{"operation":"document","citation":"0900006480e8a8ce","title":"U.S. DOT/RSPA - Draft 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 Draft Final Regulatory Evaluation Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) Docket RSPA-00-7666 Prescriptive requirements also would tend to stifle technological innovation. They do not allc w for different approaches based on advances in the technology. The technology associated wit1 i in- line inspection of pipelines (Le., pigging) is advancing at a rapid pace. Establishing prescriptive requirements could slow...","machine_formats":{"json":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e8a8ce.json","markdown":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e8a8ce.md"},"app_url":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e8a8ce","source_url":"https://downloads.regulations.gov/PHMSA-RSPA-2000-7666-0166/attachment_1.pdf","body":"<<<PAGE 1>>>\n\nU.S. Department of Transportation\nResearch and Special Programs Administration\nDraft Final Regulatory Evaluation\nPipeline Integrity Management in High Consequence Areas\n(Gas Transmission Pipelines)\nDocket RSPA-00-7666\n\n<<<PAGE 2>>>\n\nINTRODUCTION\nThe U.S. Department of Transportation Research and Special Programs Office of Pipeline Sal ety\n(OPS) is proposing to change pipeline safety regulations to require operators of certain pipelir es\nto validate the integrity of their pipelines in high consequence areas. The rule would apply to\noperators of natural and other gas transmission lines. The objective of the change is to reduce the\nrisk of pipeline incidents in these areas. The OPS defines a high consequence area as:\nAll class 3 & 4 locations. These are areas where there are at least 46 buildings intend€ d\nfor human occupancy or where buildings with four or more stories above ground are\nprevalent within 660 feet of the pipeline along any continuous mile of its length. (Are i s\nwithin class 3 & 4 locations but outside of the “potential impact zone”, as defined in tl le\nproposed rule, are considered medium consequence areas).\nLocations where any hospital, school or other facility having persons who are confineci or\nof limited mobility are in a circular impact zone having radius equal to a “threshold\nradius” defined based on the diameter and operating pressure of the pipeline.\nLocations where 20 or more persons congregate at least 50 days in any 12-month peric d\nare in this circular impact zone (pipeline within 100 yards of such locations is conside .ed\nclass 3 under the current definition in 49 CFR 192.5).\nLocations where the radius of the circular impact zone exceeds 660 feet and where an!\ncircle of 1000 ft. radius (or larger for some large-diameter, high-pressure pipelines)\ncentered on the pipeline includes 20 or more buildings intended for human occupancy\nThe 20 building limit within a 1000 ft. radius circle has been established to ensure the\nsame building density as in Class 3 Locations (see above).\nTo validate the integrity of their pipelines in high consequence areas under the regulatory chai ige,\npipeline operators must implement an integrity management program for such pipelines incluc ling\nperiodic inspection and testing and integration of information related to pipeline integrity. Th 2\npurpose of this report is to assess the benefits and costs of the proposed regulatory change.\nThis rule is similar to rules promulgated earlier for hazardous liquid pipeline operators. High\nconsequence areas were defined differently for hazardous liquid pipelines, because the\nenvironmental consequences of leaks from hazardous liquid pipelines are different than those\nfrom natural gas pipelines. The elements of an integrity management program proposed to be\nrequired by this rule are similar, however, to the elements previously required of hazardous lic pid\npipeline operators. This report considers the costs and benefits of these proposed requirement s in\na manner similar to the analysis of costs and benefits prepared for the earlier rulemakings.\nTARGET PROBLEM\n1\n\n<<<PAGE 3>>>\n\nNatural and other gas pipeline breaks can result in explosions and fires that can impact on hur ian\nhealth and safety. The magnitude of this impact differs. There are some areas in which the\nimpact of a pipe break will be more significant than it would be in others due to concentrations of\npeople near the pipeline and who thus could be affected. Because of the potential for dire\nconsequences of pipeline failures in certain areas, these areas merit a higher level of protectioi 1.\nThe OPS is promulgating this regulation to afford the necessary additional protection to these\n“high consequence areas”.\nNumerous investigations by the OPS and the National Transportation Safety Board (NTSB) h we\nhighlighted the importance of protecting the public from pipeline failures. The NTSB has ma le\nseveral recommendations to ensure the integrity of pipelines near populated areas. These\nrecommendations included requiring periodic testing and inspection to identify corrosion and\nother damage, establishing criteria to determine appropriate intervals for inspections and tests and\ndetermining hazards to public safety from electric resistance welded pipe.