{"operation":"document","citation":"0900006480e8ae8e","title":"U.S. DOT/RSPA - Final Regulatory Evaluation","source_type":"rulemaking","agency":"Pipeline and Hazardous Materials Safety Administration","status":"current","official":true,"published_on":null,"effective_on":null,"summary":"U.S. Department of Transportation Research and Special Programs Administration Final Regulatory Evaluation Pipeline Integrity Management in High Consequence Areas (Hazardous Liquid Pipeline Operators with less than 500 miles of Pipelines) Docket RSPA-00-7408 3. Requiring pipeline operators to develop integrity management programs providing for inspection and testing based on risk factors and integration of information related to pipeline 1 isk and to add accident mitigative features and improved leak detection based on risk. Pipeline operators are uniquely qualified to...","machine_formats":{"json":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e8ae8e.json","markdown":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e8ae8e.md"},"app_url":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e8ae8e","source_url":"https://downloads.regulations.gov/PHMSA-RSPA-2000-7408-0033/attachment_1.pdf","body":"<<<PAGE 1>>>\n\nU.S. Department of Transportation\nResearch and Special Programs Administration\nFinal Regulatory Evaluation\nPipeline Integrity Management in High Consequence Areas (Hazardous Liquid Pipeline\nOperators with less than 500 miles of Pipelines)\nDocket RSPA-00-7408\n\n<<<PAGE 2>>>\n\nINTRODUCTION\nThe U.S. Department of Transportation Research and Special Programs Office of Pipeline Safety\n(OPS) is changing pipeline safety regulations to require operators of certain hazardous liquid\npipelines to validate the integrity of their pipelines in high consequence areas (HCAs). The rile\nwould apply to operators with less than 500 aggregate miles of pipeline. (Requirements for\noperators with more than 500 miles of hazardous liquid pipeline were established in a previoi is\nrulemaking). The objective of the change is to reduce the risk of hazardous liquid pipeline\nincidents in these areas. OPS defines a high consequence area as one in which there is a high\npopulation area or densely populated area, a commercially navigable waterway, or an unusua ly\nsensitive area. To validate the integrity of their pipelines in high consequence areas under thi :\nregulatory change, pipeline operators must implement an integrity management program for : uch\npipelines including periodic inspection and testing and integration of information related to\npipeline integrity. The purpose of this report is to assess the benefits and costs of the regulatc ~ r y\nchange.\nTARGET PROBLEM\nHazardous liquid pipeline spills can have an adverse impact on human health and the\nenvironment. The magnitude of this impact differs. There are some areas in which the impa :t of\na spill will be more significant than it would be in others due to concentrations of people whc I\ncould be affected or to the presence of environmental resources that are unusually sensitive tc 1\ndamage. Because of the potential for dire consequences of pipeline failures in certain areas,\nthese areas merit a higher level of protection. OPS is promulgating this regulation to afford the\nnecessary additional protection to these “high consequence areas”.\nNumerous investigations by OPS and the National Transportation Safety Board (NTSB) havi :\nhighlighted the importance of protecting the public and environmentally sensitive areas fron L\npipeline failures. NTSB has made several recommendations to ensure the integrity of pipeliries\nnear populated and environmentally sensitive areas. These recommendations included requi ing\nperiodic testing and inspection to identify corrosion and other damage, establishing criteria ti 1\ndetermine appropriate intervals for inspections and tests, determining hazards to public safet 1 1\nfiom electric resistance welded pipe and requiring installation of automatic or remotely-oper ited\nmainline valves on high-pressure lines to provide for rapid shutdown of failed pipelines.\nCongress also directed OPS to undertake additional safety measures in areas that are densely\npopulated or unusually sensitive to environmental damage. These statutory requirements\nincluded having OPS prescribe standards for identifying pipelines in high density population\nareas, unusually sensitive environmental areas, and commercially navigable waters; issue\nstandards requiring periodic inspections using internal inspection devices on pipelines in der lsely-\npopulated and environmentally sensitive areas; and survey and assess the effectiveness of\n1\n\n<<<PAGE 3>>>\n\nemergency flow restricting devices, and prescribe regulations on circumstances where an\noperator must use the devices.\nThis rulemaking addresses the target problem described above, and is a comprehensive respoi ise\nto NTSB’s recommendations and Congressional mandates, as well as pipeline safety and\nenvironmental issues raised over the years.\nALTERNATIVES CONSIDERED\nOPS considered several alternatives to provide the necessary increased level of protection to 1 iigh\nconsequence areas. These alternatives were:\n1. No action.