has identified the threat of manufacturing and construction defects. This paragraph states that an operator may consider such defects to be stable defects if the operating conditions on the covered segment have not changed significantly “since December 17, 1998.” We intended this provision to provide for a retrospective evaluation of five years, beginning from the date on which integrity management requirements were first established by the Pipeline Safety Improvement Act of 2002. These requirements would also apply, however, for pipeline in areas which may be identified as high consequence areas many years in the future. For such pipe, a retrospective evaluation reaching back to 1998 would not make sense. This paragraph has been revised to require that the retrospective evaluation cover 5 years, regardless of when the high consequence area is identified.

In § 192.917, paragraph (e)(4) establishes requirements specific to low-frequency electric resistance welded (ERW) pipe and lap welded pipe that satisfies conditions in an industry standard, ASME/ANSI B31.8S. The rule incorporates by reference the industry standard. The preamble to the final rule stated that these requirements would apply to pipe that has a history of seam failures. However, this criterion was inadvertently omitted from the rule. We have added the criterion with additional clarification. We have clarified that when a covered pipe segment has low frequency ERW pipe, lap welded or other pipe that satisfies the conditions in ASME B31.8S, Appendices A.4.3 and A4.4, and any such pipe in the system has a history of seam failure, or operating pressure on the covered segment has increased over the maximum operating pressure experienced during the preceding five years, the operator must prioritize the covered segment as a high risk segment for assessment purposes and must use a specified type of assessment technology. We have also clarified the capabilities that are required of the assessment technology.

In § 192.921, paragraph (a)(2) requires that a pressure test used for the baseline assessment of a covered pipeline segment must be conducted in accordance with subpart J of part 192. The test pressures required by subpart J, while adequate to demonstrate the segment's integrity, are lower than required to justify some of the reassessment intervals under § 192.939. To avoid confusion, we have added a sentence providing that higher test pressures that are in accordance with Table 3 of Section 5 of ASME/ANSI B31.8S may be needed to justify an extended reassessment interval under § 192.939.

In § 192.921, paragraph (g) requires that an assessment be completed for newly-installed pipe within ten years from when the pipe is installed. This paragraph allows a pressure test, meeting the requirements of 49 CFR part 192, subpart J, which would normally be conducted as part of installation, to be used to meet this requirement. The reference to this pressure test in the final rule referred to it as a post-installation test. That term was incorrect because subpart J allows reliance on tests conducted prior to installation. There is no technical reason to deviate from the established subpart J requirements, and the final rule has been changed to delete the term post-installation.

Section 192.925 sets forth the requirements for external corrosion direct assessment. The threat identification section (§ 192.917) requires operators to take actions to address particular threats. One of these threats is third-party damage. The data from a direct assessment can be relevant to identifying this damage, such as identifying coating damage that may indicate damage from a third party excavation. In § 192.925 we are adding a sentence to clarify that operators are to integrate data from the external corrosion direct assessment with data from internal inspection tools and other information relevant to the pipeline to help identify and address third-party damage.

In § 192.927, paragraph (b) includes requirements for the internal corrosion direct assessment (ICDA) process for the dry gas system. If an operator uses ICDA to assess a segment operating with electrolyte present in the gas stream, the operator must develop a plan that demonstrates how it will conduct ICDA in the segment to effectively address internal corrosion. This ICDA application would be other technology that requires notification to OPS and to the State pipeline safety authority, when applicable. We have clarified that an operator using ICDA for a wet gas system must provide this required notification.

In § 192.927, paragraph (c)(3) includes criteria to identify locations where direct examination of the pipe must be conducted when an operator is using ICDA. These criteria specified a minimum of two direct examinations, one of which must be at the low spot within the covered segment nearest to the beginning of the ICDA region and the second “at the upstream end of the pipe containing a covered segment, having a slope not exceeding the critical angle of inclination nearest the end of the ICDA region.” The wording of the second required location has caused confusion. We have clarified the language to specify that the second location be “ farther downstream within a covered segment near the end of the ICDA Region.” There is no technical difference in this change; the revised wording more clearly describes the requirement.

