1220 L St., NW Washington, DC Washington, DC January 8, 2016

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1 Robin Rorick Andrew J. Black Group Director, Midstream President & CEO & Industry Operations Association of Oil Pipe Lines American Petroleum Institute 1808 Eye St., NW 1220 L St., NW Washington, DC Washington, DC U.S. DOT Docket Management System Docket No. PHMSA U.S. Department of Transportation West Building Ground Floor Room W New Jersey Ave., SE Washington, DC January 8, 2016 RE: Comments of the American Petroleum Institute and the Association of Oil Pipe Lines on Notice of Proposed Rulemaking, Pipeline Safety: Safety of Hazardous Liquid Pipelines : Docket No. PHMSA The American Petroleum Institute ( API ) 1 and the Association of Oil Pipe Lines ( AOPL ) 2 (collectively, API and AOPL or the Associations ) hereby submit comments in response to the Notice of Proposed Rulemaking ( NPRM ) issued by the Pipeline and Hazardous Materials Safety Administration ( PHMSA ) on October 13, 2015, in the above-referenced proceeding. 3 API and AOPL members are dedicated to continuous improvement in pipeline safety, and therefore, appreciate the opportunity to submit comments on the proposed regulations to address pipeline safety in several areas. The pipeline industry is committed to protecting the health and safety of its workers, neighbors, customers, and the communities through which crude oil, refined petroleum, and other products are shipped. Pipeline operators work diligently to construct, operate and maintain their facilities safely, reliably, and with a goal of zero incidents. API and AOPL value and 1 API is the national trade association representing all facets of the oil and natural gas industry, which supports 9.8 million U.S. jobs and 8 percent of the U.S. economy. API s more than 625 members include large integrated companies, as well as exploration and production, refining, marketing, pipeline, and marine businesses, and service and supply firms. They provide most of the nation s energy and are backed by a growing grassroots movement of more than 25 million Americans. Together, API and AOPL members operate approximately 90% of the hazardous liquids pipeline miles in the United States. 2 AOPL is a national trade association that represents owners and operators of oil pipelines across North America and educates the public about the vital role oil pipelines serve in the daily lives of Americans. AOPL members bring crude oil to the nation s refineries and important petroleum products to our communities, including all grades of gasoline, diesel, jet fuel, home heating oil, kerosene, propane, and biofuels Fed. Reg (Oct. 13, 2015). 1

2 appreciate many aspects of PHMSA s rulemaking as it is intended to improve pipeline safety and provide additional regulatory certainty for our members. Although the Associations do not oppose certain additions and modifications proposed in the NPRM, there are aspects of the proposed rule that require comment. On December 10 and December 15, 2015, PHMSA held one-hour webinars on the NPRM. In addition to a PHMSA staff-led presentation regarding the proposed rule, PHMSA invited webinar attendees to pose clarifying questions to PHMSA staff. API, AOPL, and some of their members participated in these webinars, and appreciate the clarifications provided on certain aspects of the proposed regulations. However, specific proposals were not addressed during the webinars, and therefore, the Associations intend to submit comments on the areas where the proposed rule still requires specificity. Also, to the extent that some of PHMSA s responses clarified language or requirements that may be somewhat ambiguous in the NPRM, the Associations request that PHMSA reflect those clarifications in the final rule. The Associations request that PHMSA ensure that the proposed regulations do not: pose additional, unintended safety risks for pipeline personnel; fail to incorporate the proven application of good engineering judgment and the consideration of facts and science in operating pipelines with integrity; ignore valuable advancements in the science and technology of pipeline integrity management; improperly analyze the benefits and costs of the proposed rules; or, impose new requirements without careful understanding of their integration with existing pipeline regulations and the operational feasibility of the proposed rules. We respectfully request that PHMSA issue a final rule consistent with the comments and recommendations below. I. Reporting Requirements and Forms on Gravity and Rural Gathering Lines Must be Narrowly Tailored to their Purpose A. Reporting for Gravity Lines Should Advance the Agency s Evaluation of Existing Federal and State Regulations The NPRM proposes to extend certain reporting requirements to all gravity lines 4 to assist in determining whether the existing federal and state regulations for these lines are adequate. 5 The language in Section II of the NPRM proposes to require that operators of all gravity lines comply with requirements for submitting annual, safety-related condition, and incident reports. 6 During the webinar held on December 10, PHMSA indicated that the safety-related condition[s] to be reported by operators were those contained in Section While the Associations appreciate the reference to Subpart B in the regulatory text, API and AOPL propose that PHMSA use the following language, with new language indicated in bold, at Section (b) in the final rule to serve PHMSA s expressed objective: Comply with the reporting 4 Id. at Id. at Id. at

3 requirements in of Subpart B, Sections through and (a) (d). The suggested language is fully consistent with the statement made in the webinar that National Pipeline Mapping System reporting under Section would not be required for gravity lines. B. Reporting Forms for Gravity Lines Should Enable Accurate and Precise Data Gathering The Associations recommend that PHMSA create a new abbreviated accident report form for pipelines not currently subject to 49 C.F.R. 195, that requests operators report only that information relevant to those pipelines. For example, pipelines not currently covered under Part 195 are not subject to Operator Qualification, Control Room Management, Leak Detection, and High Consequence Area requirements, and therefore those areas should be excluded from reporting. API and AOPL also recommend that PHMSA create a new abbreviated annual report with input from operators to segregate the reporting of pipeline data for regulated pipelines and those not currently subject to 49 C.F.R Again, the form would only require operators to report that information pertinent for those lines. An abbreviated report form that includes only information relevant to gravity lines would advance PHMSA s stated goal of analyzing the safety performance and risk by collecting only basic information of those lines. The report form would also relieve any unnecessary burdens that would potentially be placed on operators by reporting information that is not pertinent to gravity lines. C. The Scope of Reporting for Gravity Lines Should be Tailored to Risk In the comments submitted in response to the ANPRM, API and AOPL expressed support for maintaining the gravity line exception, given that these lines generally are short in length, pose limited safety risks, and are typically located within other regulated facilities, such as tank farms. API and AOPL recognize that certain gravity lines are longer, and do not oppose data collection for these lines to assess the safety performance and risk of these lines, but request that PHMSA not impose the proposed reporting requirement on more limited gravity lines. Therefore, API and AOPL propose that the data collection be narrowed, such that it would apply only to those gravity lines that: 1) travel outside of facility boundaries for at least one mile; 2) operate at a specified minimum yield strength level of twenty percent or greater; and 3) are not otherwise exempted in Section 195.1(b). API and AOPL oppose the inclusion of intra-facility and tank farm gravity lines in the proposed regulation because these lines generally exist wholly inside facility boundaries or move product between facilities within close proximity. Containment features, such as berms, limit the ability of a facility release to impact the public or the environment. Moreover, these lines operate at a very low pressure. Therefore, in recognition of the reduced risk of these assets, they should not be subject to the proposed requirements. D. The Implementation Period Should be Extended The proposed regulatory language requires operators of gravity lines to comply with the subpart B reporting requirements by a date six months after the effective date of the final rule. 7 7 Id. at