\n2. Prescriptive requirements for inspection and repair of pipelines in high consequence areas and\nfor incorporating accident mitigative features and improved leak detection.\n3. Requiring pipeline operators to develop integrity management programs providing for\ninspection and testing based on risk factors and integration of information related to pipeline iisk\nand to add accident mitigative features and improved leak detection based on risk.\n4. Requiring pipeline operators to develop integrity management programs providing for\nexpedited inspection and testing.\nINITIAL SCREENING OF ALTERNATIVES\n1. No action.\nPipeline operators currently manage their pipeline to avoid accidents, leaks and spills. They\nperform inspection and testing on their pipelines to assess their integrity, and make repairs as\nthey conclude they are needed. These actions would be expected to continue under the “no\naction” a1 ternative.\nPipeline leaks, spills, and ruptures occur, despite the existence of these operator programs.\nMajor pipeline spills have occurred in the last two years, of which two were particularly notallle,\n(Bellingham and PEPCO). In both cases, in-line inspection (pigging) of the pipeline had taki :n\nplace. Operators either failed to recognize the significance of indications from the pig runs or\nfailed to integrate that information with other information about the pipeline, including the\npresence of construction activity in the area. OPS concludes that validation of these prograrr s\nthrough audit and review by outside parties, i.e, the regulator, is necessary to help assure that\nappropriate actions are taken.\nIn addition, continuation of voluntary programs cannot be assured absent some regulatory\nrequirement. Pipeline operators must be responsive to market conditions, and future change! in\neconomic conditions could lead to curtailment or elimination of some or all inspection and\ntesting.\n2\n\n<<<PAGE 4>>>\n\nOPS concludes that assuring continuation of pipeline integrity management programs, assurir g\nthat their scope encompasses all areas requiring special protection, and verifying their adequa :y\nare necessary to assure that the requisite level of protection will be provided. This assurance\ncannot be provided without some regulatory requirement addressing the target problem. In\naddition, continued reliance on voluntary industry efforts would not be responsive to the\nCongressional mandate that OPS promulgate requirements to assure protection of the areas th at\nare herein designated as high consequence areas.\nFor these reasons, the “no action” alternative was not considered further\n2. Prescriptive requirements for inspection and repair of pipelines in high consequence areas and\nfor incorporating accident mitigative features and improved leak detection.\nPipeline circumstances differ, even within high consequence areas. These differences would\nmake it difficult, at best, to establish prescriptive requirements that would appropriately addri :ss\nall possible combinations of pipeline size, type, and configuration or to consider other factor:\nthat contribute to the risk of failure of a particular pipeline. It is likely that creating detailed\nprescriptive requirements would result in a need for a large number of waivers to address the\nissues of importance to specific pipelines and high consequence areas. The result would be a\npatchwork of specific, but different requirements. It would be an inefficient use of industry 2 nd\ngovernment resources to establish requirements in this fashion. Compliance inspection woulij\nstill require that the requirements applicable to specific pipelines be identified for comparisoi L\nwith ongoing practices.\nPrescriptive requirements also would tend to stifle technological innovation. They do not all iw\nfor different approaches based on advances in the technology. The technology associated wi. h\nin-line inspection of pipelines (i.e., pigging) is advancing at a rapid pace. Establishing\nprescriptive requirements could slow this advancement, or could preclude use of new techniciues\nthat may be developed. In the extreme, prescriptive requirements could stop technological\ninnovation in this area completely.\nMost importantly, however, establishing prescriptive requirements would not assure the\nintegration of information which experience has shown is vital to preventing pipeline accidei its.\nAs noted above, two major accidents have occurred in recent years despite the fact that the\npipelines involved had been pigged. It appears that other information was available that, if\ncorrelated to the pig results, could have highlighted the need for action regarding the indicatilms\nthat ultimately resulted in failure of the pipe. An integrity management program is required o\nassure this integration of available information. Outside review of the integrity management\nprogram (Federal and state) by regulators, is necessary to assure that it is complete and propt rly\nimplemented. This outside review cannot be assured without a requirement for such a progr im.\nFor these reasons, the option of establishing prescriptive requirements was not evaluated fur her.