\nCongress also directed the OPS to undertake additional safety measures in areas that are densc.1~\npopulated. These statutory requirements included having the OPS prescribe standards for\nidentifying pipelines in high density population areas and issue standards requiring periodic\ninspections using internal inspection devices on pipelines in densely-populated areas.\nThis rulemaking addresses the target problem described above, and is a comprehensive response\nto the NTSB’s recommendations and Congressional mandates, as well as pipeline safety and\nenvironmental issues raised over the years.\nALTERNATIVES CONSIDERED\nThe OPS considered several alternatives to provide the necessary increased level of protectior to\nhigh consequence areas. These alternatives were:\n1. No action.\n2. Prescriptive requirements for inspection and repair of pipelines in high consequence areas.\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 I isk.\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. They perform inspectic n\nand testing on their pipelines to assess their integrity, and make repairs as they conclude they ire\nneeded. These actions would be expected to continue under the “no action” alternative.\n2\n\n<<<PAGE 4>>>\n\nPipeline leaks and ruptures occur, despite the existence of these operator programs. Major\npipeline accidents have occurred in recent years, of which two were particularly notable, at Ec ison\nTownship, NJ and Carlsbad, NM. In the first case, in-line inspection (pigging) of the pipeline had\ntaken place. The operator either failed to identify, during the pig runs, the areas of damage th, it\neventually caused the rupture or the damage occurred in the years following the inspection. It\naddition, the operator failed to integrate information about the pipeline, including the presencc of\nsignificant construction activity in the area, in a continuing assessment of the line’s integrity, In\nthe latter case, the accident resulted from internal corrosion due to collection of moisture in a ow\nspot which could not be inspected by pigging. The operator failed to consider the possibility ,f\nsuch accumulation of moisture and resulting corrosion and thus did not intercede to prevent tl e\npipeline failure. An integrity management program involving integration of all safety-signifil :ant\ninformation about the pipeline could have prevented both of these accidents. The OPS conch des\nthat validation of operator’s integrity management programs through audit and review by outs ide\nparties, i.e, the regulator, is necessary to help assure that appropriate actions are taken.\nIn addition, continuation of voluntary programs cannot be assured absent some regulatory\nrequirement. In the absence of requirements, pipeline operators might choose to curtail or\neliminate some or all inspection and testing.\nThe OPS concludes that assuring continuation of pipeline integrity management programs,\nassuring that their scope encompasses all areas requiring special protection, and verifying thei r\nadequacy are necessary to assure that the requisite level of protection will be provided. This\nassurance cannot be provided without some regulatory requirement addressing the target prob ’ em.\nIn addition, continued reliance on voluntary industry efforts would not be responsive to the\nCongressional mandate that the OPS promulgate requirements to assure protection of the area ;\nthat are 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 ind\nfor incorporating accident mitigative features.\nPipeline circumstances differ, even within high consequence areas. These differences would\nmake it difficult, at best, to establish prescriptive requirements that would appropriately addre ss\nall possible combinations of pipeline size, type, and configuration or to consider other factors that\ncontribute 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 ai id\ngovernment resources to establish requirements in this fashion. Compliance inspection woulci\nstill require that the requirements applicable to specific pipelines be identified for comparison\nwith ongoing practices.\n3\n\n<<<PAGE 5>>>\n\nPrescriptive requirements also would tend to stifle technological innovation. They do not allc w\nfor different approaches based on advances in the technology. The technology associated wit1 i in-\nline inspection of pipelines (Le., pigging) is advancing at a rapid pace. Establishing prescriptive\nrequirements could slow this advancement, or could preclude use of new techniques that may be\ndeveloped. In the extreme, prescriptive requirements could stop technological innovation in t lis\narea completely.\nMost importantly, however, establishing prescriptive requirements would not assure the\nintegration of information which experience has shown is vital to preventing pipeline acciden s.