4 API and AOPL respectfully request that PHMSA extend the proposed implementation period to one year after the effective date of the final rule. As these lines were not previously regulated, operators will need to undertake a review of voluminous documents, dating back decades in some instances, in order to compile historical data. The additional time will provide operators with an opportunity to collect the necessary information and integrate the new information into their existing practices for information collection and reporting to be responsive to the proposed requirement. E. Reporting Rural Gathering Lines Should be Tailored to Collect Basic Data for Safety Performance and Pipeline Risk The NPRM proposes to extend certain Part 195 reporting requirements to all hazardous liquid gathering lines. 8 The proposed regulatory language of Section 195.1(a)(5) seeks to require operators to comply with requirements for submitting annual, safety-related condition, and incident reports. During the webinar held on December 10, PHMSA indicated that the safety-related condition[s] to be reported by operators were those contained in Section While the Associations appreciate the reference to Subpart B in the regulatory text, API and AOPL propose PHMSA use the following language, with new language indicated in bold, in the final rule at Section 195.1(a)(5): For purposes of the reporting requirements in subpart B of this part, any gathering lines not already covered under paragraphs (a)(1), (2), (3), or (4) of this section comply with the reporting requirements of Subpart B, Sections through and (a) (d). The suggested language is fully consistent with the statement made in the webinar that National Pipeline Mapping System reporting under Section would not be required for gathering lines. F. Reporting Forms for Gathering Lines Should Enable Accurate and Precise Data Collection The Associations recommend that PHMSA create a new abbreviated accident report form for those pipelines not currently subject 49 C.F.R. 195 that requests operators to report only that information relevant to those pipelines. For example, those pipelines not covered by Part 195 are not subject to Operator Qualification, Control Room Management, Leak Detection, and High Consequence Area requirements, and therefore those areas should be excluded from reporting. API and AOPL also recommend that PHMSA create a new abbreviated annual report with input from operators to segregate the reporting of pipeline data for regulated and unregulated pipelines. Again, the form would only require operators to report that information pertinent for those lines. An abbreviated report form that includes only information relevant to rural gathering lines would advance PHMSA s stated goal of analyzing the safety performance and risk by collecting only basic information of those lines. The report form would also relieve any unnecessary burdens that would potentially be placed on operators by reporting information that is not pertinent to rural gathering lines. 8 Id. at

5 G. The Implementation Period Should be Extended Since gathering lines were previously not regulated at the Federal level, operators may not have the information available to comply with the proposed data collection in the timeframe proposed by PHMSA, if at all. The proposed regulatory language requires operators of rural gathering lines to comply with the subpart B reporting requirements by a date six months after the effective date of the final rule. 9 API and AOPL respectfully request that PHMSA extend the proposed implementation period to one year after the effective date of the final rule. As these lines were not previously regulated, operators will need to undertake a review of voluminous documents, dating back decades in some instances, in order to compile physical pipeline data. The additional time will provide operators with an opportunity to collect the necessary information and integrate the new information into their existing practices for information collection and reporting to be responsive to the proposed requirement. H. PHMSA s Gathering Line Cost Analysis is Inaccurate During the comment process, API and AOPL have received several examples of how the aggregate industry cost of $22.4 million provided in the NPRM is not accurate. In fact, industry experience illustrates that the cost and time burdens associated with the proposed requirements for gravity and rural gathering lines alone greatly exceed the aggregate cost estimate cited by PHMSA in the NPRM. One operator recently identified and mapped its gathering lines to obtain centerline data only; that is, their effort did not include efforts to collect detailed information about the lines (e.g., pipe specifications, pipe grade, specified minimum yield strength, etc.,). The effort cost about $1,000 per mile and averaged a timeframe of one month per one hundred miles. The operator reports that it has only a few hundred miles of gathering lines. In the NPRM, PHMSA stated that there are approximately 30,000 to 40,000 miles of onshore hazardous liquid gathering lines in the United States. Extrapolating the cost data provided by the operator and the mileage estimate supported by PHMSA, identifying and mapping gathering lines for onshore hazardous liquid gathering lines would, at a minimum, cost $30 million. Based on this information, the cost of collecting centerline data alone will far exceed the $22.4 million estimate provided by PHMSA. The inaccurate cost burdens associated with this proposed requirement are also illustrated with data from API s Pipeline Performance Tracking System, which is a voluntary initiative that provides meaningful data that allows operators throughout the industry to identify leading indicators and learn from them to prevent safety incidents. According to those operators contributing to the PPTS data for 2014, there are a total of 7,106 miles of gathering lines not subject to Part 195. PHMSA reported a total of 3,794 miles of regulated gathering lines in Assuming the same figures as above, mapping and identifying these gathering lines for centerline data alone would cost nearly $11 million, and these numbers cited are lower than the estimate of total gathering line mileage in the NPRM. 9 Id. at

6 II. The Proposed Rules for Inspections of Pipelines in Areas Affected by Extreme Weather, Natural Disasters, and Other Similar Events Are Duplicative and Demand More Careful Definition In the NPRM, PHMSA proposes to amend its regulations to require additional inspections of pipelines within 72 hours after the cessation of an extreme weather event such as a hurricane or flood, an earthquake, a natural disaster, or other similar event. 10 API, AOPL, and industry stakeholders are committed to the goal of zero incidents, as well as the safe operation of pipelines both during and after extreme weather events to ensure adequate protection of the public and the environment, as well as pipeline assets. A. Rules Should Avoid Redundancy with Existing Federal Rules for Pipeline Abnormal Operations and Emergencies API and AOPL are concerned with how the proposed inspections relate to the existing emergency response regulations. Pursuant to Section , pipeline operators are currently required by Federal law to prepare a manual of written procedures for conducting normal operations and maintenance activities, as well as handling abnormal operations and emergencies. The remedial actions outlined in proposed Section (d) are duplicative of what is currently required of operators in their emergency response plans. Under Section (e), operators manuals must include procedures to provide safety when an emergency (including natural disasters affecting pipeline facilities) occurs and provide for prompt and effective response. 11 For example, Section (e)(4) requires operators to take necessary actions such as, emergency shutdown or pressure reduction, to minimize the volume of hazardous liquid or carbon dioxide that is released from any section of a pipeline system in the event of a failure. One of the remedial actions proposed in Section (d) would require operators to reduce the operating pressure or shut down the pipeline if appropriate, which mirrors the language of Section (e)(4). Similarly, proposed Section (d)(5) would require operators to implement emergency response activities with Federal, State, or local personnel, which is nearly identical to the language in Section (e)(7). Therefore, operators already address and complete many of the remedial actions proposed by PHMSA in their emergency response plans. As a result, API and AOPL believe the proposed language is duplicative and should be modified to only include those actions that are not addressed in Section (e). Alternatively, if explicit changes are needed to address extreme weather events, API and AOPL request that PHMSA modify Section (e)(4) by adding the three newly proposed remedial actions that are not currently included in that section: modifying, repairing, or replacing any damaged pipeline facility; preventing, mitigating, or eliminating any unsafe condition in the pipeline right of way; and perform additional patrols, surveys, tests or inspections. 10 Id. at C.F.R (e). 6

7 B. Definition of the Conditions Triggering Extreme Weather Events Must be Explicit and Relative to Pipeline Risk API and AOPL note that the weather events specifically identified by PHMSA (i.e., hurricanes, floods, and earthquakes) are stated in broad terms, and the Associations request that PHMSA provide a specific definition of the parameters of those weather events that will necessitate a pipeline inspection upon cessation. The current language suggests that pipeline inspections will be required if any of the specified weather events occur, and does not take into account the nuances that accompany each of the above events. For example, hurricanes range in intensity and the potential for damage to persons and property varies based on designations assigned to a particular hurricane as measured by the Saffir-Simpson Hurricane Wind Scale ( Saffir-Simpson ). 12 Similarly, earthquakes vary in intensity based on the amplitude of the seismic waves produced, as measured by the Richter Scale. 13 Additionally, the current language does not recognize the nuances in the particular physical design and construction of a pipeline in the area of the potential exposure. Such particular design and construction characteristics might, in and of themselves, mitigate the exposure or risk. Further, given the variation that exists in the type and severity of weather events, the Associations request regulatory clarity on how PHMSA will define a flood. For example, what amount of rainwater accumulation, and in what circumstances, would constitute a flood? According to the National Flood Insurance Program, a flood occurs when two or more acres of normally dry land, or two or more properties, are inundated by water or mudflow. 14 The flood event is not in itself a pipeline integrity risk, but could be so in conjunction with other characteristics, such as very high water flow velocity, volume, etc. Large rainfall that is easily handled in some areas because of terrain or collection infrastructure can overwhelm other areas. API and AOPL stand ready to work with PHMSA on achieving the intended goal of the proposed regulation, but request that PHMSA specify as to whether there are definite conditions that would trigger an inspection by a pipeline operator, or if the simple occurrence of a specified event itself would trigger an inspection. The Associations further request recognition in the final rulemaking that many of these events, due to variables like intensity or duration of the event, geographic region affected, assets located in the affected areas, and design capacity of the pipeline assets to withstand the conditions of the extreme events, will potentially have widely disparate impacts on pipeline assets and operators. 12 Saffir-Simpson Hurricane Wind Scale, NAT L HURRICANE CTR (May 24, 2013, 2:19 p.m.) The Saffir-Simpson scale measures sustained wind speed and the potential for damage that may be caused due to hurricane winds. 13 Measuring Earthquakes, U.S. GEOLOGICAL SURVEY (Jan. 11, 2013, 11:12 a.m.) Earthquakes with a Richter value of 6 or more are commonly considered major, while great earthquakes have a magnitude of 8 or more on the Richter scale. 14 Flooding and Flooding Risks, Nat l Flood Ins. Program (Nov. 2, 2015, 8:30 a.m.) 7