\n3\n\n<<<PAGE 5>>>\n\n3. Requiring pipeline operators to develop integrity management programs providing for\ninspection and testing based on risk factors and integration of information related to pipeline 1 isk\nand to add accident mitigative features and improved leak detection based on risk.\nPipeline operators are uniquely qualified to develop integrity management programs and prov ide\nfor the necessary integration of information. They have the best knowledge of their pipelines and\nthe factors affecting its risk. Integration of information requires that the management system:, of\nthe company be aligned and operated to assure that necessary information is shared and that i. is\nevaluated in its proper context by knowledgeable personnel. These are actions that are difficii It\nto require through prescriptive regulation. Requiring that operators develop such programs is the\nbest way to assure that they exist. Such a requirement also provides the regulatory basis for (IPS\nto audit, review, and assess these programs and their implementation.\nThe best integrity management plans, when implemented properly, can reduce the risk of pipi :line\naccidents. They cannot, however, eliminate that risk. Leaks and ruptures could still occur, fmm\nunforseen outside impacts on the pipeline or fkom unanticipated interactions among factors\ncontributing to pipeline risk. It is therefore important that features and procedures be available to\ndetect and mitigate the effects of accidents that may occur.\nHere again, circumstances differ between pipelines and between regions and local jurisdictioi is.\nThe differences make it difficult to establish prescriptive requirements that will provide the bl:st\nprotection for each high consequence area. Requiring that operators explicitly consider the n :ed\nfor improved leak detection and for mitigative features and provisions and that they impleme it\nthose found necessary is the most effective means of providing such protection. Such a\nrequirement also provides the regulatory basis for audit and review by OPS and state regulatclrs.\nFor these reasons, this option was selected for fbrther development.\n4. Requiring pipeline operators to develop integrity management programs providing for\nexpedited inspection and retesting.\nOPS considered the need for requiring integrity management programs that would require\ninspection and testing of pipelines to recur over short intervals, a few years. The ability to\nrequire frequent testing is limited by the available resources for testing and inspection.\nThe companion rule originally proposed for operators with more than 500 miles of pipeline\nincluded requirements for reassessment at ten-year intervals. Based upon consideration of\ncomments received, that interval was reduced in the final rule to five years, with limited\nexcpetions. OPS concluded that the spur provided by the regulation would be Iikely to resul. in\nan increase in testing capacity over the next five years that will then be able to accommodate\ntesting at accelerated rates. OPS considers it important to inspect and test pipeline in high\nconsequence areas at an aggressive rate in order to assure the additional protection desired fclr\nthese areas. OPS concludes that a similar interval is appropriate for operators with less than 500\n4\n\n<<<PAGE 6>>>\n\nmiles of pipeline because the increased testing capacity will also be available to them and\nbecause their historical testing rate is at a similar fiequency.\nBASELINE REGULATORY ENVIRONMENT\nIn order to assess the costs and benefits of the new regulation, it is necessary to first ascertain the\ncurrent level of activity in areas addressed by the rule. In this instance, it is necessary to\ndetermine the rate at which pipeline inspections are being performed, the presence of prevent ve\nand mitigative features, and the prevalence and nature of integrity management plans similar o\nthose required by the rule.\nInformal discussions with operators with less than 500 miles of pipeline have identified that r iiost\nhave a regular assessment program. A large majority appear to test all of their pipelines on a\nfi-equency of five years or less. OPS assumes that this rate applies to piping in high conseque nce\nareas and that this rate would have continued absent a regulatory requirement to increase it.\nMuch of the testing being conducted by these operators is the initial inspection of pipelines. The\nrate at which subsequent inspections would be performed is now unknown. It is likely that s( )me\npipeline would be identified for reinspection frequently (e.g., every five years). It is equally\nlikely that some pipeline would not be reinspected at all.\nOPS also has limited knowledge about the nature and extent of preventive and mitigative fea ures\nand procedures that have been implemented by pipeline operators. The mitigative feature fo1\nwhich OPS has the best knowledge is emergency flow restriction devices (EFRDs). EFRDs ,ire\ncheck valves or remotely operated valves, usually block valves, that can reduce the amount o F\nproduct lost in a pipeline leak. It is estimated that 84.1 percent of all valves currently instal ed\non hazardous liquid pipelines are manually operated block valves.’ OPS has no knowledge c f\ncurrent plans to convert any of these valves to remote operation.\nIntegrity plans are a key element of this rule. To better understand and promote more\ncomprehensive and integrated approaches to safety and environmental protection, OPS creatc :d\nthe Risk Management Demonstration Program, and the System Integrity Inspection (SII) Pilclt\nProgram. These programs encourage and evaluate operator-developed safety and environmeiital\nmanagement processes that incorporate operator- and pipeline-specific information and data to\nidentify, assess, and address pipeline risks. These programs, along with the Oil Spill Respor se\nPlan Review and Exercise Program, are helping RSPA’s Office of Pipeline Safety (OPS) ref ne\nits regulatory oversight processes. These processes help to ensure that pipeline operators ha7 re\neffective processes in place to identify the most important risks to the public and the\nenvironment, and to develop and implement cost-effective preventive and mitigative actions to\n‘Office of Pipeline Safety, Emergency Flow Restricting Devices Study (A Study Mandated by P.L. 100-561), U S.\nDOT, April 1990. The original source of the information was reported to be the American Petroleum Institute.\n5\n\n<<<PAGE 7>>>\n\nmanage these risks. Many of these initiatives have validated the importance of focusing\nresources and establishing higher levels of protection in areas where a pipeline failure could have\nsignificant consequences.\nThrough the Risk Management Demonstration Program and the System Integrity Inspection F ilot\nProgram, OPS has improved its understanding of pipeline operator integrity management syst lems\nand activities. This experience has shown that a number of liquid pipeline operators have\nformalized management systems to identify and address the most significant integrity threats o\ntheir pipeline systems. In the Risk Management Program, participants perform systematic an1 i\ncomprehensive risk assessments to identify the specific nature and location of the most\nsignificant risks posed by operation of their pipeline system. An essential feature of these risl\nassessments is the integration of information from many diverse sources to fully understand tl le\nintegrity threats at specific locations on the pipeline. Environmental consequences and the imiDact\non nearby population are explicitly considered in these risk assessments. Through formal, rislc-\nbased decision making processes, these companies use the risk assessment results to identify\nprojects and activities that address potential system integrity threats, thereby preventing oil SF ills.\nThe risk management process also examines the consequences of potential releases and explc res\nopportunities to minimize the environmental and public safety and health impacts should a\nfailure occur. These investigative risk management programs, and the preventive and mitigal ive\nrisk control activities that evolve from them, supplement the minimum regulatory requiremer Its\nestablished in 49 CFR 195 to protect the public and the environment.\nThe System Integrity Inspection Program is focused on developing a more integrity-based\napproach to OPS inspections. Instead of using a “checklist” approach, OPS is focusing the\ninspection process on an operator’s integrity management processes and activities. Through\nworking with the operator, OPS is able to understand and influence the methods and approac lies\nused to assess pipeline integrity, and the approaches to integrating integrity assessment data with\nother pipeline specific information to identify the most significant integrity threats to the systlem.\nSpecifically, OPS has observed how operators examine internal inspection data in conjunctia n\nwith other surveillance and operating data, expected population growth, land use, constructic n\nactivity along the pipeline, and other information relevant to assuring the integrity of the pipt line\nin high population areas and in environmentally sensitive areas. Through this interaction OP S is\nacquiring a broader understanding and a greater confidence that effective programs are in pla :e to\naddress the most significant risks. Similar to the Risk Management Program, the SI1 Program is\nemphasizing how operators evaluate their system condition and its risks, and use this\ninformation to make sound integrity management decisions.\nOPS experience in the Risk Management Demonstration Program and the System Integrity\nInspection Program indicates that integrity management programs such as that required by tk is\nrule have been developed. They are far from universal, however.\n6\n\n<<<PAGE 8>>>\n\nSCOPE AND PARAMETERS OF ANALYSIS\nThis analysis of benefits and costs takes the following approach. First, the mileage impacted iy\nthe regulatory change is identified and estimated. Then the potential benefits of the rule are\ndiscussed. In the next section the potential costs of the rule are examined. Finally, a discussicln\nof the costs versus the benefits is examined. It should be noted that, unless otherwise specific d,\nall dollar values in this report are given in constant 1998 dollars.2 Furthermore, this analysis 'vi11\narbitrarily consider only the first twenty years after the effective date of the final rule. Includi ng\nadditional years would not be expected to materially affect the conclusions of this analysis.