\nAs noted above, two major accidents have occurred in recent years despite the fact that\ninformation about the causative factors should have, or could have, been known. It appears t k at\ninformation was available that, if correlated to current pig results (in the case of Edison\nTownship) or other information about the pipeline, could have highlighted the need for action\nregarding the problems that ultimately resulted in failure of the pipe. An integrity managemei it\nprogram is required to assure this integration of available information. Outside review of the\nintegrity management program by regulators (Federal and state), is necessary to assure that it 1 s\ncomplete and properly implemented. This outside review cannot be assured without a\nrequirement for such a program.\nFor these reasons, the option of establishing prescriptive requirements was not evaluated furtf er\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.\nPipeline operators are uniquely qualified to develop integrity management programs and prov de\nfor the necessary integration of information. They have the best knowledge of their pipelines md\nthe factors affecting its risk. Integration of information requires that the management systems of\nthe company be aligned and operated to assure that necessary information is shared and that it is\nevaluated in its proper context by knowledgeable personnel. These are actions that are difficu It to\nrequire through prescriptive regulation. Requiring that operators develop such programs is th ;\nbest way to assure that they exist. Such a requirement also provides the regulatory basis for tl e\nOPS and states to audit, review, and assess these programs and their implementation.\nThe best integrity management plans, when implemented properly, can reduce the risk of pipe line\naccidents. They cannot, however, eliminate that risk. Leaks and ruptures could still occur, frc im\nunforeseen outside impacts on the pipeline or from unanticipated interactions among factors\ncontributing to pipeline risk. It is therefore important that features and procedures be availablt: to\nmitigate the effects of accidents that may occur.\nHere again, circumstances differ between pipelines and between regions and local jurisdiction s.\nThe differences make it difficult to establish prescriptive requirements that will provide the bt st\nprotection for each high consequence area. Requiring that operators explicitly consider the nc ed\nfor mitigative features and provisions and that they implement those found necessary is the m 1st\n4\n\n<<<PAGE 6>>>\n\neffective means of providing such protection. Such a requirement also provides the regulator\nbasis for audit and review by OPS and state regulators.\nFor these reasons, this option was selected for hrther development.\n4. Requiring pipeline operators to develop integrity management programs providing for\nexpedited inspection and retesting.\nThe OPS considered the need for requiring integrity management programs that would requirt\ninspection and testing of pipelines to recur over short intervals, a few years. The ability to rec uire\nfrequent testing is limited by the available resources for testing and inspection.\nThe companion rule covering hazardous liquid pipelines requires reassessments at least every five\nyears, with limited exceptions. The current capacity to perform pipeline inspections will be\nchallenged by this required schedule. The OPS concluded that the spur provided by the reguli ltion\nwould be likely to result in an increase in testing capacity over the next five years that will then be\nable to accommodate testing at accelerated rates. The OPS also concluded that protection fro1 n\nenvironmental damage that can be caused by a leak or rupture of a hazardous liquid pipeline\nnecessitated such frequent inspection. Adding requirements for similarly frequent inspection i f\nnatural gas pipelines would complicate the existing testing capacity issue and likely make it\ndifficult for any of the testing requirements to be met.\nExisting regulations already provide some additional protection from accidents on gas\ntransmission pipelines, that could affect high consequence areas. The requirements of 49 CFR\n192.61 1 specify that pipelines in class 3 or 4 areas must operate at pressures that produce\nsignificantly lower hoop stresses in the pipe than is allowed in more rural areas. As a practica 1\nmatter, operators meet this requirement by reducing operating pressure or using heavier-walle 1\npipe in class 3 and 4 areas. Hazardous liquid pipelines do not afford similar protection in higl L\nconsequence areas. The additional protection already provided by natural gas transmission\npipelines justifies assessment on a more extended interval than for hazardous liquid pipelines,\nAdditionally, the natural gas pipeline network supplies gas for use in real time. This is not thc\ncase for hazardous liquid pipelines, which move product in batches and have significant stora ;e\ncapacity. Assessment of natural gas pipelines can therefore result in interruptions of gas supp y.