# U.S. DOT/RSPA - Final Regulatory Evaluation - **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:** Not available - **effective on:** Not available - **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:** <<>> 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 <<>> INTRODUCTION The U.S. Department of Transportation Research and Special Programs Office of Pipeline Safety (OPS) is changing pipeline safety regulations to require operators of certain hazardous liquid pipelines to validate the integrity of their pipelines in high consequence areas (HCAs). The rile would apply to operators with less than 500 aggregate miles of pipeline. (Requirements for operators with more than 500 miles of hazardous liquid pipeline were established in a previoi is rulemaking). The objective of the change is to reduce the risk of hazardous liquid pipeline incidents in these areas. OPS defines a high consequence area as one in which there is a high population area or densely populated area, a commercially navigable waterway, or an unusua ly sensitive area. To validate the integrity of their pipelines in high consequence areas under thi : regulatory change, pipeline operators must implement an integrity management program for : uch pipelines including periodic inspection and testing and integration of information related to pipeline integrity. The purpose of this report is to assess the benefits and costs of the regulatc ~ r y change. TARGET PROBLEM Hazardous liquid pipeline spills can have an adverse impact on human health and the environment. The magnitude of this impact differs. There are some areas in which the impa :t of a spill will be more significant than it would be in others due to concentrations of people whc I could be affected or to the presence of environmental resources that are unusually sensitive tc 1 damage. Because of the potential for dire consequences of pipeline failures in certain areas, these areas merit a higher level of protection. OPS is promulgating this regulation to afford the necessary additional protection to these “high consequence areas”. Numerous investigations by OPS and the National Transportation Safety Board (NTSB) havi : highlighted the importance of protecting the public and environmentally sensitive areas fron L pipeline failures. NTSB has made several recommendations to ensure the integrity of pipeliries near populated and environmentally sensitive areas. These recommendations included requi ing periodic testing and inspection to identify corrosion and other damage, establishing criteria ti 1 determine appropriate intervals for inspections and tests, determining hazards to public safet 1 1 fiom electric resistance welded pipe and requiring installation of automatic or remotely-oper ited mainline valves on high-pressure lines to provide for rapid shutdown of failed pipelines. Congress also directed OPS to undertake additional safety measures in areas that are densely populated or unusually sensitive to environmental damage. These statutory requirements included having OPS prescribe standards for identifying pipelines in high density population areas, unusually sensitive environmental areas, and commercially navigable waters; issue standards requiring periodic inspections using internal inspection devices on pipelines in der lsely- populated and environmentally sensitive areas; and survey and assess the effectiveness of 1 <<>> emergency flow restricting devices, and prescribe regulations on circumstances where an operator must use the devices. This rulemaking addresses the target problem described above, and is a comprehensive respoi ise to NTSB’s recommendations and Congressional mandates, as well as pipeline safety and environmental issues raised over the years. ALTERNATIVES CONSIDERED OPS considered several alternatives to provide the necessary increased level of protection to 1 iigh consequence areas. These alternatives were: 1. No action. 2. Prescriptive requirements for inspection and repair of pipelines in high consequence areas and for incorporating accident mitigative features and improved leak detection. 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 iisk and to add accident mitigative features and improved leak detection based on risk. 4. Requiring pipeline operators to develop integrity management programs providing for expedited inspection and testing. INITIAL SCREENING OF ALTERNATIVES 1. No action. Pipeline operators currently manage their pipeline to avoid accidents, leaks and spills. They perform inspection and testing on their pipelines to assess their integrity, and make repairs as they conclude they are needed. These actions would be expected to continue under the “no action” a1 ternative. Pipeline leaks, spills, and ruptures occur, despite the existence of these operator programs. Major pipeline spills have occurred in the last two years, of which two were particularly notallle, (Bellingham and PEPCO). In both cases, in-line inspection (pigging) of the pipeline had taki :n place. Operators either failed to recognize the significance of indications from the pig runs or failed to integrate that information with other information about the pipeline, including the presence of construction activity in the area. OPS concludes that validation of these prograrr s through audit and review by outside parties, i.e, the regulator, is necessary to help assure that appropriate actions are taken. In addition, continuation of voluntary programs cannot be assured absent some regulatory requirement. Pipeline operators must be responsive to market conditions, and future change! in economic conditions could lead to curtailment or elimination of some or all inspection and testing. 