\nANALYSIS\nImpacted Mileage\nIn this section the total hazardous liquid pipeline mileage impacted by the regulatory change i s\nestimated. That mileage is located in or nearby high consequence area's, defined by the chan 1;e\nas: (1) high population areas, (2) densely populated areas, (3) commercially navigable\nwaterways, and (4) unusually sensitive areas.\nTotal PiDeline Mileage\nIn total, there is an estimated 157 thousand miles of regulated hazardous liquid pipelines in tlie\nU.S.3 This change would not impact all hazardous liquid pipeline operators. Rather, it woulc I\nimpact only those operators with an aggregate of less than 500 miles of pipeline. The Office of\nPipeline Safety (OPS) estimates that these operators have 13.3 percent of the jurisdictional\nhazardous liquid pipeline mileage.4 Thus, the operators covered by the rule are expected to h ave\nabout 20,900 miles of regulated hazardous liquid pipelines.\nImpacted Mileage in High Population And Densely Populated Areas\nBecause of the similar nature of the two types of areas, the impacted pipeline mileages in higln\npopulation areas and in densely populated areas are considered together. As defined by the\n'Dollars are converted from nominal values to real 1998 values using the Producer Price Index (PPI), Intermed ate\nMaterials, Supplies, and Components. The source of the PPI index numbers is the U.S. Bureau of Statistics Wt b\npage.\n'Jurisdictional hazardous liquid pipeline mileage for 1999. This mileage was obtained from Office of Pipeline Saf: :ty\nUser Fee Assessments.\n'This percentage estimate was based on information from Office of Pipeline Safety User Fee Assessments. This\nestimate may overstate the actual percentage operated by operators with less than 500 miles of pipeline, becaus\nsome operators may report pipeline segments using multiple names. Therefore, some operators with apparent11 little\npipeline mileage may actually be part of larger operators.\n7\n\n<<<PAGE 9>>>\n\nregulatory change, a high population area is one with 50,000 or more people in total and at lezist\n1,000 people per square mile. A densely populated area is defined as any place containing a\nconcentrated population, such as an incorporated or unincorporated town or village.\nThe OPS estimates that 16,500 miles of regulated hazardous liquid pipeline are located in higli\npopulation areas and another 5,500 miles are located in densely populated areas. It is likely tl lat\nonly part of this 22,000 miles is pipeline covered by the rule. Since 13.3 percent of the total\nmileage is operated by operators with less than 500 miles of pipeline, it appears reasonable to\nassume, in the absence of contrary information, that 13.3 percent of the mileage located in hii1,h\npopulation and densely populated areas, or 2,930 miles of pipeline, is operated by these\noperators.\nImpacted Mileage Near Commercially Navigable Waterways\nThe regulated pipeline mileage in or near commercially navigable waterways includes (1) the\nmileage crossing those waterways and (2) the mileage lying near enough to the waterways to\nadversely impact them, should a leak, spill, or rupture occur.\nThe OPS estimates that 800 miles of regulated hazardous liquid pipeline are in or near navigilble\nwaterways. It is likely that only part of this mileage is pipeline within the scope of this\nrulemaking. Since 13.3 percent of the total mileage is operated by operators with less than 500\nmiles of pipeline, it appears reasonable to assume that 13.3 percent of the mileage in or near\nnavigable waterways, or 1 10 miles of pipeline, is operated by these operators.\nImpacted Mileage in Unusually Sensitive Areas\nA pilot test relating to unusually sensitive areas (USAs) was recently conducted by the U.S.\nDepartment of Transportation (U.S. DOT) and the American Petroleum Institute (API). This\npilot test covered pipelines in California, Louisiana, and Texas. One product from this pilot t:est\nwas an estimate of the jurisdictional pipeline mileage in USAs or that could affect a USA. rl he\npilot test results indicate that 14.2 percent of hazardous liquid pipeline mileage in the three s ates\nis located in a USA. Some of this pipeline was also located in high- or densely-populated ar :as.\nPilot program results indicate that 2.7 percent of hazardous liquid pipeline mileage in the thr :e\nstates was in both a USA and a populated area. Thus, 1 1.5 percent of pipeline mileage in thc\npilot states was in a USA but not otherwise encompassed within the definition of a high\nconsequence area. For purposes of this analysis, OPS has assumed that the same percentage of\nhazardous liquid pipeline mileage in other states is located in USAs but not otherwise in a hi gh\nconsequence area. This percentage multiplied by the total hazardous liquid mileage of opere tors\nwith less than 500 miles of pipeline, 20,900 miles, results in an estimate of 2,400 miles for t le\npipeline mileage of these operators that is located in USAs.