8 C. Regulatory Ambiguity of Other Similar Events is Inadequate to Instruct Pipeline Operators When Inspections/Remedial Actions are Required API and AOPL are also concerned with the ambiguity of certain phrases in the proposed regulatory language. Proposed Section (a) references other similar event[s] in listing the extreme weather that would require an inspection by pipeline operators. That language could be interpreted to include any number of events, including events that have no historic nexis to significant pipeline incidents, such as tornadoes, wildfires, mudslides, blizzards, etc. Regulatory clarity is necessary to alert operators on the circumstances that PHMSA expects would indicate potential damage to facilities. API and AOPL suggest that PHMSA consider adopting a standard for other similar events, such as other similar events with a significant likelihood of damage to infrastructure. D. The Inspection Standard Articulated by PHMSA Must be Feasible The Associations understand the standard of proof for the inspections required in this proposed section is operator assurance that no conditions exist that could adversely affect the safe operation of that pipeline upon inspection of all potentially affected pipeline facilities. API and AOPL support PHMSA s stated purpose of these inspections, 15 which is to find and remediate any conditions that may pose a threat to the public and the environment. However, the standard of ensuring that no conditions exist is overly broad and potentially impossible for operators to demonstrate. API and AOPL agree with the need to conduct inspections to identify and remediate any adverse conditions that exist, but the standard required of operators must be feasible. The Associations recommend the proposed text at Section (a) be modified, with new language indicated in bold, as follows: an operator must inspect all potentially affected pipeline facilities to detect conditions that could adversely affect the safe operation of that pipeline ensure that no conditions exist that could adversely affect the safe operation of that pipeline. E. Cessation of a Weather Event Should be tied to Protection of Public Safety API and AOPL request that PHMSA make clear that operators have discretion to determine the cessation of a weather event (i.e., the beginning of the timeframe within which operators must complete their inspection) in order to protect public safety. Cessation is defined as a stopping of some action. 16 Implicit in that definition is the fact that cessation of the event itself could be temporary. Rather than simply focusing on the cessation of a weather event, which may be difficult to determine, the Associations suggest that the regulation should instead focus on performing inspections once it is safe to access the area. In order for operators to comply with obligations under the proposed rule and protect public safety, including the safety of their own personnel, API and AOPL recommend that PHMSA define cessation as the point F.R Cessation Definition, MERRIAM-WEBSTER.COM, (last visited Nov. 5, 2015). 8

9 in time when no further threats to personnel safety or equipment exist in the affected area, allowing for safe access by pipeline personnel and equipment. F. The Final Rule Should Reflect the Fact that Inspections May Need to Exceed 72 Hours 1. Operators should be allowed to document when 72 hours is inadequate The Associations are also concerned with the feasibility of conducting inspections within the 72-hour timeframe. 17 Inspecting to detect conditions that could adversely affect the safe operation of that pipeline is a standard that will potentially require operators to perform various tests, the results of which may not be available within 72 hours. API and AOPL request that PHMSA recognize other potential obstacles to the 72-hour window proposed by PHMSA. Underground pipe poses greater challenges for inspection than above-ground pipe. Inspections may need to include more time and resource intensive direct assessments or ILI to assure pipeline integrity. It may not be feasible to complete the inspection in 72-hours depending on the length of the pipeline and the size of the affected area. API and AOPL recommend that additional time be allowed if an operator determines that the required inspection method cannot be completed within 72-hours with documentation to support the time extension. API and AOPL are ready to work with PHMSA to mitigate, to the extent practicable, threats to the public and the environment following an extreme weather event, but request that operators be allowed additional time if an operator determines that the proposed standard cannot be met within 72- hours. Operators would record the reasons for the delay and maintain that information with the inspection records. 2. Third-party technology and expertise may not be available within 72 hours In addition to the safety of operator personnel responsible for inspecting any potentially affected facilities, another potential obstacle to the proposed timeframe is the availability of resources to complete an inspection after an extreme weather event. Multiple operators may have assets located in the same geographic area that will need to be inspected after an extreme weather event. As a result, operators may be forced to compete for access to third-party resources necessary to complete an inspection, in which case the 72-hour timeframe would undermine the safety objectives contemplated by the agency in this rulemaking. The Associations ask that PHMSA acknowledge the very likely potential for inspections to exceed the 72-hour proposed timeframe due to the limited availability of third-party resources in the final rulemaking. 3. Public and pipeline worker safety is paramount API and AOPL appreciate that PHMSA, in articulating the timeframe allotted to complete the proposed inspections, included language that acknowledges that the safety of pipeline personnel is an important consideration. The proposed regulatory language directs 17 The recent Mississippi flooding events highlight the difficulty of imposing an inspection requirement within 72 hours of cessation. The rain in this case was of an unprecedented volume within a very short period of time. The resulting floods and flow have grown and peaked over a week timeframe. The ability of operators with assets in that area to inspect pipelines crossing the river may potentially be limited for weeks, until water levels flow and subside. 9

10 operators to complete post-extreme weather event inspections within 72 hours after the cessation of the event, or as soon as the affected area can be safely accessed by the personnel and equipment required to perform the inspection 18 The Associations interpret that language to mean PHMSA is providing operators with discretion to determine when an affected area following an event can be safely accessed by personnel and equipment if threats to personnel safety exist after the expiration of the 72-hour window following the cessation of the event itself. However, consistent with the Associations proposed definition of cessation discussed above, the 72-hour window to perform the inspection would only commence once personnel and equipment could safely access the affected area. Operators are committed to safety, not just of the public and the environment, but also those employees who would be putting their personal safety at risk to inspect potentially affected pipeline facilities for the good of the communities in which they operate. We appreciate that PHMSA included language that protects all interested parties, and commend the agency for recognizing that threats to personnel safety may not quickly dissipate following the conclusion of a severe weather event. By tying the 72-hour window to the time the affected area may be safely accessed, operators and their employees will work safely and expeditiously to complete inspections in a thorough and efficient manner to ensure that the public, the environment, potentially affected facilities, and operator personnel are protected. III. Require Periodic Assessments of Pipelines That Are Not Already Covered Under the IM Program Requirements A. Assessment Methods Should Not be More Stringent for Lower Risk Segments The NPRM proposes that operators must periodically assess pipelines outside of high consequence areas ( HCAs ). While potentially reasonable on the surface, the specifics of PHMSA s proposal would impose more stringent requirements for these lower consequence pipelines than are currently imposed under the integrity management program for HCA pipelines. API and AOPL are concerned that PHMSA s proposal represents a departure from prioritizing pipelines with the highest consequences to the public and environment and would divert safety resources to lower risk assets. Specifically, proposed Section would require operators to assess non-hca pipeline segments with an ILI tool or tools capable of detecting corrosion and deformation anomalies, including dents, cracks, gouges, and grooves 19 at least once every ten years. 20 If a segment is not capable of accommodating an ILI tool, an operator may use an alternative assessment method, provided it gives prior notice to PHMSA and demonstrates that the alternative methodology renders a substantially equivalent understanding of the pipeline s condition in light of the threats that could affect its safe operation. 21 PHMSA proposes requiring use of ILI tools for non-hca pipelines for all forms of potential pipeline anomalies, regardless of whether such issues are present in the pipeline. An impractical impact of this mandate would force operators to run a crack tool on a pipeline with Fed. Reg , at Id. 20 Id. 21 Id. 10