In § 192.927, paragraph (c)(4)(i) requires that operators using internal corrosion direct assessment (ICDA) evaluate its effectiveness as an assessment method and in determining whether more frequent reassessments are required. In the final rule, this paragraph required that this evaluation be done “in the same year in which ICDA is used.” This could be unnecessarily burdensome, or even impractical, for situations in which ICDA is used late in a calendar year, as it would essentially require that the evaluations be performed immediately. This was not intended. This requirement has been revised to specify that the evaluation be carried out within a year of conducting the ICDA.

In § 192.933, paragraph (b) specifies that discovery of a condition is considered to occur when an operator has adequate information to determine that the condition “presents a potential threat to the integrity of the pipeline.” As we explained in the Preamble to the final rule (68 FR 69797-98), adequate information to make this determination includes information that the condition is one included in ASME/ANSI B31.8S as needing a response. To further clarify the types of conditions that might be potential threats to a system's integrity we have added a sentence that explains that a potential threat includes the immediate repair, one-year and monitored conditions listed in the rule. The rule does not list all conditions that might present a potential threat but gives examples of those that are most common. Although a monitored condition does not present an immediate threat or need remediation within a year, it is a condition that presents a potential threat because a change could occur making the threat to the pipeline's integrity more immediate.

To protect against third-party damage, paragraph (b)(1)(iv) of § 192.935 requires an operator to monitor excavations near its pipelines or investigate when the operator finds evidence of any excavation it did not monitor. Although not intended, this paragraph could be read as requiring an operator to investigate (i.e., excavate or conduct above ground measurements) whenever the operator finds evidence of encroachment involving excavation, even if the operator had monitored the excavation. This paragraph has been revised to reflect our intent that the investigation be limited to instances when the operator did not monitor the excavation.

In § 192.935, paragraph (d) specifies requirements for additional preventive and mitigative measures for a pipeline operating below 30% SMYS located in a Class 3 or Class 4 area but not in a high consequence area. Although the guidance table in appendix E had included measures to address external and internal corrosion threats, and additional preventive and mitigative measures for a pipeline operating below 30% SMYS located in a high consequence area, we did not include these measures in the rule language itself. We have added these measures to the rule.

In § 192.937, paragraph (c)(2) specifies that a pressure test used to reassess a covered pipeline segment must be conducted in accordance with Subpart J of Part 192. This reference to subpart J is revised to include Table 3 of Section 5 of ASME/ANSI B31.8S, for the reasons given in § 192.921(a)(2) above.

In § 192.939, paragraph (a) specifies reassessment intervals for a pipeline operating at or above 30% SMYS and paragraph (b) specifies reassessment intervals for a pipeline operating below 30% SMYS. Both paragraphs state that the minimum reassessment interval is seven years. This has been corrected now to state that the maximum reassessment interval is seven years.

In § 192.945, paragraph (a) requires an operator to include in its integrity management program methods to measure, on a semi-annual basis, whether the program is effective in assessing and evaluating the integrity of each covered pipeline segment and in protecting the high consequence areas. These measures include the four overall performance measures and the specific measures for each identified threat specified in ASME/ANSI B31.8S, appendix A. RSPA/OPS had intended that an operator submit only the four overall performance measures, by electronic or other means, on a semi-annual frequency. The additional measures are to be reviewed during inspections. However, the final rule mistakenly requires all measures to be submitted semi-annually. We have corrected paragraph (a) to specify that an operator submit the four overall performance measures semi-annually. In addition, we have included the dates by which an operator is to submit these semi-annual performance measures. Similarly, our intent was that performance measures related to external corrosion direct assessment were to be reviewed during inspection, not submitted to OPS. Accordingly, we have removed the requirement in paragraph (b) that these measures be submitted semi-annually.

Some of the examples in section I of appendix E that illustrate the methods for identifying high consequence areas are inconsistent with the definition in § 192.903. We have deleted the examples to avoid any confusion about the definition. The illustrative figure in this appendix, Figure E.I.A, is accurate, and has been retained.