\n8\n\n<<<PAGE 10>>>\n\nTotal ImDacted Mileage\nGiven the estimates derived above for the impacted mileage in or nearby high consequence ar :as,\na total of 5,440 miles of regulated hazardous liquid pipeline is expected to be impacted by the\nregulatory change.\nMileage Impacted Per Year\nThe regulatory change calls for inspection and testing, improving leak detection where\nappropriate, and the use of additional prevention or mitigation measures where necessary. Ar\nexample of such a measure includes the installation of Emergency Flow Restricting Devices\n(EFRDs) at selected points. For the purpose of illustration this analysis examines the potentiill\ncosts of installation of EFRD’s, although EFRD’s are only one alternative among many possi ;)le\npreventive and mitigative measures that operators could choose. The mileages impacted per\nyear will be important inputs in the calculation of the benefits and costs of inspection and tesl ing\nand the benefits of the installation of the EFRDs.\nInspection and Testing\nThe regulatory change requires baseline and subsequent testing of the impacted mileage usin] ; in-\nline inspection, pressure testing, or alternative methods. Acceptable in-line inspection includ es\nhigh resolution, low resolution, and ultrasonic pigging. Acceptable pressure testing consists )f\nhydrostatic testing. Acceptable alternative methods include any other methods that would\nprovide a level of safety equivalent to that provided by internal inspection or pressure testing\nBaseline Testing\nThe rule requires that baseline testing be completed within seven years of the effective date clf the\nrule. Informal discussions with operators with less than 500 miles of pipeline have identified that\nmost have a regular assessment program. A large majority appear to test all of their pipeline ; on\na frequency of five years or less. Thus, it would appear that they would need to test no addit onal\nmileage beyond that otherwise planned in order to meet the requirements for baseline inspec ion.\nOPS recognizes, however, that there are probably some companies not already conducting\nassessments at frequencies consistent with the rule, even though the overall amount of inspe1:tion\nand assessment in the industry is more than would be required. OPS has conservatively assL med\nthat as much as 10 percent of impacted mileage, or 544 miles, may require unplanned assessinent\nover a seven year period (78 miles per year).\n9\n\n<<<PAGE 11>>>\n\nOnce baseline testing has been performed on a segment of pipe, the rule requires that subsequlmt\ntesting be undertaken on that segment, based on risk factors, at least once every five years (wilh\nlimited exceptions). The planned rate of re-testing of pipeline by operators with less than 50C\nmiles of pipeline is unknown. Informal discussions with pipeline operators indicate that muc’i\npipeline mileage would have been re-tested frequently (e.g., every five years), while some\nmileage would not have been re-tested at all.\nSince most operators with less than 500 miles of pipeline appear to test their pipelines every 1 ive\nyears or more often, it should only require minor changes in scheduling specific pipe segmenl s\nfor assessment to assure that all pipe is inspected at least every five years. OPS therefore\nconcludes that there could be limited additional assessment needed by operators with less tha 1\n500 miles of pipeline in order to meet requirements for re-assessment at a five-year fi-equencj .\nFor the reasons described above, OPS has again estimated for this analysis that 10 percent of\nimpacted mileage will require unplanned assessment.\nOperators with less than 500 miles of pipeline will therefore need to assess an additional two\npercent of their impacted mileage annually (1 10 miles) to meet the requirements for subsequt nt\nassessment. OPS expects that operators will identify some pipeline in high consequence area s\nfor which a longer inspection interval can be justified, and that they will seek OPS review to\npermit these segments to be tested at a longer interval. OPS has not adjusted this analysis to\naccount for these longer-interval re-assessments, since the information obtained by informal\ndiscussions with operators indicates limited unplanned assessment should be required and ou r\nassumption that 10 percent of impacted mileage will require unplanned assessment should btlund\nany additional costs.\nPipeline operators will need to do some subsequent testing at the same time they are doing\nbaseline testing. This subsequent testing will begin in the sixth year of baseline testing, which is\nwhen mileage “baseline tested” in the first year after the final rule will need to be re-tested.\nDuring the sixth and seventh years of baseline testing, subsequent and baseline testing will\noverlap. Assuming that most re-testing would have been deferred until all initial testing was\ncompleted in the absence of a regulatory requirement, all subsequent testing in those two years\nwill be over and above what would have been done in the absence of the rule. The full 1,09(1\nmiles undergoing subsequent testing during each of these two years is therefore assumed to be in\nexcess of what would have been done. This analysis also assumes that 78 miles of additional\npipeline must be inspected in each of these two years to complete baseline inspection (see ab we)\nso that the total of additional mileage that will require inspection during these years is 1,168\nmiles.