2 <<>> OPS concludes that assuring continuation of pipeline integrity management programs, assurir g that their scope encompasses all areas requiring special protection, and verifying their adequa :y are necessary to assure that the requisite level of protection will be provided. This assurance cannot be provided without some regulatory requirement addressing the target problem. In addition, continued reliance on voluntary industry efforts would not be responsive to the Congressional mandate that OPS promulgate requirements to assure protection of the areas th at are herein designated as high consequence areas. For these reasons, the “no action” alternative was not considered further 2. Prescriptive requirements for inspection and repair of pipelines in high consequence areas and for incorporating accident mitigative features and improved leak detection. Pipeline circumstances differ, even within high consequence areas. These differences would make it difficult, at best, to establish prescriptive requirements that would appropriately addri :ss all possible combinations of pipeline size, type, and configuration or to consider other factor: that contribute to the risk of failure of a particular pipeline. It is likely that creating detailed prescriptive requirements would result in a need for a large number of waivers to address the issues of importance to specific pipelines and high consequence areas. The result would be a patchwork of specific, but different requirements. It would be an inefficient use of industry 2 nd government resources to establish requirements in this fashion. Compliance inspection woulij still require that the requirements applicable to specific pipelines be identified for comparisoi L with ongoing practices. Prescriptive requirements also would tend to stifle technological innovation. They do not all iw for different approaches based on advances in the technology. The technology associated wi. h in-line inspection of pipelines (i.e., pigging) is advancing at a rapid pace. Establishing prescriptive requirements could slow this advancement, or could preclude use of new techniciues that may be developed. In the extreme, prescriptive requirements could stop technological innovation in this area completely. Most importantly, however, establishing prescriptive requirements would not assure the integration of information which experience has shown is vital to preventing pipeline accidei its. As noted above, two major accidents have occurred in recent years despite the fact that the pipelines involved had been pigged. It appears that other information was available that, if correlated to the pig results, could have highlighted the need for action regarding the indicatilms that ultimately resulted in failure of the pipe. An integrity management program is required o assure this integration of available information. Outside review of the integrity management program (Federal and state) by regulators, is necessary to assure that it is complete and propt rly implemented. This outside review cannot be assured without a requirement for such a progr im. For these reasons, the option of establishing prescriptive requirements was not evaluated fur her. 3 <<>> 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 develop integrity management programs and prov ide for the necessary integration of information. They have the best knowledge of their pipelines and the factors affecting its risk. Integration of information requires that the management system:, of the company be aligned and operated to assure that necessary information is shared and that i. is evaluated in its proper context by knowledgeable personnel. These are actions that are difficii It to require through prescriptive regulation. Requiring that operators develop such programs is the best way to assure that they exist. Such a requirement also provides the regulatory basis for (IPS to audit, review, and assess these programs and their implementation. The best integrity management plans, when implemented properly, can reduce the risk of pipi :line accidents. They cannot, however, eliminate that risk. Leaks and ruptures could still occur, fmm unforseen outside impacts on the pipeline or fkom unanticipated interactions among factors contributing to pipeline risk. It is therefore important that features and procedures be available to detect and mitigate the effects of accidents that may occur. Here again, circumstances differ between pipelines and between regions and local jurisdictioi is. The differences make it difficult to establish prescriptive requirements that will provide the bl:st protection for each high consequence area. Requiring that operators explicitly consider the n :ed for improved leak detection and for mitigative features and provisions and that they impleme it those found necessary is the most effective means of providing such protection. Such a requirement also provides the regulatory basis for audit and review by OPS and state regulatclrs. For these reasons, this option was selected for fbrther development. 