11 no history of or presence of risk factors for cracking, for example. By contrast, the current integrity management program for HCAs requires operators to evaluate each pipeline and select an assessment method most appropriate to address the potential threats specific to that pipeline, if any. In its current form, the proposed regulatory language implies that operators must assess non-hca pipelines for each of the enumerated anomalies regardless of whether threat indicators of those anomalies are present on the line. During the PHMSA-led webinar on December 15, an attendee posed a question to PHMSA staff requesting clarification on this very point. Specifically, the individual asked whether a tool capable of detecting a crack anomaly must be used during each assessment. The informal response suggested that operators historical data related to the pipeline may be used in determining whether a crack assessment is necessary. API and AOPL support operator use of historical data in making a determination of whether a pipeline must be tested for a crack anomaly or any other specific feature type (e.g., grooves). The rule, as proposed, does not apply this approach and would result in unnecessary tool runs on pipelines that do not pose threats of cracking. Additionally, as crack detection tools are very nuanced specialty tools, the demand generated by the rule as proposed would overwhelm the current supply of anomaly detection resources, and divert them from HCA or high risk segments of pipeline. B. PHMSA Should Clarify the Scope of the Proposed Rule The NPRM states that the proposed section applies to pipelines that are not subject to the integrity management requirements in The Associations believe that the agency s intent is to apply these regulations to transmission pipe only; however, the use of the term pipelines is misleading and overbroad. The definition of a pipeline in the current regulations means all parts of a pipeline facility through which a hazardous liquid or carbon dioxide moves in transportation, including, but not limited to, line pipe, valves, and other appurtenances connected to line pipe, pumping units, fabricated assemblies associated with pumping units, metering and delivery stations and fabricated assemblies therein, and breakout tanks. 23 The Associations do not believe that PHMSA is proposing that the regulations require operators to run ILI assessments on facility, station, and terminal piping, or breakout tanks. Therefore, the Associations request that PHMSA clarify that it intends for the requirements articulated in this regulatory proposal to include transmission lines only. C. Modifying the Proposed Rule Ensures Analytical Resources Match the Threat Indicators and PHMSA s Stated Intent As suggested at the December 15 webinar, with the aid of pipeline data, operators are best situated to determine whether a particular feature is a threat and necessitates a particular tool run. Accordingly, the Associations recommend that PHMSA amend the regulatory language proposed in Section (c) to include additional language, indicated by the bolded text, as follows: The assessment must be performed with an in-line inspection tool or tools capable 22 Id C.F.R

12 of detecting corrosion and or, if indicated as a threat by the historical data of the pipeline, deformation anomalies including dents, cracks, gouges, and grooves, unless an operator D. Both HCA and non-hca Assessments Should Include Hydrostatic Testing Alternatives PHMSA also proposes that operators perform non-hca assessments with ILI tools unless an operator demonstrates the pipeline segment is not capable of accommodating an ILI tool. An operator would not be allowed to satisfy the assessment requirement by performing a hydrostatic test of the line, even if appropriate for assessing the safety of that line, unless it can demonstrate that the line is not capable of accommodating an ILI tool. Such a one-size-fits-all approach for non-hca pipelines similarly departs from current HCA requirements to evaluate each pipeline and select an assessment method most appropriate for that pipeline. Therefore, the Associations request that the final rule make clear that operators may select the appropriate assessment method, just as they may with respect to the current HCA requirements. PHMSA s proposal, if left unmodified, would create unnecessary burdens on pipeline safety resources without a demonstrated commensurate safety benefit. PHMSA would require that operators run ILI tools even if assessments demonstrate the pipeline is not threatened by anomalies PHMSA mandated tool runs are designed to find. As there is no tool on the market currently that is capable of addressing each of the specified anomalies in one run, compliance with this requirement would require combination tools, multiple runs, or both. Therefore, PHMSA s proposal, as written, could result in potentially hundreds of additional unnecessary ILI runs for any one operator in a single year. Resources spent on unnecessary PHMSA-mandated ILI tool runs would not be available for protection of areas of high consequence to the public and the environment. E. Rule Language Should Reflect PHMSA Intent that Low Flow is Appropriate for Alternative Assessment Methodology During the first webinar convened by the agency on December 10, AOPL sought to clarify the circumstances under which an operator may show that a pipeline is not capable of accommodating an inline inspection tool. Specifically, AOPL asked whether the lack of accommodation standard that operators must demonstrate depends on factors relating to the basic construction of the pipeline (as articulated in the proposed repair criteria for HCA lines in Section (n)(4)), or operational factors, as no criteria are articulated in the language of the proposed rule. PHMSA staff indicated informally that factors relating to the basic construction of the pipeline (e.g., sharp bends and elbows), would be sufficient to utilize an alternative test method. Other operators asked follow-up questions relating to other factors that the agency would deem appropriate. Based on the staff answers, low flow in a pipeline would also be a circumstance warranting an alternative assessment methodology. Pipeline operators believe the approach of the current integrity management program for HCAs of tailoring assessment and inspection tools to the specific threats of the pipeline is both protective of safety and avoids unnecessarily burdening resources that could be used to protect pipeline safety elsewhere. API and AOPL request that PHMSA amend proposed Section 12

13 (c) to allow operators to apply the inspection technology most appropriate to the conditions of the pipeline and provide for alternative testing techniques through processes consistent with current regulation of HCA areas. The amendment would allow operators to evaluate each pipeline and select an assessment method most appropriate to address the potential threats specific to that pipeline, if any. The Associations ask that PHMSA acknowledge in the final rulemaking that each of the assessment methods afforded to HCA segments in Section (c)(1)(i) may be utilized in addition to hydrostatic testing for all non-hca lines, especially non-hca gathering lines. Industry stakeholders have indicated that the costs associated with making these lines ILI-capable could result in wells being shut in, as the modification costs would far outweigh the revenue from production. The changes proposed by the Associations align this section with the current Integrity Management rules by giving operators the same flexibility for choosing assessment methods based on each pipeline s unique characteristics and threats, if any. F. Implementation of Periodic Assessments Requires a Specific Phase-In Schedule Additionally, while the proposal provides a ten-year cycle for assessments, it does not specify when operators must perform the first assessment. As it is critical for operators to understand the timeframe in which they must complete the first assessment, API and AOPL request that PHMSA clarify that operators have a ten year period for completing the first assessment, with subsequent assessments occurring once every ten years or as otherwise necessary to comply with the public safety timeframe set by the proposal. G. The Cost/Benefit Analysis is Inaccurate 1. Offshore Pipelines Much of the offshore pipeline mileage that is regulated by PHMSA is non-hca mileage. Under the current language proposed by PHMSA, however, a majority of the offshore pipeline network would potentially be subject to an ILI assessment. Requiring ILI assessments for offshore pipelines would present particularly acute challenges due to factors such as heavy wall thickness (often over 1 inch), intense pressures at the seafloor, availability of space on platforms for accommodating longer smart tools, just to name a few. Projects that would normally be easily accomplished onshore (e.g., locating and retrieving a stuck pig) can become a highly complex and costly undertaking for an offshore pipeline. In addition, the limited number of vendors that currently have tools that can work under such extreme circumstances further compounds these challenges. The technology does not currently exist to perform an ILI inspection for some offshore pipelines. In addition to technical challenges, the costs associated with mobilization and execution of an ILI run offshore are exponentially greater than those for similar projects conducted onshore. The cost to perform ILI for offshore pipelines can outpace an ILI run for an onshore pipeline by a factor of 10 in certain instances. One operator estimates that executing an ILI assessment for offshore lines would cost approximately $1 million per segment. This same operator estimates that it has over thirty offshore segments that could potentially need to be 13

