{"operation":"document","citation":"67 FR 1650","title":"Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Repair Criteria)","source_type":"rulemaking","agency":"Research and Special Programs Administration","status":"historical","official":true,"published_on":"2002-01-14","effective_on":"2001-05-29","summary":"This final rule finalizes repair provisions for hazardous liquid pipelines. These provisions were initially proposed in the previous rulemaking action which addressed requirements for pipeline integrity management programs in high consequence areas for operators owning or operating 500 or more miles of hazardous liquid or carbon dioxide pipeline (Integrity Management rule.) In the Integrity Management rule, we requested comment on the repair and mitigation provisions, because the provisions were substantially modified from those originally proposed in the notice of proposed rulemaking. This final rule also makes several non-substantive corrections and clarifications to other provisions of the Integrity Management rule.","machine_formats":{"json":"https://regulus.evalyn.ai/document/federal-register-02-267.json","markdown":"https://regulus.evalyn.ai/document/federal-register-02-267.md"},"app_url":"https://regulus.evalyn.ai/document/federal-register-02-267","source_url":"https://www.federalregister.gov/documents/2002/01/14/02-267/pipeline-safety-pipeline-integrity-management-in-high-consequence-areas-repair-criteria","body":"Federal Register, Volume 67 Issue 9 (Monday, January 14, 2002) [Federal Register Volume 67, Number 9 (Monday, January 14, 2002)] [Rules and Regulations] [Pages 1650-1661] From the Federal Register Online via the Government Publishing Office [ www.gpo.gov ] [FR Doc No: 02-267] ======================================================================= ----------------------------------------------------------------------- DEPARTMENT OF TRANSPORTATION Research and Special Programs Administration 49 CFR Parts 195 [Docket No. RSPA-99-6355; Amendment 195-74] RIN 2137-AD61 Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Repair Criteria) AGENCY: Research and Special Programs Administration (RSPA), DOT. ACTION: Final rule. ----------------------------------------------------------------------- SUMMARY: This final rule finalizes repair provisions for hazardous liquid pipelines. These provisions were initially proposed in the previous rulemaking action which addressed requirements for pipeline integrity management programs in high consequence areas for operators owning or operating 500 or more miles of hazardous liquid or carbon dioxide pipeline (Integrity Management rule.) In the Integrity Management rule, we requested comment on the repair and mitigation provisions, because the provisions were substantially modified from those originally proposed in the notice of proposed rulemaking. This final rule also makes several non-substantive corrections and clarifications to other provisions of the Integrity Management rule. DATES: This rule is effective May 29, 2001, except for paragraph (h) of Sec. 195.452 which takes effect February 13, 2002. The incorporation by reference of certain publications in this rule is approved by the Director of the Federal Register as of February 13, 2002. FOR FURTHER INFORMATION CONTACT: Mike Israni, (202) 366-4571, or by e- mail: [email protected] , regarding the remediation provisions in paragraph (h) or any other provisions of the integrity management rule; or the Dockets Facility (202) 366-9329, for copies of this final rule or other material in the docket. All materials in this docket may be accessed electronically at http://dms.dot.gov . General information about the RSPA/Office of Pipeline Safety (OPS) programs may be obtained by accessing OPS's Internet homepage at http://ops.dot.gov . SUPPLEMENTARY INFORMATION: Background On December 1, 2000, RSPA published a final rule (65 FR 75378) that prescribed integrity management [[Page 1651]] program requirements for pipeline operators who own or operate 500 or more miles of pipeline transporting hazardous liquids or carbon dioxide. Under the Integrity Management rule, operators are required to develop and implement integrity management programs that focus on hazardous liquid and carbon dioxide pipelines that could affect high consequence areas. High consequence areas are defined as: populated areas, areas unusually sensitive to environmental damage, and commercially navigable waterways. As part of the Integrity Management final rule, we requested comment on repair and mitigation provisions (Sec. 195.452(h).) We made this request because we substantially changed the initial provisions proposed in the notice of proposed rulemaking. We noted at that time that, at the end of the comment period (March 31, 2001), we would either publish a final rule modifying these repair provisions or stating that the provisions would remain unchanged. We received comments from six sources. Based on our analysis of the comments received, we modified paragraph (h). We discussed the comments, our responses, and changes made to these provisions below, in greater detail. This document also makes several corrections