\n10\n\n<<<PAGE 12>>>\n\nEnhanced Leak Detection\nThe rule includes criteria for operators to evaluate their leak detection capabilities and upgrad ;\nthem where necessary. OPS does not know how many operators with less than 500 miles of\npipeline currently have leak detection capabilities nor how many of those existing systems wi 1\nrequire upgrading. Evaluation and upgrading, if necessary, of leak detection capability is\nintegrally related to the required addition of mitigative features since leak detection would\nprovide the information necessary to activate those mitigative features or procedures.\nInstallation of EFRDs\nThe OPS does not know how many of the manually operated block valves currently installed iin\nthe 5,440 miles of impacted pipeline will be converted to EFRDs as a consequence of the\nregulatory change. (OPS also has no knowledge of other mitigation or prevention actions thal.\nmight be taken.) It is estimated that 84.1 percent of all valves currently installed on hazardou;;\nliquid pipelines are manually operated block valve^.^ The rule specifies factors that operators\nmust consider in deciding whether to convert these valves to remote operation or to install otl ier\npreventive or mitigative features. These factors are:\nswiftness of leak detection and pipeline shutdown capabilities\ntype of commodity camed\nrate of potential leakage\nvolume that can be released\ntopography or pipeline profile\npotential for ignition\nproximity to power sources\nlocation of nearest response personnel\nspecific terrain between the pipeline and the high consequence area\nbenefits expected by reducing spill size\nOperators will only install EFRD’s in pipelines where installation of an EFRD would prove 1 o be\nbeneficial. That is the cost of the installation and maintenance of the EFRD would be less than\nthe potential benefit.\nBENEFITS\nTo help reduce hazardous liquid pipeline incidents and their consequences, OPS is requiring that\npipeline integrity management plans be developed and implemented by operators with less tl ian\n5\nOffice of Pipeline Safety, Emergency Flow Restricting Devices Study (A Study Mandated by P.L. 100-561), 1. .S.\nDOT, April 1990. The original source of the information was reported to be the American Petroleum Institute.\n11\n\n<<<PAGE 13>>>\n\n500 aggregate miles of pipeline. These plans are to provide for inspection and testing of pipeline\nthat could affect high consequence areas, which are high-density population areas, navigable\nwaterways, and unusually sensitive areas. In addition, the rule requires that the plans identify any\nsites where Emergency Flow Restricting Devices (EFRDs) would significantly reduce the risk to\na high consequence area from a pipeline spill and that the operators install EFRDs at those sit :s\nand that affected operators evaluate leak detection capability and upgrade it if necessary.\nThe benefits resulting from the regulatory change are discussed in this section. Those benefitis\nare expected to result from improvements in pipeline safety performance attributable primaril y\nto: ( 1 ) the development of a framework for integrity management that assists operators in\ndetermining and identifying risks to their pipelines in high consequence areas that could bene fit\nfrom periodic testing or other examination, (2) reassurance to the public that pipelines in higl-1\nconsequence areas receive the necessary levels of attention that ensure their integrity (3)\nincreases in inspection and testing on pipelines in or near high consequence areas and (4) the\ninstallation of improved leak detection or additional EFRDs on pipelines in or near high\nconsequence areas.\nPipeline operators also have strong incentives to ensure the integrity of their pipelines. In\naddition to the positive safety and environmental benefits, the lost product and unscheduled\ndowntime for repairs following a major incident can significantly impact the company’s final icial\nperformance and its ability to satisfy customer commitments. Operators cannot afford to haw e\nthese critical transportation assets out of service for lengthy periods of time in today’s\ncompetitive business environment. In addition, the damage to the company’s public image aiid\nreputation, as well as the legal implications of serious incidents, can pose an even broader a d\nlonger term negative impact on the company’s business operations. For these and other reasc ns,\nmany pipeline operators have implemented and are continuing to improve more systematic s ifety\nand environmental management processes.