14 pigged if offshore lines were included in this requirement. The NPRM estimated that the cost for this proposal would be $16 million. Based on feedback from industry stakeholders, API and AOPL submit that the cost of this proposal per operator affected is estimated to be over $32 million, and that figure represents only the initial inspections. The cost data alone suggest that the single operator would incur costs that exceed the total industry aggregate cited by PHMSA in the NPRM. The Associations respectfully request, therefore, that PHMSA take into account the full cost impact of completing inspections on all of the non-hca pipelines in the final rulemaking. While PHMSA has indicated that pipelines that cannot accommodate an ILI may be approved for hydrostatic testing through prior notification, hydrostatic testing of offshore lines is also challenging and costly. Isolating a segment for a hydrostatic test often requires saturation diving in shallow water or the use of remotely operated vehicles (ROVs) in deep water to close valves (testing against closed valves is not optimal) or remove pipe spools with complicated piping work to facilitate assessments. Further, the removal of underwater pipe spools creates spill opportunities and would likely result in undesired hydrocarbon release to the environment. The logistics and preparation for a test can easily push the costs of an offshore hydrostatic test over the $10 million range, not including the lost production from shutting in the platform. Assuming only a handful of segments would require hydrostatic testing over ILI further pushes the incurred costs over the costs cited in the NPRM. While offshore pipeline operators are fully committed to pipeline safety and zero spills, the cost-benefit of requiring these inspections offshore is particularly difficult to justify when comparing these exceedingly high costs and technical challenges to the number of incidents that actually occur offshore due to causes targeted by these types of assessments. Of the 1887 pipeline incidents reported to PHMSA from , only 15 occurred offshore, releasing less than 90 barrels, with most of those barrels originating from a single release caused by outside force damage. This is less than 0.01% of the total incidents for this time period. And the incident rate is similarly low historically with most offshore pipeline failures coming from hurricane damage. Offshore operators request some provisions for engineering and risk based decisions regarding assessing offshore pipelines to prevent misdirecting disproportionate valuable resources from higher risk/higher consequence lines to very low risk/low consequence lines. With the exceedingly low incident rate and the different threat profile for offshore pipelines, API and AOPL request that PHMSA reflect the low safety improvement impact and high cost impact of completing inspections on offshore non-hca pipelines in the final rulemaking language. Specifically, the Associations request that PHMSA amend 49 CFR (c) as follows: (c) Method. The assessment required under paragraph (b) of this section must be performed with an in-line inspection tool or tools capable of detecting corrosion or, if indicated as a threat by the historical data of the pipeline, deformation anomalies including dents, cracks, gouges, and grooves, unless an operator: 14

15 (i) Demonstrates that the pipeline is not capable of accommodating an inline inspection tool; and that the use of an alternative assessment method will provide a substantially equivalent understanding of the condition of the pipeline; or and (ii) Demonstrates for an offshore line through historical data and a risk-based analysis that use of an alternative assessment method will provide a substantially equivalent understanding of the condition of the pipeline; and (iii) Notifies the Office of Pipeline Safety (OPS) 90 days before conducting the assessment by: (A) Sending the notification, along with the information required to demonstrate compliance with paragraph (c)(i) of this section, to the Information Resources Manager, Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue SE., Washington, DC 20590; or (B) Sending the notification, along with the information required to demonstrate compliance with paragraph (c)(i) of this section, to the Information Resources Manager by facsimile to (202) Idle or out of service pipelines In addition to the concerns highlighted above, the industry has many miles of pipelines that are currently not in service and, therefore, empty. The NPRM does not indicate whether the proposals contained therein would apply to those lines. The language, if left in current form, suggests that idle or out of service pipelines may be subject to the regulatory proposals contained in Section The Associations request that PHMSA clarify in the final rulemaking that operators need not run assessments on idle or out of service pipelines. These lines pose no risk to the environment or the public and conducting inspections on these lines would divert resources from areas that more immediately require operator attention. 3. Cost-Benefit Analysis: Gathering and Gravity Lines While the industry supports improving pipeline safety through inspection of the lines not currently in the Integrity Management Programs, it is worth pointing out that the cost-benefit analysis provided by PHMSA for this provision is neither accurate nor complete. In addition to the cost figures cited above for offshore pipelines, PHMSA does not examine the impact of the provision on gathering lines in its Regulatory Impact Analysis (RIA). Instead, PHMSA bifurcates pipelines into either 24-inch pipe or 8 to 10 inch pipe (RIA, page 56). PHMSA acknowledges that the smaller diameter pipes will likely undergo pressure testing, which according to PHMSA s estimates (Table 12) is considerably more expensive on a per mile basis than ILI testing. However, based on the pipe sizes provided, it appears PHMSA does not examine the costs for gathering lines, which are defined in Section as having an outside diameter of 8-5/8 or less. These costs could significantly impact the economic viability of the wells the gathering lines service, so it is imperative that this be considered. Moreover, PHMSA does not estimate whether the benefits for this class of pipelines are greater than the costs. Gathering lines may exhibit significantly different rates of incidents and volumes lost per incident than transmission lines. Good policy making requires that the costs and benefits of the rule on offshore and gathering lines be adequately examined. At a minimum, the final rule 15

16 should allow a longer implementation time to come into compliance to account for the uncertain nature of the ratio of costs to benefits. IV. Modify the IM Repair Criteria and Apply Those Same Criteria to Any Pipeline Where the Operator has Identified Repair Conditions In the NPRM, PHMSA proposed several changes to Sections and , which provide direction on anomaly repairs for non-hca and HCA lines, respectively. API and AOPL appreciate PHMSA suggesting changes to both the conditions requiring repair and the timing of their repair. Advances in inspection detection technology have greatly improved the industry s ability to detect and understand threats to pipeline integrity. Similarly, research on pipe metal strength and failure mechanics has broadened the industry s ability to predict the safety of pipeline operations more accurately. API and AOPL suggest the following changes to fully reflect these safety advances. A. General Considerations API and AOPL recommend that PHMSA repair conditions reflect advances in understanding metallurgy and fracture mechanics. In regards to calculating a predicted burst pressure for the purposes of determining remaining strength, selection of a suitable calculation method depends on several factors, including the failure mode of the anomaly. PHMSA should expand appropriate calculation methods to include, but not limited to: 1. For metal loss anomalies susceptible to failure in plastic collapse: ASME/ANSI B31G ( Manual for Determining the Remaining Strength of Corroded Pipelines (1991)) or AGA Pipeline Research Committee Project PR ( A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe (December 1989)). 2. For crack anomalies or selective seam weld corrosion (SSWC) associated with EFW and vintage ERW seams susceptible to failure from fracture: the Battelle Model (Modified Log-Secant), CorLAS or API 579 Part 9. Experience in detecting likely cracks and determining actual cracks provides a historical reference that operators can put to use analyzing potential crack defects. A likely crack is best defined as having a reasonable degree of confidence that the anomaly called by the ILI vendor correlates to a crack defect. This can be the case where the operator s previous experience on the present pipeline segment or other similar pipeline segment has found cracks or the case where the data integration indicates a strong likelihood that cracks could exist even though no historical data suggests so. Whereas a possible crack is defined as having a reduced certainty of being an actual crack and, when it is a crack, it occurs under different circumstances or the operator cannot determine with a high degree of confidence that the indication is not a crack defect. Similarly, PHMSA and the Associations below both seek to address potential anomalies that require further engineering analysis to determine fitness for purpose. API and AOPL believe qualified personnel should perform all such evaluations, based on sound engineering principles, providing adequate technical justification with supporting documentation by the operator. API and AOPL also seek to collaborate with PHMSA on establishing sufficient industry recognized 16

17 evaluation methods. API and AOPL propose adding the following language to the end of PHMSA s proposed new 49 CFR Pipeline Remediation. * * * * (f) Other Considerations. (1) In calculating a predicted burst pressure for the purposes of determining remaining strength, selection of a suitable calculation method depends on several factors, including the failure mode of the anomaly. Appropriate calculation methods include, but are not limited to: (i) For metal loss anomalies susceptible to failure in plastic collapse: ASME/ANSI B31G ( Manual for Determining the Remaining Strength of Corroded Pipelines (1991)) or AGA Pipeline Research Committee Project PR ( A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe (December 1989)); (ii) For crack anomalies or selective seam weld corrosion (SSWC) associated with EFW and vintage ERW seams susceptible to failure through fracture: the Battelle Model (Modified Log-Secant), CorLAS or API 579 Part 9; (iii) For dent anomalies: the safe working pressure can be determined using PRCI PR Safe Inspection Procedures for Dent and Gouge Damage (2010). (2) For purposes of this section, a likely crack is defined as having a reasonable degree of confidence that the anomaly called by the ILI vendor correlates to a crack defect. This can be the case where the operator s previous experience on the present pipeline segment or other similar pipeline segment has found cracks or the case where the data integration indicates a strong likelihood that cracks could exist even though no historical data suggests so. Whereas, a possible crack is defined as having a reduced certainty of being an actual crack and, when it is a crack, it occurs under different circumstances or the operator cannot determine with a high degree of confidence that the indication is not a crack defect. (3) For purposes of this regulation, an engineering analysis must include operator documentation and provide adequate technical justification for not completing repair or remediation of identified conditions within the specified timeframe. All evaluations must be performed by qualified persons, be based on sound engineering principles, and must account for the following factors at a minimum: (i) Dents: predicted flaw dimensions, material properties, tool tolerance, failure mode, operational pressure cycles, and predicted growth rate of corrosion and/or cracks. * * * * 17