and language clarifications to other provisions in Sec. 195.452 and the Appendix C guidance. These changes do not affect the substance of any of the Integrity Management rule requirements. Rather, these revisions either correct the rule because of mistakes found since the rule was issued, or they clarify some of the language. Corrections The reference in paragraph (j)(4)(i) that the external monitoring technology provide an understanding of the line pipe equivalent to that obtained under paragraph (j)(2), was incorrect. The reference should be to the assessment methods listed in paragraph (j)(5), not to the evaluation described in paragraph (j)(2). We deleted the sentence in paragraph (j)(4)(ii) requiring an operator to complete an integrity assessment within 180 days, after providing 180-days advance notice that it could not complete the five- year continual integrity assessment because of unavailable technology. If we did not remove this requirement, an operator would have to complete the re-assessment within the five-year period. Thus, the exception for a longer assessment period would be illusory. We corrected the notification period in paragraph (j)(5)(iii), which required using alternative technology in the continual integrity assessment, from 60 days to 90 days. 90 days is consistent with the advance notice required for a baseline assessment that uses technology other than a hydrostatic test or an internal inspection tool. We added paragraph number 1 to precede the first sentence in paragraph (l). We corrected the grammar in several places in Appendix C. Clarifications and Non-Substantive Revisions We added carbon dioxide pipelines to Sec. 195.452(a) to clarify that the integrity management program requirements for hazardous liquid pipelines to also apply to carbon dioxide pipelines regulated under Part 195. We clarified in paragraphs (c)(1)(i) and (j)(5) that the three allowable assessment methods for the baseline and continual integrity assessments are to be applied to lap welded pipe and to low frequency ERW pipe. We clarified that the periodic evaluation (paragraph (j)(2)) is to consider the results from the integrity assessments required by Sec. 195.452, i.e., the baseline and continual integrity assessments. We clarified the language in paragraph (j)(4)(i) regarding the justification and notice required for a variance based on engineering reasons. We added the requirement that an address and facsimile number must be included for notifications required by the Integrity Management rule, rather than referencing these in other pipeline safety regulations. Due to the confusion of some operators about where to send a notification required by Sec. 195.452 versus notifications required for other purposes, we added a new paragraph (paragraph (m)), which provides this information. We revised several paragraphs in Sec. 195.452 and Appendix C to make the terminology consistent with changes made to the terms used in paragraph (h). We added another section to the guidance in Appendix C, which lists conditions an operator should include in its schedule for evaluation and remediation. Advisory Committee Consideration The Technical Hazardous Liquid Pipeline Safety Standards Committee (THLPSSC) is the Federal advisory committee charged with the responsibility of advising on the technical feasibility, reasonableness, cost-effectiveness, and practicability of proposed hazardous liquid pipeline safety standards. The committee is composed of members with the requisite statutory expertise who represent industry, government, and the general public. We discussed the repair provisions in paragraph (h) and comments received on those provisions by teleconference with the THLPSSC at its meeting on August 13, 2001. Before the discussion, the committee members were mailed a summary of comments on the repair provisions, and a supplement to the cost-benefit analysis that addressed these provisions. At the August 13 meeting, seven of the twelve current members participated in the teleconference. These seven THLPSSC members voted unanimously to accept the repair provisions, provided OPS consider the changes and comments discussed during the teleconference. The following is a list of the changes and comments that the THLPSSC asked OPS to consider: Reevaluate and relax the 60-day repair schedule for dents on the top of the pipe. Allow mitigative measures, other than repair. The provisions assume the use of in-line-inspection technology to identify defects although the rule allows both hydrostatic testing and other technologies for the integrity assessments. Provide that discovery of a defect occurs when an engineering analysis of the assessment results is completed. Let the section reflect that some internal inspection assessment results cannot be analyzed as quickly as others. For example, it typically takes a year following completion of the assessment to receive final results from a crack detection tool. Delete the section on other conditions requiring repair or move it to Appendix C as guidance material. We discuss below all changes made to Sec. 195.452(h) in response to the THLPSSC and other commenters. Comments