\nThis can have a safety impact, in addition to its economic effect, due to the need to restart gas\nservice in a controlled manner so as to avoid explosions at the point of service. The likelihoo 1 of\nservice interruptions, with attendant costs and safety concerns, increases as the assessment\ninterval is shortened, since operators have less flexibility to conduct assessments at times when\ndemand is lower.\nFinally, significant environmental damage is not expected to result from failure of a natural gas\npipeline, unlike hazardous liquid pipelines, since gas is lighter than air and dissipates in the\natmosphere.\n5\n\n<<<PAGE 7>>>\n\nThe Pipeline Safety Improvement Act of 2002 requires assessments on no greater than 7-year\nintervals. The OPS has established requirements in this proposed rule that would provide for a\nmore focused assessment on this shorter interval. The OPS evaluated the effect on costs to\noperators of requiring full assessments at increased intervals, as described later in this analysi, ;.\nCosts would increase significantly without addition of commensurate benefits.\nFor these reasons, the OPS concluded that assessment of natural gas pipelines need not be\nrequired as frequently as for hazardous liquid pipelines.\nBASELINE REGULATORY ENVIRONMENT\nIn order to assess the costs and benefits of the new regulation, it is necessary first to 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, and the prevalence and\nnature of integrity management plans similar to those required by the rule.\nThe OPS has interacted with gas pipeline operators in recent years as part of development of: n\nintegrity management standard by the American Society of Mechanical Engineers (ASME). 'I 'he\nstandard includes many of the elements of the proposed rule, and has been adopted as a conselisus\nstandard. As a result of these interactions, the OPS understands that many gas pipeline operators\ncurrently have integrity management programs including many aspects that would be required by\nthis proposed regulation.\nThese current integrity management programs include inspection of their pipelines by some\noperators. The amount of such inspection is relatively low, however. Much of the testing beilig\nconducted by these operators is the initial inspection of pipelines. The rate at which subseque nt\ninspections would be performed is now unknown. It is likely that some pipeline would be\nidentified for reinspection routinely (e.g., every ten years). It is equally likely that some pipe1 ne\nwould not be reinspected at all.\nIntegrity management plans are a key element of this rule. To better understand and promote\nmore comprehensive and integrated approaches to safety and environmental protection, the 0 i'S\ncreated the Risk Management Demonstration Program, and the System Integrity Inspection Pi lot\nProgram. These programs encourage and evaluate operator-developed safety and environmen tal\nmanagement processes that incorporate operator- and pipeline-specific information and data tl\nidentify, assess, and address pipeline risks. These programs are helping RSPA's Office of\nPipeline Safety refine its regulatory oversight processes. These processes help to ensure that\npipeline operators have effective processes in place to identify the most important risks to the\npublic and the environment, and to develop and implement cost-effective preventive and\nmitigative actions to manage these risks. Many of these initiatives have validated the importance\nof focusing resources and establishing higher levels of protection in areas where a pipeline fai lure\ncould have significant consequences.\n6\n\n<<<PAGE 8>>>\n\nThrough the Risk Management Demonstration Program and the System Integrity Inspection Pilot\nProgram, the OPS has improved its understanding of pipeline operator integrity management\nsystems and activities. This experience has shown that a number of pipeline operators have\nformalized management systems to identify and address the most significant integrity threats 1 o\ntheir pipeline systems. In the Risk Management Program, participants perform systematic an( I\ncomprehensive risk assessments to identify the specific nature and location of the most significant\nrisks posed by operation of their pipeline system. An essential feature of these risk assessmer ts is\nthe integration of information from many diverse sources to fully understand the integrity t h e ats\nat specific locations on the pipeline. The impact on nearby population is explicitly considerer in\nthese risk assessments. Through formal, risk-based decision making processes, these compan ies\nuse the risk assessment results to identify projects and activities that address potential system\nintegrity threats, thereby preventing leaks and accidents. These investigative risk managemen t\nprograms, and the preventive and mitigative risk control activities that evolve from them,\nsupplement the minimum regulatory requirements established in 49 CFR 192.