4. Requiring pipeline operators to develop integrity management programs providing for expedited inspection and retesting. OPS considered the need for requiring integrity management programs that would require inspection and testing of pipelines to recur over short intervals, a few years. The ability to require frequent testing is limited by the available resources for testing and inspection. The companion rule originally proposed for operators with more than 500 miles of pipeline included requirements for reassessment at ten-year intervals. Based upon consideration of comments received, that interval was reduced in the final rule to five years, with limited excpetions. OPS concluded that the spur provided by the regulation would be Iikely to resul. in an increase in testing capacity over the next five years that will then be able to accommodate testing at accelerated rates. OPS considers it important to inspect and test pipeline in high consequence areas at an aggressive rate in order to assure the additional protection desired fclr these areas. OPS concludes that a similar interval is appropriate for operators with less than 500 4 <<>> miles of pipeline because the increased testing capacity will also be available to them and because their historical testing rate is at a similar fiequency. BASELINE REGULATORY ENVIRONMENT In order to assess the costs and benefits of the new regulation, it is necessary to first ascertain the current level of activity in areas addressed by the rule. In this instance, it is necessary to determine the rate at which pipeline inspections are being performed, the presence of prevent ve and mitigative features, and the prevalence and nature of integrity management plans similar o those required by the rule. Informal discussions with operators with less than 500 miles of pipeline have identified that r iiost have a regular assessment program. A large majority appear to test all of their pipelines on a fi-equency of five years or less. OPS assumes that this rate applies to piping in high conseque nce areas and that this rate would have continued absent a regulatory requirement to increase it. Much of the testing being conducted by these operators is the initial inspection of pipelines. The rate at which subsequent inspections would be performed is now unknown. It is likely that s( )me pipeline would be identified for reinspection frequently (e.g., every five years). It is equally likely that some pipeline would not be reinspected at all. OPS also has limited knowledge about the nature and extent of preventive and mitigative fea ures and procedures that have been implemented by pipeline operators. The mitigative feature fo1 which OPS has the best knowledge is emergency flow restriction devices (EFRDs). EFRDs ,ire check valves or remotely operated valves, usually block valves, that can reduce the amount o F product lost in a pipeline leak. It is estimated that 84.1 percent of all valves currently instal ed on hazardous liquid pipelines are manually operated block valves.’ OPS has no knowledge c f current plans to convert any of these valves to remote operation. Integrity plans are a key element of this rule. To better understand and promote more comprehensive and integrated approaches to safety and environmental protection, OPS creatc :d the Risk Management Demonstration Program, and the System Integrity Inspection (SII) Pilclt Program. These programs encourage and evaluate operator-developed safety and environmeiital management processes that incorporate operator- and pipeline-specific information and data to identify, assess, and address pipeline risks. These programs, along with the Oil Spill Respor se Plan Review and Exercise Program, are helping RSPA’s Office of Pipeline Safety (OPS) ref ne its regulatory oversight processes. These processes help to ensure that pipeline operators ha7 re effective processes in place to identify the most important risks to the public and the environment, and to develop and implement cost-effective preventive and mitigative actions to ‘Office of Pipeline Safety, Emergency Flow Restricting Devices Study (A Study Mandated by P.L. 100-561), U S. DOT, April 1990. The original source of the information was reported to be the American Petroleum Institute. 5 <<>> manage these risks. Many of these initiatives have validated the importance of focusing resources and establishing higher levels of protection in areas where a pipeline failure could have significant consequences. Through the Risk Management Demonstration Program and the System Integrity Inspection F ilot Program, OPS has improved its understanding of pipeline operator integrity management syst lems and activities. This experience has shown that a number of liquid pipeline operators have formalized management systems to identify and address the most significant integrity threats o their pipeline systems. In the Risk Management Program, participants perform systematic an1 i comprehensive risk assessments to identify the specific nature and location of the most significant risks posed by operation of their pipeline system. An essential feature of these risl assessments is the integration of information from many diverse sources to fully understand tl le integrity threats at specific locations on the pipeline. Environmental consequences and the imiDact on nearby population are explicitly considered in these risk assessments. Through formal, rislc- based decision making processes, these companies use the risk assessment results to identify projects and activities that address potential system integrity threats, thereby preventing oil SF ills. The risk management process also examines the consequences of potential releases and explc res opportunities to minimize the environmental and public safety and health impacts should a failure occur. These investigative risk management programs, and the preventive and mitigal ive risk control activities that evolve from them, supplement the minimum regulatory requiremer Its established in 49 CFR 195 to protect the public and the environment. The System Integrity