on Section 195.452(h) On December 1, 2000, OPS issued a final rule addressing pipeline integrity management in high consequence areas for operators owning or operating 500 or more miles of hazardous liquid or carbon dioxide pipeline (65 FR 75378) (The Integrity Management Rule.) This rule included provisions addressing the repair of conditions found during an integrity assessment. The provisions were found in paragraph (h) of section 195.452, under the title ``What actions must be taken to address integrity [[Page 1652]] issues.'' However, because the repair provisions in the Integrity Management rule were substantially different from what we initially proposed in the notice of proposed rulemaking, we requested comment on the provisions. All other provisions of the Integrity Management rule were final and became effective May 29, 2001. We received comments from the following six sources: --One trade association with members affected by this rulemaking: American Petroleum Association (API) --Three individual liquid pipeline operators: Tosco Corporation Chevron Pipe Line Company Colonial Pipeline Company --One operator not directly affected by this rulemaking: Enron Transportation Services Company (natural gas transmission) --One Engineering company: SEFBO Pipeline Bridge, Inc. SEFBO did not comment directly on the repair provisions but expressed its support for pipeline integrity management programs and stressed the importance of considering safety issues relating to the support structures used by pipelines to cross high consequence and other sensitive areas. Some of the comments we received about the repair provisions also addressed other portions of the final rule. As we only requested comment on the repair provisions in paragraph (h), this document will focus on those comments. If at some point we determine that substantive revisions to the final rule are necessary and we propose changes, we will then consider those comments. Comments on Section 195.452(h)--``What actions must be taken to address integrity issues?'' 1. General comments about paragraph (h): API objected to use of the word repair throughout paragraph (h). API contended the exclusive focus of the rule on repairs undermined the holistic approach of the rule. API commented that a key principle throughout the rule is the integration of information, so appropriate mitigative actions can be taken based on a comprehensive assessment. API explained that although actions may consist of repair, other actions such as further testing and evaluation, environmental changes, operational changes, or administrative changes could be appropriate. API advised that the goal should be to ensure operators differentiate defects injurious to a pipeline's integrity from those that are not. Tosco also commented that requiring repair in all instances was too inflexible, and operators must have the flexibility to address a wide range of conditions. Response: To assure the integrity of pipeline segments that could affect high consequence areas, Section 195.452 requires an operator to conduct a variety of assessments. The assessments include baseline and continual integrity assessments of the line pipe and periodic evaluations of entire pipeline systems, to assure the integrity of pipeline segments that could affect high consequence areas. This is accomplished through the continual identification and remediation of potential problems. We agree the word ``repair'' in paragraph (h) might be too narrow to encompass the range of actions an operator could take to address a problem. We intended paragraph (h) to reflect the broader actions an operator must take to address integrity issues that are identified. We further agree that all anomalies identified by an integrity assessment or information analysis might not require repair. Therefore, we replaced the word repair with remediate throughout paragraph (h). Remediate can encompass a broad range of actions, which include mitigative measures as well as repair, that an operator can take to resolve a potential integrity concern. Although we firmly believe repair is necessary to address many anomalies, we recognize repair may not be necessary in all instances. The rule provides the operator flexibility to determine the most appropriate action to take. However, we added language to ensure that whatever action is taken by an operator, it must be adequate to resolve the integrity concern on the pipeline for the long term. We also added a requirement that when an operator chooses to remediate a condition through a reduction in operating pressure, the pressure reduction is not to extend beyond 365 days without the operator taking further action to ensure the safety of the pipeline. 