18 B. Non-HCA Repairs at Section Pipeline Remediation. 1. Immediate Repair Conditions As discussed above, PHMSA s proposal to update regulations for repair of hazardous liquids pipelines affords PHMSA the opportunity to reflect advances in inspection detection technology and our improved ability to detect and understand threats to pipeline integrity. For example, API and AOPL suggest PHMSA strengthen the immediate repair criteria by adding a repair condition for likely crack anomalies greater than 70% of nominal wall thickness. This change would reflect the latest industry recommendations for repairing crack anomalies. API and AOPL also recommend PHMSA include criteria ensuring consideration of both metal loss features associated with plastic collapse and cracking that is considered a fracture mechanics feature. The changes recommended by API and AOPL regarding dent-related conditions avoids immediate criteria for anomalies that historically do not pose a near term risk of release. The application of clear criteria, the latest ILI capabilities, and understanding of remaining strength characteristics and fracture mechanics renders PHMSA s proposal requiring immediate repair of any indication of significant stress corrosion cracking (SCC) or selective seam weld corrosion (SSWC) unnecessary. API and AOPL agree with PHMSA s desire to ensure operators are appropriately mitigating the threat of SSWC or SCC. However, a requirement to immediately repair any indication of this type of these threats is overly broad and wasteful. Additionally, the significant designation is not representative of the technical severity of this anomaly, which is described by maximum depth or failure-pressure ratio, FPR. Finally, SSWC can be managed appropriately through the proposed immediate and 18-month criteria, which are based on the FPR treating suspected SSWC with a fracture mechanics model. Considering PHMSA s elevated concern for SCC, API and AOPL recommend that SCC reporting be considered for inclusion in the annual report. This addition will inform the regulator of the presence of detected SCC and will aid in PHMSA inspections, ensuring that they are aware of how the operator is managing the anomalies. The associations will gladly work with PHMSA on changes to the annual report to include notification of SCC in the appropriate places. As described above and provided through specific language below, API and AOPL propose PHMSA adopt a new criteria for likely crack anomalies greater than 70% of nominal wall thickness. Furthermore, API and AOPL propose a broadening of the potential approaches for calculating remaining strength of pipe. These changes appropriately address the concerns of SCC and SSWC, and also extend to longitudinal seam cracking mechanisms. Therefore, API and AOPL propose the following changes to PHMSA proposed 49 C.F.R (d)(1) and (2) (bold and strikeout reflecting additions and deletions, respectively): * * * * 18

19 (1) Immediate repair conditions. An operator must repair the following conditions immediately upon discovery: (i) Metal loss greater than 80% of nominal wall regardless of dimensions. (ii) Likely crack anomalies greater than 70% of nominal wall or of an indeterminate depth regardless of dimensions or the maximum depth sizing capabilities of the tool, as stated by the vendor s performance specification, where the depth cannot otherwise be established through correlation with previous ILI runs. (ii)(iii) A calculation of the remaining strength of the pipe shows a burst pressure less than 1.1 times the maximum operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, but are not limited to, ASME/ ANSI B31G ( Manual for Determining the Remaining Strength of Corroded Pipelines (1991) or AGA Pipeline Research Committee Project PR ( A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe (December 1989)) (incorporated by reference, see 195.3). (iii)(iv) A dent located anywhere on the pipeline that has any indication of metal loss, a gouge, cracking or a stress riser unless an industry recognized engineering analysis shows that it poses minimal risk to pipeline integrity. (iv)(v) A dent located on the top of the pipeline (above the 4 and 8 o clock positions) with a depth greater than 6% of the nominal pipe diameter unless an industry recognized engineering analysis shows that it poses minimal risk to pipeline integrity. (v) An anomaly that in the judgment of the person designated by the operator to evaluate the assessment results requires immediate action. (vi) Any indication of significant stress corrosion cracking (SCC). (vii) Any indication of selective seam weld corrosion (SSWC). (2) Until the remediation of a condition specified in paragraph (d)(1) of this section is complete, an operator must: (i) Reduce the operating pressure of the affected pipeline using an appropriate remaining strength calculation method specified in paragraph (d)(3)(iv) or; (ii) Shutdown the affected pipeline. * * * * 19

20 2. 18-month Repair Conditions PHMSA proposes a number of conditions on non-hca pipelines requiring repair within 18 months of discovery. API and AOPL are concerned PHMSA s proposed criterion in paragraph 49 CFR (d)(3)(iv) for remaining strength of pipe at an anomaly less than the maximum operating pressure at that location presents a flawed logic, as an equivalent criteria of deriving a similar response from design factors in the natural gas pipeline regulations would not be feasible. Also, a more appropriate equivalence to a proof hydro-static test would lead to the proposed response criteria of a burst pressure less than 1.25 times the maximum operating pressure at the location of the anomaly. Finally, modifications need to be made to generalize this criterion to both metal loss and cracking. Given that SSWC is otherwise addressed within the proposed criteria API and AOPL believe that there remains no basis for a criteria regarding corrosion that is coincidentally of or along a seam weld API and AOPL strongly urge PHMSA to address confusing language in paragraph (vii) which reads: A potential crack indication that when excavated is determined to be a crack. This wording would create the impossible scenario of requiring operators to excavate a potential crack in order to determine whether they should excavate that potential crack. Written as such, the criterion is irrelevant to ILI response and provides no guidance or risk reduction. API and AOPL propose a measurable and detectable criterion of a likely or possible crack with depth greater than 50% of nominal wall. API and AOPL also recommend PHMSA adopt an additional 18-month repair condition on dents with corrosion. The current generation of ILI tools used to identify metal loss will frequently identify shallow, non-injurious metal loss associated with the manufacturing process of the pipe. Grinding to remove burrs for thin film coating is an example. API and AOPL recommend usage of industry recognized engineering analysis to show an anomaly poses minimal risk to pipeline integrity. Therefore, API and AOPL propose the following changes to PHMSA proposed 49 C.F.R. 422(d)(3) (bold and strikeout reflecting additions and deletions, respectively): * * * * (3) 18-month repair conditions. An operator must repair the following conditions within 18 months of discovery: (i) A dent with a depth greater than 2% of the pipeline s diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or a longitudinal seam weld unless an industry recognized engineering analysis shows that it poses minimal risk to pipeline integrity. 20