\nDevelopment of Integrity - Plans And Framework\nThe single most important part of this rule is the requirement for the integrity plan and\nframework. The creation, development and implementation of these documents will provide for\nthe necessary integration of information regarding pipeline condition. Integration is importa nt to\nassure OPS, and the public, that pipeline operators are considering fully the unique risks tha\nhazardous liquid pipelines pose to high consequence areas. Plan development will assure ncit\nonly that they are considering these risks but that they have developed a plan that requires e, tra\nscrutiny and precautions in these areas to safeguard the public and the environment. These\nsafeguards include the use of periodic testing and the installation of EFRD’s where they are\nappropriate. The public is apprehensive that “aging” hazardous liquid pipelines pose a dangi :Tous\nthreat to the safety and environmental health of their community. The development and\nimplementation of an integrity management plan that requires a periodic testing schedule shimld\nprovide the public as well as the OPS some level of assurance that pipeline operators have\n12\n\n<<<PAGE 14>>>\n\nprovided significantly to the protection of public safety and the environment in these sensitivt 8\nareas.\nSince integrity management systems are not universal across the industry, OPS believes that i\nrequirement that such plans be developed is necessary. The rule requires that plans be develo ped\nand specifies considerations that must be taken into account in that development. Developmt nt\nof the plans will involve consideration of risk factors unique to particular pipelines and high\nconsequence areas. Operators will be required to establish a periodic assessment program in\nwhich all segments in high consequence areas are pressure tested or internally inspected no le ss\nfrequently than once every five years, unless an exception is justified, and the entire pipeline s\nevaluated, and to determine how experience in other areas should be a factor in HCA’s.\nEvaluation is an ongoing process. Operators will be expected to consider the risk factors and\ntheir relative priorities in establishing assessment schedules. This allows operators to develo I an\ninternal inspection and testing program that is customized to the particular operating\ncharacteristics and risks associated with different portions of their system(s).\nInspection And Testing\nThe inspection and testing required by the regulatory change will be some combination of in- line\ninspection (i.e., high resolution, low resolution, and ultrasonic instrumented pigging), pressui e\ntesting (i.e., hydrostatic testing), and equivalent alternative testing (Le., testing using other\ntechniques or tools that provide a level of safety and environmental protection comparable to\npigging and hydrostatic testing).\nThe change will spur operators with less than 500 miles of pipeline to identify and correct\npotential problems in pipelines in high consequence areas that might otherwise be missed. The\nmain types of potential problems that can be helped by inspection and testing are those relatii lg to\n(1) intemal corrosion, (2) external corrosion, and (3) ruptures of previously damaged pipelinl:.\nOther types of potential pipeline problems may also be helped, but to a significantly lesser dt g e e\nthan these.\nThe expected benefit of increased internal inspection and pressure testing will be a reduction in\nincidents and incident consequences. Consequently, the benefits that are expected to result f 1-om\nthe regulatory change are reduced (1) deaths, (2) major and minor injuries, (3) property damlige,\n(4) spilled product, (5) recovered product, (6) environmental damage, and (7) other\nconsequences.\nBenefits of Increased Inspection and Testing\nThe expected benefit of increased inspection and testing will be a reduction in incidents cau:,ed\nby internal corrosion, external corrosion, and ruptures of previously damaged pipeline and irl\ntheir consequences. This benefit will be a function of (1) the additional pipeline mileage tesled\nper year, (2) the expected reduction in incidents and consequences that will be attributable tci\n13\n\n<<<PAGE 15>>>\n\ninspection and testing, and (3) the expected annual incident and consequence rates on the\nrelevant mileage.\nThe Additional Mileage Tested Per Year\nAdditional mileage inspected and tested during the first five years following the effective datc of\nthe rule will be 78 miles. During each of the next two years, 1,168 additional miles of pipelir e\nwill be inspected and tested each year, and 1 10 additional miles of pipeline will be inspected md\ntested annually from then on (described above).\nWith respect to deaths and serious injuries, the following assumptions are made:\nA life is valued at $2.7 million\nA serious injury is valued at $490 thousand\nThese valuations are standard assumptions currently used in Office of Pipeline Safety and DC bT\nbenefit/cost analyses.\nEnhanced Leak Detection and EFRDs\nIn addition to inspection and testing, the regulatory change requires that leak detection be\nupgraded where necessary and that other preventive and mitigative actions be considered whl :re\nthe benefit exceeds the costs. One example of such measures that is used here for purposes c f\nillustration is that Emergency Flow Restricting Devices (EFRDs) be installed at locations in I )r\nnear high consequence areas where they would significantly reduce ri","truncated":true,"body_characters":83827}