2. Section 195.452(h)(1)--General Requirements: In this paragraph we required an operator to take prompt action to address all pipeline integrity issues raised by the integrity assessment and information analysis, and evaluate all anomalies and repair those that could reduce a pipeline's integrity. An operator was further required to follow Sec. 195.422 in making a repair. API objected to the words ``prompt'' and ``all'' because these words could be interpreted in their absolute sense; could cause confusion because of the required time frames for addressing certain conditions; and could lead inspectors to require operators to take costly actions to address insignificant anomalies. API recommended deleting these terms. Tosco suggested the rule only require an operator to comply with Sec. 195.22 when a repair is necessary. Response: As explained in the previous section, we replaced ``repair'' with ``remediate'' throughout paragraph (h), allowing for actions other than repair, in order to address integrity threatening pipeline conditions. This will allow an operator flexibility in how to address anomalous conditions on its pipeline. We did not delete the terms ``prompt'' and ``all.'' The pipeline safety regulations have long incorporated the term ``prompt,'' with consistent enforcement; there is little disagreement between operators and inspectors about its meaning. For the listed conditions, we determined what a prompt time frame should be (viz., immediate, 60 days, 180 days), but leave it to the operator to determine appropriate time frames for other conditions. We kept the word ``all'' because it is a reasonable requirement for an operator to evaluate all conditions indicated by an integrity assessment or the information analysis, in order to determine the significance of each concern. Upon evaluation of the condition, the operator can then determine the appropriate further action to take, if any. We revised the language to clarify that an operator must evaluate all anomalous conditions (i.e., any condition that is irregular, abnormal, deviates from the norm, etc.) and remediate those conditions that could reduce the integrity of a pipeline. The word ``address'' is used in the introductory paragraph to encompass the process an operator should go through to find and remedy anomalous conditions, i.e., discovery, evaluation, and remediation of the condition through repair or other mitigative action. Using language to capture the process, is consistent with API's comment about the intended goal of the rule. By having an operator address all anomalous conditions raised by the integrity assessment or the information analysis, we envision a process that begins with discovery of a condition or anomaly that poses an integrity concern to the pipeline; continues with an evaluation that includes the analysis of other relevant data about the pipeline (this analysis could also be part of the discovery); and concludes with fixing the problem. We did not add ``if necessary,'' to the requirement about complying with [[Page 1653]] Sec. 195.422, as suggested by Tosco. The rule now uses the word remediate, which should alleviate any confusion about when compliance with Sec. 195.422 is necessary. Section 195.422 applies only to repairs. If actions other than repair are taken, the requirements in the section do not apply. 3. Section 195.452(h)(2)--Discovery of a condition. The discovery of a condition triggers the time frames (either required by the rule or the operator's schedule) for remediating the condition. We defined discovery as occurring when an operator has adequate information to determine the need for a repair, and we provided examples of when such information might be available, depending on the circumstances. The examples included the receipt of the preliminary internal inspection report, the gathering and integrating of other inspection information, and the receipt of the final internal inspection report. The date of discovery could be no later than the date of the integrity assessment results or the final report. API objected to tying discovery to a specific point in time because discovery is not usually a single event but occurs over time as information is analyzed. API commented that other provisions of the Integrity Management rule require operators to integrate information from various sources, and tying the date of discovery to the date of the integrity results or receipt of the final report is inconsistent with the concept of integrating data. API maintained that too much emphasis is put on the use of internal inspection tools and the data collected from running these tools through a pipeline. API also commented that the emphasis on the results of in-line inspections in determining what action must be taken, is inappropriate and inconsistent with the rule's intent for information from multiple sources to be integrated in the assessment process. API suggested that rather than tying discovery to the integrity assessment results or final report, discovery should occur when an operator has integrated other inspections, tests, surveillance, controls, or pipeline integrity data with the final inspection report from an in-line inspection vendor or hydrostatic test. API believes this integration should be completed within 90 days from the receipt of the final inspection report. Tosco expressed similar concerns and suggested the word ``discovery'' not be used, since it has the common meaning of when something is first found and might cause confusion with how the term is used in Sec. 195.56. Instead, Tosco would tie the repair