21 (ii) A dent located on the top of the pipeline (above 4 and 8 o clock position) with a depth greater than 2% of the pipeline s diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) unless an industry recognized engineering analysis shows that it poses minimal risk to pipeline integrity. (iii) A dent located on the bottom of the pipeline with a depth greater than 6% of the pipeline s diameter unless an industry recognized engineering analysis shows that it poses minimal risk to pipeline integrity. (iv) A calculation of the remaining strength of the pipe at the metal loss, likely crack or possible crack anomaly shows a predicted burst pressure safe operating pressure that is less than 1.25 times the MOP at that location. Provided the safe operating pressure includes the internal design safety factors in in calculating the pipe anomaly safe operating pressure, suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G ( Manual for Determining the Remaining Strength of Corroded Pipelines (1991)) or AGA Pipeline Research Committee Project PR ( A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe (December 1989)) (incorporated by reference, see 195.3). (v) An area of general corrosion with a predicted metal loss greater than 50% of nominal wall. (vi) Predicted metal loss greater than 50% of nominal wall that is located at a crossing of another pipeline or is in an area with widespread circumferential corrosion, or is in an area that could affect a girth weld. (vii) A likely or possible crack with depth greater than 50% of nominal wall. A potential crack indication that when excavated is determined to be a crack. (viii) Corrosion of or along a seam weld. (ix) A dent located anywhere on the pipeline with corrosion unless an industry recognized engineering analysis shows that it poses minimal risk to pipeline integrity. (ix)(x) A gouge or groove greater than 12.5% of nominal wall. 3. Scheduled Conditions API and AOPL recommend PHMSA include a Scheduled Conditions repair condition for non-hca lines, with only one provision in this criterion. The Associations proposed language is designed to mitigate the potential for pressure-limiting, immediate features before the next ILI is conducted. API and AOPL propose a new 49 C.F.R (d)(4) to read as follows: 21

22 * * * * (4) Scheduled Conditions. An operator must repair the following condition prior to the year the condition is met until the next re-inspection: (i) A calculation of the predicted remaining strength of the pipe (including allowances for growth and tool measurement error) shows a predicted burst pressure less than 1.1 times the maximum operating pressure at the location of the anomaly. C. Repairs at Section Pipeline Integrity Management in High Consequence Areas API and AOPL also propose changes to repair conditions for HCA lines in 49 C.F.R based on the rationale behind the modifications to the proposed non-hca repair criteria in Section The Associations recognize that, in HCA areas, repairs need to be made in 270 days, as opposed to 18 months. For clarity, API and AOPL have not restated the rationale, but have pasted below changes to what PHMSA proposed in Section (h)(4), with additions in bold and deletions with strike through: (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 formulas in paragraph (h)(4)(i)(b)(v) of this section, if applicable, or when the formulas in paragraph (h)(4)(i)(b)(v) of this section are not applicable by using a pressure reduction determination in accordance with and the appropriate remaining pipe wall thickness, or if all of these are unknown a minimum 20 percent or greater operating pressure reduction must be implemented until the anomaly is repaired. 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. (A) Metal loss greater than 80% of nominal wall regardless of dimensions. (B) Likely crack anomalies greater than 70% of nominal wall or of an indeterminate depth regardless of dimensions or the maximum depth sizing capabilities of the tool, as stated by the vendor s performance specification, where the depth cannot otherwise be established through correlation with previous ILI runs. 22

23 (B)(C) A calculation of the remaining strength of the pipe shows a predicted burst pressure less than 1.1 times the maximum operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, but are not limited to, ASME/ ANSI B31G ( Manual for Determining the Remaining Strength of Corroded Pipelines (1991) or AGA Pipeline Research Committee Project PR ( A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe (December 1989)) (incorporated by reference, see 195.3). (C)(D) A dent located anywhere on the pipeline that has any indication of metal loss, a gouge, cracking or a stress riser unless an industry recognized engineering analysis shows that it poses minimal risk to pipeline integrity. (D)(E) A dent located on the top of the pipeline (above the 4 and 8 o clock positions) with a depth greater than 6% of the nominal pipe diameter unless an industry recognized engineering analysis shows that it poses minimal risk to pipeline integrity. (E) Any indication of significant stress corrosion cracking (SCC). (F) Any indication of selective seam weld corrosion (SSWC). (G) (F) An anomaly that in the judgment of the person designated by the operator to evaluate the assessment results requires immediate action. (ii) 270 day repair conditions. Except for conditions listed in paragraph (h)(4)(i) of this section, an operator must schedule evaluation and remediation of the following within 270 days of discovery of the condition: (A) A dent with a depth greater than 2% of the pipeline s diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or a longitudinal seam weld unless an industry recognized engineering analysis shows that it poses minimal risk to pipeline integrity. (B) A dent located on the top of the pipeline (above 4 and 8 o clock position) with a depth greater than 2% of the pipeline s diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) unless an industry recognized engineering analysis shows that it poses minimal risk to pipeline integrity. (C) A dent located on the bottom of the pipeline with a depth greater than 6% of the pipeline s diameter unless an industry recognized engineering analysis shows that it poses minimal risk to pipeline integrity. (D) A calculation of the remaining strength of the pipe at the metal loss, likely crack or possible crack anomaly shows a predicted burst pressure safe 23

24 operating pressure that is less than 1.25 times the MOP at that location. Provided the safe operating pressure includes the internal design safety factors in in calculating the pipe anomaly safe operating pressure, suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G ( Manual for Determining the Remaining Strength of Corroded Pipelines (1991)) or AGA Pipeline Research Committee Project PR ( A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe (December 1989)) (incorporated by reference, see 195.3). (E) An area of general corrosion with a predicted metal loss greater than 50% of nominal wall. (F) Predicted metal loss greater than 50% of nominal wall that is located at a crossing of another pipeline or is in an area with widespread circumferential corrosion, or is in an area that could affect a girth weld. (G) A likely or possible crack with depth greater than 50% of nominal wall. A potential crack indication that when excavated is determined to be a crack. (H) Corrosion of or along a seam weld. (H) A dent located anywhere on the pipeline with corrosion unless an industry recognized engineering analysis shows that it poses minimal risk to pipeline integrity. (I) A gouge or groove greater than 12.5% of nominal wall. (iii) Scheduled Conditions. An operator must repair the following condition prior to the year the condition is met until the next re-inspection. (A) A calculation of the predicted remaining strength of the pipe (including allowances for growth and tool measurement error) shows a predicted burst pressure less than 1.1 times the maximum operating pressure at the location of the anomaly. (iii) (iv) Other conditions. In addition to the conditions listed in paragraphs (h)(4)(i) and (ii) of this section, an operator must evaluate any condition identified by an integrity assessment or information analysis that could impair the integrity of the pipeline, and as appropriate, schedule the condition for remediation. Appendix C of this part contains guidance concerning other conditions that an operator should evaluate. (v) Other considerations. (A) In regards to calculating a predicted burst pressure for the purposes of determining remaining strength, selection of a suitable 24

25 calculation method depends on several factors, including the failure mode of the anomaly. Appropriate calculation methods include, but are not limited to: For metal loss anomalies susceptible to failure in plastic collapse: ASME/ANSI B31G ( Manual for Determining the Remaining Strength of Corroded Pipelines (1991)) or AGA Pipeline Research Committee Project PR ( A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe (December 1989)). For crack anomalies or selective seam weld corrosion (SSWC) associated with EFW and vintage ERW seams susceptible to failure through fracture: the Battelle Model (Modified Log-Secant), CorLAS or API 579 Part 9. For dent anomalies: the safe working pressure can be determined using PRCI PR Safe Inspection Procedures for Dent and Gouge Damage (2010). (B) For purposes of this regulation, a likely crack is defined as having a reasonable degree of confidence that the anomaly called by the ILI vendor correlates to a crack-like defect. This can be the case where the operator s previous experience on the present pipeline segment or other similar pipeline segment has found cracks or the case where the data integration indicates a strong likelihood that cracks could exist even though no historical data suggests so. Whereas, a possible crack is defined as having a reduced certainty of being or rarely been an actual crack and, when it is a crack, it occurs under different circumstances or the operator cannot determine with a high degree of confidence that the indication is NOT a crack-like defect. (C) For purposes of this regulation, an industry recognized engineering analysis must include operator documentation and provide adequate technical justification for not completing repair or remediation of identified conditions within the specified timeframe. All evaluations must be performed by qualified persons, based on sound engineering principles, and must consider the following factor at a minimum: Dents: predicted flaw dimensions, material properties, tool tolerance, failure mode, operational pressure cycles, and predicted growth rate of corrosion and/or cracks. * * * * D. Additional Considerations API and AOPL are also concerned about the future interpretation of Section beyond non-hca transmission lines to gravity and gathering lines located offshore. PHMSA could address the Associations concerns by adding the following language at the end of Section (a): This section does not apply to gravity or gathering lines. There is also a concern about timing and response to anomalies located offshore. Repair of offshore lines can take anywhere from one month to well over a year depending on the type of repair and permitting that might be involved. For example, clamps used to repair offshore lines 25