\nThe System Integrity Inspection Program is focused on developing a more integrity-based\napproach to OPS inspections. Instead of using a “checklist” approach, the OPS is focusing th :\ninspection process on an operator’s integrity management processes and activities. Through\nworking with the operator, the OPS is able to understand and influence the methods and\napproaches used to assess pipeline integrity, and the approaches to integrating integrity assess nent\ndata with other pipeline specific information to identify the most significant integrity threats t I the\nsystem. Specifically, the OPS has observed how operators examine internal inspection data i t\nconjunction with other surveillance and operating data, expected population growth, land use,\nconstruction activity along the pipeline, and other information relevant to assuring the integrity of\nthe pipeline in high population areas and in environmentally sensitive areas. Through this\ninteraction the OPS is acquiring a broader understanding and a greater confidence that effectii’e\nprograms are in place to address the most significant risks. Similar to the Risk Management\nProgram, the SII Program is emphasizing how operators evaluate their system condition and i s\nrisks, and use this information to make sound integrity management decisions.\nThe OPS experience in the Risk Management Demonstration Program and the System Integri y\nInspection Program indicates that integrity management programs such as that required by thi ;\nrule have been developed. They are far from universal, however.\nREVIEW BY TECHNICAL PIPELINE SAFETY STANDARDS COMMITTEE\nThe OPS presented a preliminary draft of this regulatory analysis to the Technical Pipeline Sa fety\nStandards Committee (TPSSC) at a public meeting on July 18, 2002. TPSSC is a Federal\nadvisory committee charged with responsibility for advising on the technical feasibility,\nreasonableness, cost-effectiveness, and practicability of gas pipeline safety standards. The TF SSC\nprovided extensive comments on the preliminary draft regulatory analysis, which have been\nconsidered in developing this draft version.\n7\n\n<<<PAGE 9>>>\n\nOf greatest significance were comments indicating that the natural gas pipeline industry intent Is to\nimplement this proposed rule, if finalized, by a preponderance of in-line inspection. As descr bed\nlater in this analysis, the OPS presumed that some pipelines that can be modified easily to\naccommodate in-line inspection devices would be so modified, but presumed that no pipe tha\nwould require significant modification costs would be pigged. Industry members of the TPSS C\nreported, instead, that much “hard-to-pig” pipe would be modified and that pigging would be Jsed\nas the assessment method of choice. This represents an industry conclusion that pigging is thc ;\nmost cost-effective means of conducting assessments, even if significant up-front capital cost:, are\nrequired to modify existing pipelines. At the same time, the industry members of TPSSC repc n-ted\nthat reliance on hydrostatic testing would be significantly less than the OPS had estimated in 1 he\npreliminary draft analysis. High costs, environmental issues associated with disposing of wat :r\nused for hydrostatic tests, and operational difficulties that could result from watedmoisture le t in\npipelines after assessments all contribute to the relative undesirability of this assessment metl- od.\nThis draft analysis has been revised to reflect these relative industry priorities. With respect tl) the\nintent to modify hard-to-pig piping, this is presented herein as an alternative. For reasons\ndescribed below, the OPS still has some doubt that significant amounts of hard-to-pig pipe wi 11 be\nmodified.\nThe TPSSC also commented that the OPS had underestimated the costs associated with the\nproposed rule. In particular, estimates for programmatic costs (i.e., those associated with\ndeveloping integrity management programs and implementing related information analysis) v, ere\nnoted to be low, industry’s estimate of the cost of hydrostatic testing - particularly in urbanizc d\nareas where natural gas distribution companies operate - was much higher than that used by tl Le\nOPS, and the amount of additional mileage that must be pigged (since pig launchers and receivers\nare not generally located on the boundaries of high consequence areas) was noted to be\nsignificantly underestimated.\nThe OPS has limited data regarding current costs for developing integrity management programs.\nThe cost ranges used in the preliminary draft analysis were based on a survey conducted sevei a1\nyears ago. Interactions with hazardous liquid pipeline operators, who are developing integritj\nmanagement programs in response to similar rules promulgated earlier, indicate that these ran zes\nlikely do underestimate actual costs. The OPS had increased the costs assumed for programrr atic\nactivities, above those used in the analysis of the hazardous liquid rules, but the TPSSC\ncommented that the increases were not enough. The OPS has further increased the cost estim ites\nfor these activities in this draft analysis, as described below.