schedules to the determination that a condition requires mitigation, which would be an outcome of the ongoing assessment process. Chevron also believed it is inappropriate to tie discovery to a specific event because discovery is a process that is subject to change with new information. Chevron suggested language changes identical to those recommended by API. Response: We contend that discovery triggers an operator's process to address a condition that could affect the integrity of a pipeline. Therefore, discovery has to occur at a specific point in time to start the period for evaluation and remediation of the condition. The use of the word ``discovery'' here is consistent with how the word has been used in other pipeline safety regulation. However, to allow flexibility the rule provides that the time of discovery can vary depending on circumstances, and does not define discovery to occur at the same time for every operator and every pipeline. Discovery will depend on circumstances. We revised the rule to provide that discovery occurs when an operator has adequate information about a condition to determine the condition presents a potential threat to the integrity of the pipeline. The ``when'' for an operator to have sufficient information to make a determination will not be the same for every operator and every pipeline. Although the examples in paragraph (h) provide circumstances when discovery might occur, they were intended only as examples. We decided to eliminate the list as it is not exhaustive and may cause confusion. We did keep the performance- based standard to give an operator flexibility when deciding there is adequate information to determine a condition presents a potential threat to its pipeline. However, we put an upper limit on the length of the discovery process. An operator must promptly obtain the information from an assessment to ensure that remediation of a condition which could threaten a pipeline's integrity occurs soon after an integrity assessment. The discovery process (the process for obtaining the adequate information) will end 180 days after an integrity assessment unless an operator can demonstrate that the 180-day period is impracticable. 4. Section 195.452(h)(3)--Review of integrity assessment: This paragraph, as proposed, required an operator to include in its schedule for evaluation and repair a schedule for promptly reviewing and analyzing integrity assessment results. After March 31, 2004, an operator's schedule had to provide for this review within 120 days of conducting each assessment. The operator also had to obtain and assess a final report within an additional 90 days. API objected to setting a fixed period for the review of integrity assessment results. API commented that the language confused the role of the vendor who conducts a specific test or provides interpretive results, with the operator who conducts the integrity assessment and uses information from sources other than in-line inspections in performing those assessments. API explained that an operator contracts with the vendor for a specific service that is part of an overall integrity assessment. API also expressed concern that increased demand for inspection services would likely affect the time in which tool vendors deliver the reports. API stated that it is unlikely that operators will be able to meet the deadlines for every tool run and for every type of tool, as many types of tools are on the leading edge of development. API suggested that the rule: require review of integrity tests and inspections (rather than assessments); provide for integrating other appropriate data with the inspection/test results; and allow for a delay in schedule beyond the specified deadlines as long as an operator provides a reasonable explanation for the delay. Tosco commented that the two separate time periods is confusing; that if assessment of inspection results must be accomplished within 120 days, it is not clear what additional evaluation is required within 90 days of obtaining the report of an inspection. Response: We wish to note: an integrity assessment should not be confused with an integrity management program. Integrity management applies to the entire pipeline. It is a process that uses the information from an integrity assessment, in conjunction with the periodic evaluation and information analysis, to better manage the risks posed to each pipeline segment that could affect a high consequence area. Assessment is only one part of an operator's integrity management program and applies only to the line pipe. In the integrity management rule an assessment is required as a baseline and then required, periodically, every five years to ascertain the condition of the line pipe in each pipeline segment that could affect a high consequence area. To perform this assessment an operator has a choice of technologies: hydrostatic testing; internal inspection devices; or other technology. The rule clearly states that it is the operator's [[Page 1654]] responsibility to perform the required baseline and periodic assessments. Integration of information is a critical part of an operator's integrity management