Section II of appendix E provides additional guidance for operators on assessment methods and additional preventive and mitigative measures. Some, but not all, of the guidance in this appendix is applicable to pipelines operating below 30% SMYS. However, the title of the appendix incorrectly states that the guidance is only for assessment methods and applies only to pipelines operating below 30% SMYS. This is being corrected. The paragraphs in this appendix that refer to Tables E.II.1 and E.II.2 are also corrected to more accurately describe the information in those tables.

Table E.II.1, in appendix E, describes additional preventive and mitigative measures that must be taken for pipelines in class 3 or class 4 areas but not in high consequence areas. The title of the table and the heading for column 4 inaccurately refer to assessment methods, which are not described in this table. We have corrected the title and column heading.

Recommended Changes Not Made

In the petition for reconsideration of the final rule, several of the changes INGAA recommended are substantive changes to the final rule. The recommended changes were neither errors we had made in drafting the rule nor language we believe needs clarification. We have not made these changes because they do not reflect our intent and would substantively change the intent of the rule. Specifically, we have not included the following changes in this document.

• In § 192.913(b)(2)(ii), we have not changed the word “anomalies” to “defects”. We use the word “anomalies” throughout the rule.
• In § 192.917(a), we have not deleted the description of the four types of general threats an operator must identify. INGAA noted that this listing is redundant to the descriptions in ASME/ANSI B31.8S. We consider the nature of these threats as key to understanding the rule; therefore, the listing should be included in the rule. As we described above, we have clarified the language in this section to correct any impression that the described threats are in addition to those in the standard.
• In § 192.917(b), we have not, as INGAA suggested, substituted “similar segments” for the word “entire” in the requirement that an operator gather and integrate information on its entire pipeline system that could be relevant to the covered segment. A crucial element of integrity management is the integration of relevant information from the entire system, not just from certain segments of the system.
• In § 192.921(e), we have not adopted the suggestion that a prior assessment done before December 17, 2002 substantially meet the baseline requirements for the prior assessment to qualify as a baseline assessment. We believe that what constitutes substantial compliance is too subjective. There would be constant disagreement between operators and regulators about what substantial compliance means. We allowed more flexible requirements for a prior assessment under the performance-based option because that option sets additional and more stringent requirements. Those additional requirements are not present when a prior assessment is used under the non performance-based approach. Furthermore, to give operators flexibility in the use of prior assessments, in the final rule we deleted the proposed requirement that set a five-year period before December 17, 2002 and allowed any prior assessment before December 17, 2002 so long as it meets certain requirements.
• In § 192.927(c)(5)(iii), we have not deleted the word “entire” from the requirement that an operator's internal corrosion direct assessment plan provide for an analysis carried out on the entire pipeline in which covered segments are present.
• In § 192.937(b), we have not deleted the word “entire” from the requirement that an operator conduct a periodic evaluation that is based on a data integration and risk assessment of the entire pipeline.
• Several provisions in the rule differentiate requirements based on whether a transmission pipeline is operating below 30% SMYS, operating at or above 30% SMYS up to 50% SMYS or operating at or above 59% SMYS. We have not changed the categories. However, we recognize that these categories are changed in the draft 2004 version of the ASME B31.8S standard. Once that standard is finalized and if we adopt it into the rule, then we will change the stress classifications.
• We have not moved the notification procedures in §§ 192.941 and 192.951 to Part 191. These procedures are specific to notification for integrity management program purposes.

List of Subjects in 49 CFR Part 192

• High consequence areas
• Incorporation by reference
• Integrity management
• Pipeline safety
• Potential impact areas
• Reporting and recordkeeping requirements

PART 192—[AMENDED]

Accordingly, 49 CFR part 192 is corrected by making the following correcting amendments:

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. Section 192.9 is revised to read as follows:

3. Section 192.903 is amended as follows:

a. In the definition of “Assessment”, the word “nondestructive” is removed;

b. In the definition of “Confirmatory direct assessment”, the word “integrity” is added in the first sentence before the words “assessment method”;

c. The definition of “High consequence area” is revised; and

d. The definition of “Identified site” is amended by removing ”)” at the end of paragraphs (a) and (b).