\nThe per-mile cost estimate for hydrostatic testing used in the preliminary draft regulatory analysis,\nand in this analysis, is based on a 1990 study. It is possible that costs for such testing have\nincreased over the last twelve years by more than the rate of inflation. Little hydrostatic testir g\nhas been performed in recent years, particularly in urbanized areas. The OPS has no more rec mt\ndata on what the costs of such testing would be, and has not changed the per-mile cost estimai es\nused in this analysis. As described above, however, industry’s belief that the costs and diffia lties\nassociated with hydrostatic testing will be significant has much reduced the relative important e\n8\n\n<<<PAGE 10>>>\n\nexpected to be placed on this assessment method. The OPS has revised downward its assumr tion\nof how much mileage will be subjected to hydrostatic testing, making any disagreement in thc per-\nmile cost relatively less important.\nThe OPS was persuaded by TPSSC discussion that the amount of mileage that must be piggeci in\norder to assess mileage that can affect high consequence areas was underestimated in the\npreliminary draft analysis. That analysis estimated an additional 25 percent of pipeline mileal ;e\nwould be pigged (i.e., the total pigged would be 1.25 times the high consequence area mileagt ).\nThis is the same additional percentage assumed in the analyses supporting similar rules for\nhazardous liquid pipelines and was used for both pigging and hydrostatic testing. Industry\nrepresentatives on the TPSSC used a similar assumption for additional mileage for hydrostatic\ntesting. They reported, however, that launchers and receivers for in-line inspection devices ar 2\nspaced much farther apart than valves that will be used for hydrostatic testing. They estimate( I\nthat the additional mileage that will be pigged will be up to several hundred percent of the mileage\nthat can affect high consequence areas. The OPS has reflected these comments in this analysi; by\nassuming that 200 percent additional mileage will require pigging in order to assess the milea ;e\nthat can affect high consequence areas and which will be assessed using in-line inspection.\nFinally, it is significant to note that the TPSSC supported proceeding with this proposed rule\ndespite the significant comments made concerning the regulatory analysis. The committee, a~ d\npublic representatives of the pipeline industry that made presentations at the public meeting,\nexpressed the belief that the benefit associated with improved public confidence in pipeline s; fety\njustifies the costs associated with the proposed rule. The TPSSC unanimously adopted a mot on\nfinding that the draft cost-benefit analysis supports the concepts for a proposed standard for\nintegrity management programs for gas transmission pipelines'.\nPIPELINE SAFETY IMPROVEMENT ACT OF 2002\nThe Congress passed the Pipeline Safety Improvement Act of 2002 subsequent to the public\nmeeting with the TPSSC. The Act requires that natural gas pipeline operators implement inte gity\nmanagement plans, and that the Department of Transportation promulgate regulations govem ng\nthese plans. The Act specifies, however, that assessments of pipelines covered by operator\nintegrity management plans must occur at no greater than seven (7) year intervals. This\nperiodicity is greater than considered in the analysis discussed with the TPSSC.\nThe OPS has revised the proposed rule, and this analysis, to be responsive to the assessment\nperiodicity requirements in the Act. For reasons described above, under Alternatives Conside red,\nand as described in the appendix to this analysis, the OPS concluded that requiring assessmen1.s\nusing traditional methods at intervals of seven years or less was not necessary. The OPS has,\ninstead, included in the proposed rule a more-focused application of direct assessment. The\n'TPSSC meeting transcript, July 18,2002, RSPA-1998-4470-68\n9\n\n<<<PAGE 11>>>\n\nproposed rule would require that assessments using pressure testing, in-line inspections, direct\nassessment, or an equivalent technology be used at intervals of five, ten, or fifteen years\n(depending on factors to be described later in this analysis), as considered in the analysis\ndiscussed with the TPSSC. The proposed rule further requires that operators assure that an\nassessment, using one of these methods or the more-focused method described in the rule, are\nused at least every seven years. This analysis has been revised, from the version discussed wit n\nthe TPSSC, to reflect this additional method and requirements.