program. An operator must conduct periodic evaluations, which are to include evaluating data from the information analysis. The evaluations must be conducted as frequently as needed to assure pipeline integrity, not just when an assessment is done. Thus, the rule leaves it to each operator to best determine the frequency for evaluating its pipelines. We further expect an operator to structure its program to bring the necessary information together at the appropriate time. The requirement that an operator obtain and analyze an integrity assessment report by a specified time was intended to prompt an operator to obtain a timely report so that it could begin the repair of pipeline integrity-threatening conditions. However, after further analysis of this requirement we believe its implementation would be confusing and likely result in endless disagreements between operators and enforcement personnel. For example, an operator might have a condition on its pipeline that falls into the 60-day category. It could be argued that discovery occurred when the operator received a preliminary report of its integrity assessment, and that the operator was required to remediate the condition within 60 days after it received the report. However, the operator is supposed to have 120 days to review and analyze a preliminary report. Thus, there could be disagreement over whether the 60-day requirement negated the period for review and analysis, or whether the period for initial review and analysis gave the operator an additional 120 days before it was required to remediate the condition. Furthermore, we realized that the intent of this provision is to ensure an operator promptly addresses anomalous conditions on its pipeline, not to create disagreements about when an operator receives a report, reviews the report, and whether the report was a preliminary or final report. Rather than create a potential compliance and enforcement nightmare, we eliminated this provision from paragraph (h). Instead, we rewrote the provision (see discussion on discovery above) to give the operator flexibility in what information it uses, and what analysis it needs to discover a condition. Now an operator must promptly obtain sufficient information about a condition to make the determination that the condition presents a potential threat to the integrity of the pipeline. However, the obtaining of this information can take no longer than 180 days after an integrity assessment. 180 days after an integrity assessment, is considered sufficient time for an operator to obtain a report and any other information the operator needs to determine that a condition may present a threat. In limited instances, an operator may be able to demonstrate that the 180-day period is impracticable. By having a performance-based requirement, yet establishing an upper limit on when discovery can occur, it should be clearer to an operator on how to comply. It should also be clearer to determine when there is a violation, for enforcement purposes. The revised provisions ensure that an operator takes prompt action following an integrity assessment to remediate anomalous conditions and encourage operators to use sophisticated and developing technologies, because the operator will not be dependent on the report from the vendor. 5. Section 195.452(h)(4)--Schedule for repairs: This paragraph required an operator to complete repairs according to a schedule that prioritizes conditions for evaluation and repair. The schedule was based on risk factors used for establishing the baseline and continual integrity assessment schedules. An operator would be allowed to notify RSPA/OPS when it could not meet the schedule and provide a justification for the delay. Notice was to be sent to the address in Sec. 195.58 or to the facsimile number in Sec. 195.56. API recommended the reference to the risk factors be deleted because the factors are appropriate for establishing re-inspection intervals but not for prioritizing mitigative actions. Tosco questioned, in the event an operator could not meet its schedule, whether the notification required should also be sent to the appropriate State agency in those States that are certified under Section 60105 of the Federal Pipeline Safety Statute. Tosco also noted that because Sec. 195.58 applies to subpart B and Sec. 195.56 applies to Safety Related Condition reports, we should reference the integrity management notification in these sections. Response: It is likely the results of an integrity assessment will be the principal basis for scheduling a condition for remediation. These results will generally indicate the significance of anomalies so operators can establish their relative importance for remediation. However, RSPA recognizes that there may be other factors an operator needs to consider in prioritizing the conditions for remediation, and agrees that requiring an operator to base its schedule on risk factors is unnecessary. We deleted this requirement from the rule and will leave it to the operator to determine how best to set up a schedule for evaluation and remediation of conditions identified from the assessment. Of course, an