Inspection Program is focused on developing a more integrity-based approach to OPS inspections. Instead of using a “checklist” approach, OPS is focusing the inspection process on an operator’s integrity management processes and activities. Through working with the operator, OPS is able to understand and influence the methods and approac lies used to assess pipeline integrity, and the approaches to integrating integrity assessment data with other pipeline specific information to identify the most significant integrity threats to the systlem. Specifically, OPS has observed how operators examine internal inspection data in conjunctia n with other surveillance and operating data, expected population growth, land use, constructic n activity along the pipeline, and other information relevant to assuring the integrity of the pipt line in high population areas and in environmentally sensitive areas. Through this interaction OP S is acquiring a broader understanding and a greater confidence that effective programs are in pla :e to address the most significant risks. Similar to the Risk Management Program, the SI1 Program is emphasizing how operators evaluate their system condition and its risks, and use this information to make sound integrity management decisions. OPS experience in the Risk Management Demonstration Program and the System Integrity Inspection Program indicates that integrity management programs such as that required by tk is rule have been developed. They are far from universal, however. 6 <<>> SCOPE AND PARAMETERS OF ANALYSIS This analysis of benefits and costs takes the following approach. First, the mileage impacted iy the regulatory change is identified and estimated. Then the potential benefits of the rule are discussed. In the next section the potential costs of the rule are examined. Finally, a discussicln of the costs versus the benefits is examined. It should be noted that, unless otherwise specific d, all dollar values in this report are given in constant 1998 dollars.2 Furthermore, this analysis 'vi11 arbitrarily consider only the first twenty years after the effective date of the final rule. Includi ng additional years would not be expected to materially affect the conclusions of this analysis. ANALYSIS Impacted Mileage In this section the total hazardous liquid pipeline mileage impacted by the regulatory change i s estimated. That mileage is located in or nearby high consequence area's, defined by the chan 1;e as: (1) high population areas, (2) densely populated areas, (3) commercially navigable waterways, and (4) unusually sensitive areas. Total PiDeline Mileage In total, there is an estimated 157 thousand miles of regulated hazardous liquid pipelines in tlie U.S.3 This change would not impact all hazardous liquid pipeline operators. Rather, it woulc I impact only those operators with an aggregate of less than 500 miles of pipeline. The Office of Pipeline Safety (OPS) estimates that these operators have 13.3 percent of the jurisdictional hazardous liquid pipeline mileage.4 Thus, the operators covered by the rule are expected to h ave about 20,900 miles of regulated hazardous liquid pipelines. Impacted Mileage in High Population And Densely Populated Areas Because of the similar nature of the two types of areas, the impacted pipeline mileages in higln population areas and in densely populated areas are considered together. As defined by the 'Dollars are converted from nominal values to real 1998 values using the Producer Price Index (PPI), Intermed ate Materials, Supplies, and Components. The source of the PPI index numbers is the U.S. Bureau of Statistics Wt b page. 'Jurisdictional hazardous liquid pipeline mileage for 1999. This mileage was obtained from Office of Pipeline Saf: :ty User Fee Assessments. 'This percentage estimate was based on information from Office of Pipeline Safety User Fee Assessments. This estimate may overstate the actual percentage operated by operators with less than 500 miles of pipeline, becaus some operators may report pipeline segments using multiple names. Therefore, some operators with apparent11 little pipeline mileage may actually be part of larger operators. 7 <<>> regulatory change, a high population area is one with 50,000 or more people in total and at lezist 1,000 people per square mile. A densely populated area is defined as any place containing a concentrated population, such as an incorporated or unincorporated town or village. The OPS estimates that 16,500 miles of regulated hazardous liquid pipeline are located in higli population areas and another 5,500 miles are located in densely populated areas. It is likely tl lat only part of this 22,000 miles is pipeline covered by the rule. Since 13.3 percent of the total mileage is operated by operators with less than 500 miles of pipeline, it appears reasonable to assume, in the absence of contrary information, that 13.3 percent of the mileage located in hii1,h population and densely populated areas, or 2,930 miles of pipeline, is operated by these operators. Impacted Mileage Near Commercially Navigable Waterways The regulated pipeline mileage in or near commercially navigable waterways includes (1) the mileage crossing those waterways and (2) the mileage lying near enough to the waterways to adversely impact them, should a leak, spill, or rupture occur. The OPS estimates that 800 miles of regulated hazardous liquid pipeline are in or near navigilble waterways. It is likely that only part of this mileage is pipeline within the scope of this rulemaking. Since 13.3 percent of the total mileage is operated by operators with less than 500 