\nSCOPE AND PARAMETERS OF ANALYSIS\nThis analysis of benefits and costs takes the following approach. First, the mileage impacted by\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 discussio 1 of\nthe costs versus the benefits is presented. It should be noted that, unless otherwise specified, i 11\ndollar values in this report are given in constant 2001 dollars.* Furthermore, this analysis will\narbitrarily consider only the first twenty years after the effective date of the final rule. Includir Lg\nadditional years would not be expected to materially affect the conclusions of this analysis.\nANALYSIS\nImpacted Mileage\nIn this section the total pipeline mileage impacted by the regulatory change is estimated. That\nmileage is located in or nearby high consequence areas, defined by the change as areas in which\ndefined numbers of people are expected to be within specified distances of the pipeline. The\ndistances vary depending on the diameter of the pipe and the pressure at which it operates.\nTotal Pipeline Mileage\nIn total, there is an estimated 292 thousand miles of regulated natural gas transmission pipelinzs in\nthe U.S.3 This rule would not apply to all of this mileage. The proposed rule does not apply tl)\npipelines operated at a hoop stress of less than 20 percent of specified minimum yield strengtk\n(SMYS). The OPS has no data on how much transmission pipeline mileage is operated at the ;e\nlow stresses, but presumes that it is small. The rule also applies to transmission pipelines for\nhydrogen, synthetic gas and other products subject to 49 CFR Part 192 that are not included ir the\nnatural gas transmission pipeline totals. Here, again, the OPS does not have data on the total\ntransmission mileage for these other gases. This analysis uses the available natural gas\n'Dollars are converted from nominal values to real 2001 values using the Producer Price Index (PPI), Intermedi, ite\nMaterials, Supplies, and Components. The source of the PPI index numbers is the U.S. Bureau of Statistics We11\npage.\n'Jurisdictional natural gas transmission pipeline mileage (onshore) for 2000. This mileage was obtained from annua I\nreports filed by pipeline operators with the Office of Pipeline Safewata available on the OPS web page.\n10\n\n<<<PAGE 12>>>\n\ntransmission pipeline total mileage, which is considered to be very close to the total pipeline\nmileage potentially affected by the proposed regulation.\nImpacted Mileage in High Consequence Areas\nThe proposed regulatory change does not apply to all of this pipeline. Instead, it applies to thi I t\ntransmission pipeline that can affect high consequence areas, as described earlier. A principa\nelement of this definition is pipeline that is in class 3 and 4 areas as defined in 49 CFR 192.5.\nPipeline operators are presently required to maintain data on the population near their pipelint in\norder to determine pipeline that is in class 3 or class 4 areas. Historically, this data has not be :n\nrequired to be submitted to the OPS. Reporting of mileage by class was required for the first ime\nas part of the 2001 annual reports from gas transmission pipeline operators. At the time this\nanalysis was prepared, a total of 2 8 3 18 miles had been reported in those reports as class 3 or 4.\nAnalysis of the 2001 reports was not complete, however. Only approximately 256,000 on-shc Ire\nmiles of natural gas transmission pipeline had been reported. For purposes of this analysis, th 2\nOPS presumes that the total amount of on-shore natural gas transmission mileage did not deci ease\nsignificantly between 2000 and 2001 and that the percentage of class 3 and 4 mileage in the a! -yet\nunreported 36,000 miles is the same as that in the 256,000 miles reported. This results in a\nconclusion that an additional 4,010 miles of pipeline exists in class 3 and 4 areas, for a total o\n32,528 miles.\nThere are several factors in the definition of high consequence areas which could lead to\nadditional mileage being included. These include:\ne\ne\n. the requirement to consider the location of buildings that could house populations of\nlimited mobility,\nthe requirement to consider areas near pipelines where people congregate, and\nthe requirement to expand the radius of consideration to 1000 feet (or possibly more) for\npipelines larger than 30 inches in diameter and operating at pressures greater than 101 10\npsig or where calculations of potential impact radius indicate a likelihood that areas\nbeyond 660 feet from the pipeline would be affected by an accident.\nThe OPS cannot know with certainty how much additional mileage that can affect high\nconsequence areas will be added by these criteria. The definition of piping that can affect hig I\nconsequence areas for natural gas transmission pipelines is only now being finalized. Provisic ms\nof this proposed rule add additional factors that further refine the definition. Pipeline operato 's\nare not required presently to collect data related to these additional factors, and the OPS has n\nindependent source of such information. For purposes of this analysis, the OPS assumes that\nthese additional factors would increase the total transmission pipeline mileage affected by the rule\nby 30 percent, or 9,758 miles. The OPS seeks comments on the reasonableness of this\nassumption.