operator must document the basis for how it prioritizes conditions in its schedule. As for where an operator is to send a notification when it is unable to meet its schedule, the language clearly provides the address and facsimile numbers for sending the notification. Although we see no reason for confusion about where to send a notification, we added a new paragraph (m) to the integrity management rule that contains the address and facsimile number for sending notification. This paragraph now contains the current room number and facsimile number for sending any notification required by Sec. 195.452. The rule continues to require operator notification to RSPA/OPS. We will then ensure that the relevant Regional office receives the notification for forwarding to a certified State. Having the notification come to RSPA is consistent with the filing of other reports, such as the safety-related condition report and accident report. As RSPA plans to keep a data base of notifications, it is most practicable for it to be the notified agency rather than State safety agencies. It also prevents a burden to operators of trying to determine which agencies should be notified. Requiring all notifications under the Integrity Management rule first come to RSPA/OPS, eliminates any potential confusion about where a notification should be sent. When a certified State adopts the integrity management regulations, it may also add a requirement for notification by intrastate hazardous liquid operators. 6. Section 195.452(h)(5)--Special requirements for scheduling repairs: This paragraph provided a list of certain conditions that require either immediate repair, repair within 60 days, or repair within six months. This paragraph also listed other conditions an operator would be required to evaluate and repair, but did not specify the time frame. Although not directly affected by this rulemaking, Enron maintained that the prescriptive time frames for certain conditions were not appropriate for the conditions, forcing operators to seek extensions. Enron further commented [[Page 1655]] that the descriptions of the conditions were open to interpretation. Immediate repair conditions: This subparagraph provided a list of conditions that require immediate repair. An operator is further required to temporarily reduce operating pressure or shut down the pipeline until the operator could complete the repair, basing the temporary operating pressure reduction on remaining wall thickness. API acknowledged that the conditions we listed as immediate repair conditions are those where the indicated anomaly may suggest the potential for imminent failure. However, API objected to limiting an operator's actions to address these conditions to repair of the condition. API recommended renaming these immediate concern conditions, and allowing an operator to take actions other than repair. API gave the example of a pipeline over-designed for wall thickness, as able to remain in service at very low pressure and not subject to imminent failure, even with metal loss greater than 80 percent of nominal wall thickness. API further stated that limiting an operator's discretion on reducing operating pressure to remaining wall thickness may be inappropriate in many situations (e.g., dents with indicated metal loss) and supported by engineering calculations. API suggested that the original wall thickness in some pipelines may have been above that needed to contain current maximum operating pressure, and recommended basing pressure reduction on an engineering assessment that includes all the potential factors that may contribute to pressure containment. Chevron recommended we remove the condition of ``dents on the top of the pipeline with any indicated metal loss'' from the immediate repair category. Chevron agreed such dents may be serious, but contended there is insufficient data to prove that these types of anomalies are of immediate concern. Chevron also believed an immediate repair requirement related to such anomalies would be difficult to meet because corrosion internal inspection tools do not always identify such dents, and those vendors that claim the tools can identify such dents cannot correctly size and identify them. Chevron recommended we place these types of anomalies in the 60-day category, and reword the anomaly description to include known topside dents that exceed 6 percent of the nominal pipe diameter with any (emphasis in the original comments) indicated metal wall loss. In addition, Chevron recommended RSPA work with industry to develop a pressure calculation that will determine the level of pressure reduction required (dependent on the size of the dent) to operate the pipeline safely. Response: We allowed an operator latitude in how it addresses most conditions, by changing the word repair to remediate throughout paragraph (h). However, we firmly believe that certain conditions, due to the immediate threat they pose to a pipeline's integrity and to a high consequence area, are best addressed by repair. We continue to list these conditions as ``Immediate repair conditions.'' An operator must repair these conditions; and