miles of pipeline, it appears reasonable to assume that 13.3 percent of the mileage in or near navigable waterways, or 1 10 miles of pipeline, is operated by these operators. Impacted Mileage in Unusually Sensitive Areas A pilot test relating to unusually sensitive areas (USAs) was recently conducted by the U.S. Department of Transportation (U.S. DOT) and the American Petroleum Institute (API). This pilot test covered pipelines in California, Louisiana, and Texas. One product from this pilot t:est was an estimate of the jurisdictional pipeline mileage in USAs or that could affect a USA. rl he pilot test results indicate that 14.2 percent of hazardous liquid pipeline mileage in the three s ates is located in a USA. Some of this pipeline was also located in high- or densely-populated ar :as. Pilot program results indicate that 2.7 percent of hazardous liquid pipeline mileage in the thr :e states was in both a USA and a populated area. Thus, 1 1.5 percent of pipeline mileage in thc pilot states was in a USA but not otherwise encompassed within the definition of a high consequence area. For purposes of this analysis, OPS has assumed that the same percentage of hazardous liquid pipeline mileage in other states is located in USAs but not otherwise in a hi gh consequence area. This percentage multiplied by the total hazardous liquid mileage of opere tors with less than 500 miles of pipeline, 20,900 miles, results in an estimate of 2,400 miles for t le pipeline mileage of these operators that is located in USAs. 8 <<>> Total ImDacted Mileage Given the estimates derived above for the impacted mileage in or nearby high consequence ar :as, a total of 5,440 miles of regulated hazardous liquid pipeline is expected to be impacted by the regulatory change. Mileage Impacted Per Year The regulatory change calls for inspection and testing, improving leak detection where appropriate, and the use of additional prevention or mitigation measures where necessary. Ar example of such a measure includes the installation of Emergency Flow Restricting Devices (EFRDs) at selected points. For the purpose of illustration this analysis examines the potentiill costs of installation of EFRD’s, although EFRD’s are only one alternative among many possi ;)le preventive and mitigative measures that operators could choose. The mileages impacted per year will be important inputs in the calculation of the benefits and costs of inspection and tesl ing and the benefits of the installation of the EFRDs. Inspection and Testing The regulatory change requires baseline and subsequent testing of the impacted mileage usin] ; in- line inspection, pressure testing, or alternative methods. Acceptable in-line inspection includ es high resolution, low resolution, and ultrasonic pigging. Acceptable pressure testing consists )f hydrostatic testing. Acceptable alternative methods include any other methods that would provide a level of safety equivalent to that provided by internal inspection or pressure testing Baseline Testing The rule requires that baseline testing be completed within seven years of the effective date clf the rule. Informal discussions with operators with less than 500 miles of pipeline have identified that most have a regular assessment program. A large majority appear to test all of their pipeline ; on a frequency of five years or less. Thus, it would appear that they would need to test no addit onal mileage beyond that otherwise planned in order to meet the requirements for baseline inspec ion. OPS recognizes, however, that there are probably some companies not already conducting assessments at frequencies consistent with the rule, even though the overall amount of inspe1:tion and assessment in the industry is more than would be required. OPS has conservatively assL med that as much as 10 percent of impacted mileage, or 544 miles, may require unplanned assessinent over a seven year period (78 miles per year). 9 <<>> Once baseline testing has been performed on a segment of pipe, the rule requires that subsequlmt testing be undertaken on that segment, based on risk factors, at least once every five years (wilh limited exceptions). The planned rate of re-testing of pipeline by operators with less than 50C miles of pipeline is unknown. Informal discussions with pipeline operators indicate that muc’i pipeline mileage would have been re-tested frequently (e.g., every five years), while some mileage would not have been re-tested at all. Since most operators with less than 500 miles of pipeline appear to test their pipelines every 1 ive years or more often, it should only require minor changes in scheduling specific pipe segmenl s for assessment to assure that all pipe is inspected at least every five years. OPS therefore concludes that there could be limited additional assessment needed by operators with less tha 1 500 miles of pipeline in order to meet requirements for re-assessment at a five-year fi-equencj . For the reasons described above, OPS has again estimated for this analysis that 10 percent of impacted mileage will require unplanned assessment. Operators with less than 500 miles of pipeline will therefore need to assess an additional two percent of their impacted mileage annually (1 10 miles) to meet the requirements for subsequt nt assessment. OPS expects that operators will identify some pipeline in high consequence area s for which a longer inspection interval can be justified, and that they will seek OPS review to permit these segments to be tested at a longer interval. OPS has not adjusted this analysis to account for these longer-interval re-assessments, since the