26 are special order items that have a long lead time and while a company might have some clamps in storage, if those available are not the right type, or if there are multiple anomalies, it will take months to get the proper equipment. In addition, each repair can cost a minimum of $500,000 and if a cutout is required this will be a major project that could cost as much as $10 million. Because of the difficulty of some of these repairs, it is requested that extra time be allowed for these repairs and that room for engineering judgment be included in the decision of what anomalies to repair. The language proposed by the Associations in these sections strike the appropriate balance between allowing operators to exercise sound engineering judgment and ensuring safety to the public and to the environment by not diverting valuable resources to fixing anomalies that do not pose a threat. V. Expand the Use of Leak Detection Systems for All Hazardous Liquid Pipelines PHMSA proposes to require all new regulated hazardous liquids pipelines to include leak detection systems, expanding the scope of the existing requirements that apply only to HCAs. Additionally, all existing portions of a regulated hazardous liquids pipeline system must have a means for detecting leaks, including regulated onshore gathering lines. API and AOPL ask that PHMSA provide an implementation timeline so that operators have clarity on when pipelines should be updated with some form of leak detection system. Neither the NPRM language nor the proposed regulatory text references an implementation period. As it is critical for operators to understand the timeframe in which they must comply, API and AOPL request that PHMSA adopt a minimum implementation period of five years so that operators have sufficient time and resources to comply with the proposed rules. The Associations assume that this requirement, which is applicable to regulated onshore gathering lines, will not be applied to offshore gathering lines. API and AOPL request that PHMSA confirm this point in issuing a final rule. Applying this proposed requirement to offshore gathering lines would be an unwarranted change, as they are typically comprised of short segments and operate only intermittently. As such, applying leak detection to these lines would result in a potential increase of false alarms and would divert resources from higher-risk leak detection for onshore pipelines. VI. The Proposed Requirement that All HCA Could Affect Segments and Newly- Identified HCAs be able to Accommodate ILI Tools Lacks Adequate Cost/Benefit Analysis and is Not Supported The NPRM proposes to require that all pipelines in areas that could affect an HCA be made capable of accommodating ILI tools within twenty years, unless the basic construction of a pipeline will not permit that accommodation or the existence of an emergency renders such an accommodation impracticable. 24 Additionally, PHMSA would require that pipelines in newlyidentified HCAs after the twenty-year period be made capable of accommodating ILIs within Fed. Reg 61610, at

27 five years of the date of identification or before the performance of the baseline assessment, whichever is sooner. API and AOPL request that this proposal not be adopted, as imposing this requirement would require pipelines to incur exorbitant costs due to the age, design and location of the pipelines, without any demonstration of commensurate benefits. Such costs would dwarf the aggregate industry cost estimated by PHMSA in the preamble to the NPRM. The Associations have received industry estimates and cost figures that would follow from including this provision in a final rulemaking without providing sufficient exception for those pipelines that cannot be made ILI-capable, such as a number of gathering lines. One operator recently replaced a 320-foot pipeline segment of an 8-inch diameter pipe; as part of the replacement, the operator made the line ILI-capable and estimated that about $1 million was spent on this effort. A 1,500-foot pipeline with an 8-inch diameter was replaced by the same operator, and part of the replacement focused on making the pipeline ILI-capable, the operator estimates that about $2 million was spent to make this line ILI-capable. Similarly, if an offshore line needs to have subsea fittings replaced to accommodate ILI tools, this effort can easily reach into the $100 million range. API and AOPL have received industry estimates suggesting the costs would run extraordinarily high even if the line itself did not need to be replaced. For example, one operator has estimated that materials and labor for a pipeline that needed only launching and receiving traps in order to accommodate ILI tools may cost $50,000 per trap on a small diameter line, and as much as $300,000 on a larger line. Similarly, the cost for a pipeline with traps but needing a larger radius bend for a successful ILI run would be driven by the number of bends requiring excavation and replacement, as well as the revenue loss due to shutdown of the pipeline. The base cost is estimated at $100,000 unless the pipeline was decommissioned previously. Taking these cost figures into account, many operators particularly those with gathering lines may be faced with the choice of either abandoning a pipeline and shutting production due to the decreased economic viability of the project, or using alternate methods (e.g., trucks) to transport the product. The latter choice runs contrary to PHMSA s mission of increased safety to the public and the environment, as pipelines remain the safest mode of transportation for hazardous liquids. Moreover, the proposal will surely trigger a tremendous volume of petitions under Section requesting a finding that the physical attributes or operational limitations of the pipeline do not allow for the passage of an ILI device. PHMSA has not demonstrated how this process would improve public safety given that pipelines will need to petition for such relief due to the physical limitations of these lines. The Associations support increased use of ILI in new lines and recognize its value in promoting an understanding of pipeline integrity. However, rather than creating an onerous administrative burden on operators and PHMSA to request the use of hydrostatic testing and other detection approaches through a formal petition, API and AOPL request that PHMSA remove the requirement to petition under Section and instead continue to allow operators to exercise their expertise and engineering judgment in using the most effective and efficient methods of evaluating the integrity of their facilities with prior notification to the Office of Pipeline Safety. 27

28 VII. Explicit Reference to Seismicity in Lists of Risk Factors The NPRM proposes to further comply with Congress s directive related to seismicity and pipeline safety by including an explicit reference to seismicity in the list of risk factors that must be considered in establishing assessment schedules ( (e)), performing information analyses ( (g)), and implementing preventative and mitigative measures ( (i)) under the IM requirements. 25 API and AOPL request that PHMSA clarify how to manage and implement the requirement to consider seismicity as a risk factor under these subsections. The Associations understand the need to consider seismicity as a potential threat to pipeline safety and appreciate PHMSA s efforts to comply with Congress s directive in Section 29 of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of However, pipeline operators need clear guidance and direction regarding how to manage this requirement in order to fully and efficiently implement the inclusion of seismicity as a risk factor to be considered in establishing assessment schedules, performing information analyses and implementing preventative and mitigative measures. VIII. Clarify Other Requirements A. A Reasonable Implementation Period for the Newly Proposed Data Integration Requirements is Needed The NPRM proposes enhanced requirements for the integration and analysis of twenty one specific pipeline attributes and any spatial relationship that exist within the data in Section (g). The Associations support the enhanced focus on risk data integration. API and AOPL note that the proposed regulatory text does not articulate or propose an implementation period for pipeline operators. In the absence of any implementation period, the proposed rule language will make the requirements in this section become effective immediately. API and AOPL urge PHMSA to delay the implementation of this requirement for five years to allow operators to establish the programs required to implement the attributes in a spatial platform, which will include implementing the new information systems, populating data into these systems, and validating of the quality of the data process. The Associations believe a five-year period is appropriate, as this timeframe is consistent with the language currently contained in Section (j). B. Hydrostatic Testing Should be an Acceptable Method for Baseline Assessments Prior to Commencing Operations on Newly-Constructed Pipelines Proposed Section (d)(1) provides that operators must complete the baseline assessment before the pipeline begins operation. 26 The Associations request that PHMSA clarify that hydrostatic testing is an acceptable method of meeting this requirement for new construction. Currently, Section (a) of PHMSA s regulations requires that new pipelines 25 Id. at Id. at

29 be hydrostatically tested prior to commencing service. During the webinar hosted by PHMSA on December 10, 2015, an industry representative asked for clarification on this point and PHMSA informally responded that a hydrostatic test, performed according to Section , would meet the baseline assessment requirement. The Associations request confirmation in the final rule that the requirement in Section (a) would meet the baseline assessment requirement proposed in Section (d)(1). IX. Conclusion API and AOPL appreciate the opportunity to comment on the proposed regulations and support PHMSA s efforts in promoting pipeline safety. API and AOPL respectfully request that PHMSA promulgate regulations in the final rule consistent with the comments herein. Robin Rorick Andrew J. Black Midstream, Group Director President and CEO American Petroleum Institute Association of Oil Pipe Lines 1220 L Street, NW 1808 Eye Street, NW Washington, DC Washington, DC