until the repair is completed, either reduce operating pressure or shut down the pipeline. We agree that a situation might exist where an over designed pipe segment operating at a lower pressure could withstand maximum operating pressure, even with 80% wall loss. However, we find it unacceptable for an operator not to immediately repair a segment of pipeline where less than 20 percent of original wall thickness remains. Wall loss exceeding 80% indicates something significant is occurring on the pipeline. We also do not agree with Chevron's suggestion that ``dents on top of the pipeline with indicated metal loss'' do not require immediate repair because they are hard to identify. We acknowledge current inspection techniques may not readily identify dents with metal loss. The rule does not require an operator to identify such conditions. The rule simply specifies that when such conditions are identified, an operator must repair them immediately. This type of dent is also classified as an immediate concern in the most recent draft of API- 1160, ``Managing System Integrity for Hazardous Liquid Pipelines.'' Therefore, we are not removing this condition from the list of immediate repair conditions. The reduction in operating pressure, or the shutdown of the pipeline, provides an additional margin of safety. This requirement is consistent with Sec. 195.401(b). This established regulation requires an operator to correct conditions that could adversely affect safe operations in a reasonable time and not operate the affected part of the system until the condition is corrected, if it is of such a nature that it presents an immediate hazard to persons or property. We agree that pressure reductions should be based on an engineering evaluation, and changed the final rule accordingly. Although it is appropriate to base the pressure reduction on the remaining wall thickness for corrosion, this may not be the best method on which to base a pressure reduction for dents and gouges. We modified the requirement so that an operator must calculate the temporary reduction in the operating pressure using the formula in section 451.7 of ASME/ ANSI B31.4. In response to concerns about the rule confusing the role of vendors with that of operators, we clarified the language in one of the listed conditions concerning the person responsible for making certain determinations about a condition. We revised the language so that now it is the person designated by the operator to evaluate assessment results, who is to determine whether an anomaly requires immediate action. 60-day conditions: As proposed, this paragraph required an operator to schedule for evaluation and repair all dents (other than those listed as immediate repair conditions), regardless of size, located on the top of the pipeline (above the 4 and 8 o'clock position) within 60 days of discovery of the condition. API agreed with placing special emphasis on investigating anomalies that represent potential excavation damage on the top of the pipe. However, API contended that requiring repair of any topside dent, regardless of size, would preclude operators from making appropriate engineering judgments about anomalies that differ in character and risk profile from one pipeline to another. API contended that increasing sensitivities of inspection tools could result in ``hundreds or even thousands'' of topside line indications, only some of which will be a result of third-party damage. (Colonial and Chevron made the same comment). To better focus resources on areas of highest risk, API recommended we specify dents that are in excess of three percent of pipeline diameter and are located in a high population or other populated area, as 60-day conditions and include remaining dent-type defects as 6-month conditions. API believes this conservatively reduces by half the ASME B31.4 provisions, which require removal or repair of dents exceeding a depth of six percent of nominal diameter. API explained that the focus on high population areas and populated areas is appropriate because third-party activity is more likely to occur in these areas. (Chevron recommended these same changes). API further recommended excluding dents less than 0.25 inches for small diameter pipe (less than NPS 12) to recognize mill imperfections that fall within manufacturing tolerances. API maintained that operators have [[Page 1656]] conducted verification digs on many such small defects identified by past in-line inspections to demonstrate that these indications do not threaten pipeline integrity. Colonial reported in its experience, in-line inspection identified hundreds of bending shoe marks, smooth dents, and minor mill imperfections that fall within manufacturing tolerances. However, Colonial found these indications to be neither injurious to the pipeline nor the result of third-party damage. Colonial suggested that increased focus on these indications would result in dilution of resources and diversion of attention from higher risks. Colonial recommended we exclude ``smooth dents, bending anomalies, and mill defects that may be identified through en","truncated":true,"body_characters":81977}