information obtained by informal discussions with operators indicates limited unplanned assessment should be required and ou r assumption that 10 percent of impacted mileage will require unplanned assessment should btlund any additional costs. Pipeline operators will need to do some subsequent testing at the same time they are doing baseline testing. This subsequent testing will begin in the sixth year of baseline testing, which is when mileage “baseline tested” in the first year after the final rule will need to be re-tested. During the sixth and seventh years of baseline testing, subsequent and baseline testing will overlap. Assuming that most re-testing would have been deferred until all initial testing was completed in the absence of a regulatory requirement, all subsequent testing in those two years will be over and above what would have been done in the absence of the rule. The full 1,09(1 miles undergoing subsequent testing during each of these two years is therefore assumed to be in excess of what would have been done. This analysis also assumes that 78 miles of additional pipeline must be inspected in each of these two years to complete baseline inspection (see ab we) so that the total of additional mileage that will require inspection during these years is 1,168 miles. 10 <<>> Enhanced Leak Detection The rule includes criteria for operators to evaluate their leak detection capabilities and upgrad ; them where necessary. OPS does not know how many operators with less than 500 miles of pipeline currently have leak detection capabilities nor how many of those existing systems wi 1 require upgrading. Evaluation and upgrading, if necessary, of leak detection capability is integrally related to the required addition of mitigative features since leak detection would provide the information necessary to activate those mitigative features or procedures. Installation of EFRDs The OPS does not know how many of the manually operated block valves currently installed iin the 5,440 miles of impacted pipeline will be converted to EFRDs as a consequence of the regulatory change. (OPS also has no knowledge of other mitigation or prevention actions thal. might be taken.) It is estimated that 84.1 percent of all valves currently installed on hazardou;; liquid pipelines are manually operated block valve^.^ The rule specifies factors that operators must consider in deciding whether to convert these valves to remote operation or to install otl ier preventive or mitigative features. These factors are: swiftness of leak detection and pipeline shutdown capabilities type of commodity camed rate of potential leakage volume that can be released topography or pipeline profile potential for ignition proximity to power sources location of nearest response personnel specific terrain between the pipeline and the high consequence area benefits expected by reducing spill size Operators will only install EFRD’s in pipelines where installation of an EFRD would prove 1 o be beneficial. That is the cost of the installation and maintenance of the EFRD would be less than the potential benefit. BENEFITS To help reduce hazardous liquid pipeline incidents and their consequences, OPS is requiring that pipeline integrity management plans be developed and implemented by operators with less tl ian 5 Office of Pipeline Safety, Emergency Flow Restricting Devices Study (A Study Mandated by P.L. 100-561), 1. .S. DOT, April 1990. The original source of the information was reported to be the American Petroleum Institute. 11 <<>> 500 aggregate miles of pipeline. These plans are to provide for inspection and testing of pipeline that could affect high consequence areas, which are high-density population areas, navigable waterways, and unusually sensitive areas. In addition, the rule requires that the plans identify any sites where Emergency Flow Restricting Devices (EFRDs) would significantly reduce the risk to a high consequence area from a pipeline spill and that the operators install EFRDs at those sit :s and that affected operators evaluate leak detection capability and upgrade it if necessary. The benefits resulting from the regulatory change are discussed in this section. Those benefitis are expected to result from improvements in pipeline safety performance attributable primaril y to: ( 1 ) the development of a framework for integrity management that assists operators in determining and identifying risks to their pipelines in high consequence areas that could bene fit from periodic testing or other examination, (2) reassurance to the public that pipelines in higl-1 consequence areas receive the necessary levels of attention that ensure their integrity (3) increases in inspection and testing on pipelines in or near high consequence areas and (4) the installation of improved leak detection or additional EFRDs on pipelines in or near high consequence areas. Pipeline operators also have strong incentives to ensure the integrity of their pipelines. In addition to the positive safety and environmental benefits, the lost product and unscheduled downtime for repairs following a major incident can significantly impact the company’s final icial performance and its ability to satisfy customer commitments. Operators cannot afford to haw e these critical transportation assets out of service for lengthy periods of time in today’s competitive business environment. In addition, the damage to the company’s public image aiid reputation, as well as the legal implications of serious incidents, can pose an even broader a d longer term negative impact on the company’s business operations. For these