\n11\n\n<<<PAGE 13>>>\n\nThe OPS would like operators to apply the definition of high consequence areas and submit\ncomments indicating how much additional mileage (Le., beyond that in classes 3 and 4) is\nidentified. The OPS also would like to receive information regarding how this mileage is\ndistributed. The OPS expects that mileage in urbanized areas, whether classes 3 or 4 or inclul led\nas a result of one of the other criterion, will be reasonably concentrated, with a significant por ;ion\nof any piggable segment (Le., launcher to receiver) so identified. At the same time, the OPS\nexpects that piping in rural areas that meets the definition as piping that can affect high\nconsequence areas (e.g., due to the proximity of areas where people congregate) will be much\nmore distributed. In rural locations, such areas may constitute only a few miles of a piggable\nsegment. The distribution of these areas may affect decisions regarding the method of assess1 lent\noperators will use, as discussed below.\nThe total gas transmission pipeline mileage in high consequence areas is thus 42,286 miles, tl e\nsum of the amount estimated to be in class 3 and 4 areas and the amount assumed to be added as a\nresult of other factors in the definition of high consequence areas.\nThe state of Texas has already promulgated a regulation requiring assessment of intrastate nat xal\ngas transmission pipelines within the state. The provisions of the Texas rule require assessmc nt at\nintervals that are more frequent than those in this proposed rule. As a result, this proposed ru e\nwill not impose additional assessment requirements on Texas intrastate natural gas transmissi In\nlines, and the total mileage of such pipeline must be subtracted from the national total to\ndetermine the mileage affected by this proposed rule. The Texas Railroad Commission repon s\nthat there are 37,5 10 miles of intrastate natural gas transmission pipeline within Texas4 The 'IPS\nassumes that the percentage of this mileage in high consequence areas is the same as the\npercentage of total U.S. transmission pipeline mileage that is affected. The Texas mileage th; t\nmust be subtracted therefore amounts to 5,432 miles.\nThe total gas transmission pipeline mileage in high consequence areas that is considered in th s\nanalysis to be affected by this proposed rule is thus 36,854 miles.\nBENEFITS\nThe benefits resulting from the proposed regulatory change are discussed in this section. Tho ;e\nbenefits are expected to result from detection of problems that could cause pipeline failures bc :fore\nthe failure occurs, thereby averting accidents. The inspection and assessment that would be\nrequired by the proposed rule is designed to detect problems related to internal corrosion, extc mal\ncorrosion, stress corrosion cracking and external damage to the pipeline, all of which can resu It in\npipeline ruptures. Natural gas pipeline accidents usually involve explosions and fire and can\nresult in death, serious injury, and property damage. Preventing accidents will result in reduced\nnumbers of deaths and serious injuries and in reduced property damage. These reductions, thc :n,\nare principal benefits of the proposed rule. The proposed rule will also provide improved\n4Data from Texas Railroad Commission web site, http:/lwww.rrc.state.tx.us/divisions/gslsmiles-html.\n12\n\n<<<PAGE 14>>>\n\nassurance of pipeline safety, will provide a basis for increased public acceptance of the risks f -om\nnatural gas transmission pipelines, and will provide other, less tangible, benefits. Each of the, ;e\ncategories of benefits is discussed below.\nPipeline operators also have strong incentives to ensure the integrity of their pipelines. In add ition\nto the positive safety and societal benefits, the lost product and unscheduled downtime for rep airs\nfollowing a major incident can significantly impact the company’s financial performance and its\nability to satisfy customer commitments. Operators cannot afford to have these critical\ntransportation assets out of service for lengthy periods of time in today’s competitive busines:\nenvironment. In addition, the damage to the company’s public image and reputation, as well I is\nthe legal implications of serious incidents, can pose an even broader and longer term negative\nimpact on the company’s business operations. For these and other reasons, many pipeline\noperators have implemented and are continuing to improve more systematic safety and\nenvironmental management processes, many of which already embody the principles in this\nproposed rule.\nBenefits from reduced death and serious inju$\nAccident reports submitted to the OPS during the period 1986 to 2001 (this period was chose] I\nbecause this data is publicly available on the OPS website) identify that there were 1,285","truncated":true,"body_characters":176265}