The additions and revisions read as follows:

4. Section 192.909 is amended by revising paragraph (b) to read as follows:

5. In § 192.911, paragraph (i) is amended by removing “§ 192.943” and adding “§ 192.945” in its place.

6. In § 192.913:

a. Paragraph (b)(1) (vii) is amended by removing “§ 192.943” and adding “§ 192.945” in its place; and

b. Paragraph (b)(2)(i) is revised to read as follows:

7. In § 192.917:

a. Paragraph (a) introductory text is revised;

b. Paragraph (b) is revised;

c. Paragraphs (e)(1), (e)(3) and (e)(4) are revised; and

d. Paragraph (e)(5) is amended by removing “§ 192.931” and adding “§ 192.933” in its place.

The revisions read as follows:

8. In § 192.921:

a. Paragraphs (a)(2) and (a)(4) are revised;

b. Paragraph (c) is amended by removing “§ 192.917(d)” and adding “§ 192.917(e)” in its place;

c. Paragraph (f) is amended by removing “§ 192.205” and adding “§ 192.905” in its place; and

d. Paragraph (g) to revised.

The revisions read as follows:

9. Section 192.925 is amended by revising paragraph (b) to read as follows:

10. Section 192.927 is amended by revising paragraphs (b), (c)(3) introductory text and (c)(4)(i) to read as follows:

11. Section 192.929 is amended by revising paragraph (a) to read as follows:

12. Section 192.933 is amended by revising paragraphs (b), (c) and (d)(1)(iii) to read as follows:

13. In § 192.935:

a. The section heading of § 192.935 is revised;

b. Paragraphs (b)(1) introductory text, (b)(1)(ii), and (b)(1)(iv) are revised; and

c. Paragraph (d) introductory text is revised and paragraph (d)(3) is added.

The additions and revisions are as follows:

14. Section 192.937 is amended by revising paragraphs (c)(2) and (c)(4) to read as follows:

15. In § 192.939:

a. Paragraphs (a) introductory text and (a)(1)(i) are revised;

b. Paragraph (a)(3) is amended by removing the word “calculation” at the end of the first sentence and adding the word “method” in its place;

c. Paragraph (b) introductory text is amended by removing the word “minimum” in the beginning of the second sentence and adding the word “maximum” in its place; and

d. Paragraph (b)(5) is revised and the undesignated paragraph before the table is designated as paragraph (b)(6).

The revisions read as follows:

16. In § 192.941, paragraph (b)(2)(ii) is amended by removing the term “1 1/2 years” in the first sentence and adding “18 months” in its place.

17. Section 192.943 is amended by revising paragraph (a)(1) to read as follows:

18. Section 192.945 is amended as follows:

a. Paragraph (a) to revised; and

b. Paragraph (b) is amended by removing the last sentence.

19. In § 192.947 second sentence is amended by removing “minium” and adding “minimum” in its place.

Appendix A to Part 192 [Amended]

20. Appendix A to part 192 is amended by redesignating paragraph numbers II. F. and II. G. as paragraph numbers II. H. and II. I., respectively.

21. Appendix E to part 192 is revised to read as follows:

Appendix E to Part 192—Guidance on Determining High Consequence Areas and on Carrying out Requirements in the Integrity Management Rule

I. Guidance on Determining a High Consequence Area

To determine which segments of an operator's transmission pipeline system are covered for purposes of the integrity management program requirements, an operator must identify the high consequence areas. An operator must use method (a) or (b) from the definition in § 192.903 to identify a high consequence area. An operator may apply one method to its entire pipeline system, or an operator may apply one method to individual portions of the pipeline system. (Refer to figure E.I.A for a diagram of a high consequence area).

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II. Guidance on Assessment Methods and Additional Preventive and Mitigative Measures for Transmission Pipelines

(a) Table E.II.1 gives guidance to help an operator implement requirements on additional preventive and mitigative measures for addressing time dependent and independent threats for a transmission pipeline operating below 30% SMYS not in an HCA (i.e. outside of potential impact circle) but located within a Class 3 or Class 4 Location.

(b) Table E.II.2 gives guidance to help an operator implement requirements on assessment methods for addressing time dependent and independent threats for a transmission pipeline in an HCA.

(c) Table E.II.3 gives guidance on preventative & mitigative measures addressing time dependent and independent threats for transmission pipelines that operate below 30% SMYS, in HCAs.

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