and other reasc ns, many pipeline operators have implemented and are continuing to improve more systematic s ifety and environmental management processes. Development of Integrity - Plans And Framework The single most important part of this rule is the requirement for the integrity plan and framework. The creation, development and implementation of these documents will provide for the necessary integration of information regarding pipeline condition. Integration is importa nt to assure OPS, and the public, that pipeline operators are considering fully the unique risks tha hazardous liquid pipelines pose to high consequence areas. Plan development will assure ncit only that they are considering these risks but that they have developed a plan that requires e, tra scrutiny and precautions in these areas to safeguard the public and the environment. These safeguards include the use of periodic testing and the installation of EFRD’s where they are appropriate. The public is apprehensive that “aging” hazardous liquid pipelines pose a dangi :Tous threat to the safety and environmental health of their community. The development and implementation of an integrity management plan that requires a periodic testing schedule shimld provide the public as well as the OPS some level of assurance that pipeline operators have 12 <<>> provided significantly to the protection of public safety and the environment in these sensitivt 8 areas. Since integrity management systems are not universal across the industry, OPS believes that i requirement that such plans be developed is necessary. The rule requires that plans be develo ped and specifies considerations that must be taken into account in that development. Developmt nt of the plans will involve consideration of risk factors unique to particular pipelines and high consequence areas. Operators will be required to establish a periodic assessment program in which all segments in high consequence areas are pressure tested or internally inspected no le ss frequently than once every five years, unless an exception is justified, and the entire pipeline s evaluated, and to determine how experience in other areas should be a factor in HCA’s. Evaluation is an ongoing process. Operators will be expected to consider the risk factors and their relative priorities in establishing assessment schedules. This allows operators to develo I an internal inspection and testing program that is customized to the particular operating characteristics and risks associated with different portions of their system(s). Inspection And Testing The inspection and testing required by the regulatory change will be some combination of in- line inspection (i.e., high resolution, low resolution, and ultrasonic instrumented pigging), pressui e testing (i.e., hydrostatic testing), and equivalent alternative testing (Le., testing using other techniques or tools that provide a level of safety and environmental protection comparable to pigging and hydrostatic testing). The change will spur operators with less than 500 miles of pipeline to identify and correct potential problems in pipelines in high consequence areas that might otherwise be missed. The main types of potential problems that can be helped by inspection and testing are those relatii lg to (1) intemal corrosion, (2) external corrosion, and (3) ruptures of previously damaged pipelinl:. Other types of potential pipeline problems may also be helped, but to a significantly lesser dt g e e than these. The expected benefit of increased internal inspection and pressure testing will be a reduction in incidents and incident consequences. Consequently, the benefits that are expected to result f 1-om the regulatory change are reduced (1) deaths, (2) major and minor injuries, (3) property damlige, (4) spilled product, (5) recovered product, (6) environmental damage, and (7) other consequences. Benefits of Increased Inspection and Testing The expected benefit of increased inspection and testing will be a reduction in incidents cau:,ed by internal corrosion, external corrosion, and ruptures of previously damaged pipeline and irl their consequences. This benefit will be a function of (1) the additional pipeline mileage tesled per year, (2) the expected reduction in incidents and consequences that will be attributable tci 13 <<>> inspection and testing, and (3) the expected annual incident and consequence rates on the relevant mileage. The Additional Mileage Tested Per Year Additional mileage inspected and tested during the first five years following the effective datc of the rule will be 78 miles. During each of the next two years, 1,168 additional miles of pipelir e will be inspected and tested each year, and 1 10 additional miles of pipeline will be inspected md tested annually from then on (described above). With respect to deaths and serious injuries, the following assumptions are made: A life is valued at $2.7 million A serious injury is valued at $490 thousand These valuations are standard assumptions currently used in Office of Pipeline Safety and DC bT benefit/cost analyses. Enhanced Leak Detection and EFRDs In addition to inspection and testing, the regulatory change requires that leak detection be upgraded where necessary and that other preventive and mitigative actions be considered whl :re the benefit exceeds the costs. One example of such measures that is used here for purposes c f illustration is that Emergency Flow Restricting Devices (EFRDs) be installed at locations in I )r near high consequence areas where they would significantly reduce ri - **truncated:** true - **body characters:** 83827