{"operation":"document","citation":"0900006480e8a8cc","title":"U.S. DOT/RSPA - Environmental Assessment Report - Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines)","source_type":"rulemaking","agency":"Pipeline and Hazardous Materials Safety Administration","status":"current","official":true,"published_on":null,"effective_on":null,"summary":"Scope and purpose: The document describes a proposed addition to 49 CFR 192 requiring operators to develop and implement integrity management programs for gas transmission pipeline segments located in ‘‘high consequence areas,’’ including baseline and periodic integrity assessments and consideration of preventive and mitigative measures. It explains the rulemaking history, the proposed elements of operator programs, the allowed assessment methods (internal in-line inspection, pressure testing, direct assessment), and alternatives considered (no action; use hazardous-liquid rule provisions). The assessment states the rule is intended to reduce the frequency of pipeline failures affecting high consequence areas, describes minor localized environmental impacts associated with assessment and repair activities, and concludes the national environmental impact is not expected to be significant.","machine_formats":{"json":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e8a8cc.json","markdown":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e8a8cc.md"},"app_url":"https://regulus.evalyn.ai/document/regulations-gov-attachment-0900006480e8a8cc","source_url":"https://downloads.regulations.gov/PHMSA-RSPA-2000-7666-0172/attachment_1.pdf","body":"<<<PAGE 1>>>\n\nDRAFT 6/24/02\nResearch and Special Programs Administration\nU.S. Department of Transportation .I%\n: =-\n> J\nc-7\n-7\n7 \" I\n8\n_ . 1\nL, 1 _1\n1 ,\n7;- -\nf'- t> ;\n-\n-\n;-i\n.. - . I\nr->\n._. -.\nc- r\n_ _\n- * --\nEnvironmental Assessment\nProposed Rulemaking\nPipeline Integrity Management in High Consequence Areas\n(Gas Transmission Pipelines)\nDocket: RSPA-00-7666\nRIN 2137-AD45\n\n<<<PAGE 2>>>\n\nDRAFT 6/24/02\nTable of Contents\nPreliminary Finding of No Significant Impact\n...\n111\nA.\nB.\nC.\nPurpose and Need for Action\nDescription of Proposed Action\nAlternatives Considered\n1\nD.\nAffected Environment\nE.\nEnvironmental Consequences of Proposed Action and Alternatives\nE. 1\nEnvironmental Impact of the Proposed Integrity Management Rule\nE.2\nEnvironmental Effects of the Aitzmatives\nF.\nEnvironmental Justice Considerations\nG.\nInformation Made Available to States, Local Governments, and Individuals\nH.\nI.\nList of Agencies and Persons Consulted\nConclusion\n..\n11\n\n<<<PAGE 3>>>\n\nDRAFT\n6/24/02\nPreliminary Finding of No Significant Impact -\nThis Environmental Assessment is prepared in accordance with section 102(2)(c) of the National\nEnvironmental Policy Act (42 U.S.C. Section 4332), the Council on Environmental Quality\nregulations (40 CFR Sections 1500-1 508), and Department of Transportation Order 5610.lc,\nProcedures for Considering Environmental Impacts. It was prepared to assist in the agency’s\nplanning and decision-making. This document concisely describes the Research and Special\nPrograms Administration’s (RSPA) proposed rulemaking to establish integrity management\nprogram requirements for operators of natural gas transmission pipelines. This Environmental\nAssessment also addresses the need for the proposed action, the alternative definitions\nconsidered, the environment affected by this action, the consequences to the environment of the\nproposed action and the alternatives, and a list of the agencies and organizations consulted. This\nEnvironmental Assessment provides sufficient evidence to determine that the provisions of the\nproposed rule are expected to have no significant impact on the environment.\n...\n111\n\n<<<PAGE 4>>>\n\nDRAFT 6/24/02\nA. Purpose and Need-for - Action\nThe Research and Special Programs Administration (RSPA) is proposing new rules for integrity\nmanagement for gas transmission pipelines. RSPA believes that requiring pipeline operators to\nimplement more systematic and integrated approaches to assure pipeline integrity in areas where\nincidents have the greatest potential consequences to people and property will enhance control of\npipeline risks and improve industry performance.\nRSPA’s experience in the Risk Management Demonstration Program and System Integrity\nInspection (SII) Pilot Program have validated the importance of focusing resources and\nestablishing higher levels of protection in areas where pipeline failure could have significant\nconsequences. These programs showed that some companies are developing more sophisticated\nand mature integrity management systems and diagnostic tools, resulting in safety,\nenvironmental, and economic benefits. RSPA’s Office of Pipeline Safety (OPS) believes the next\nstep is to require all operators to follow at least minimal requirements for integrity management\nprograms that focus on areas of potential significant consequence from pipeline incidents.\nCongress has directed OPS to consiaer initiatives to improve safety and environmental protection\nin areas where pipeline failures might have significant consequences. In addition, the National\nTransportation Safety Board (NTSB) has made several recommendations addressing improved\nprotection for high population and environmentally sensitive areas. RSPA believes that issues\nraised by these legislative mandates and NTSB recommendations can be best addressed by new\nrequirements for systematic integrity management programs that consider the total spectrum of\nrisks from pipeline operation, including those risks in locations where potential consequences to\npublic health and safety and the environment are high.\nIn 1999, OPS began the development of new regulations for natural gas and hazardous liquid\ntransmission lines in high population areas, commercially navigable waterways, and areas of the\nenvironment that are unusually sensitive to damage. Areas fitting one or more of these criteria\nare referred to as “high consequence areas.” In the ensuing period, OPS has solicited the opinions\nof industry, other agencies, and stakeholders through public meetings, requests for public\ncomment, an electronic discussion forum, and other smaller meetings and conference calls. After\nconsidering the resulting feedback and experience from the Risk Management and SI1 programs,\nRSPA decided to introduce pipeline integrity management requirements in a series of steps. The\nfirst rulemaking covered integrity management for hazardous liquid pipeline operators with 500\nor more miles of pipeline. The final rule for these pipeline operators was published on December\n1,2000 (65 FR 75378). A similar rule for hazardous liquid operators with less than 500 miles of\npipeline was proposed on March 21,2001 and made final on January 16,2002 (67 FR 2136).\nRSPA began gathering information for the development of new regulations for integrity\n1\n\n<<<PAGE 5>>>\n\nDRAFT 6/24/02\nmanagement for gas pipeline operators through meetings with representatives of the gas pipeline\nindustry, research institutions, state pipeline safety agencies, and public interest groups. In\nFebruary, 2001, OPS held a public meeting to exchange information on the potential regulations.\nSummaries of all meetings and the information exchanged may be found in DOT docket number\nRSPA-2000-7666 and on the OPS web site under InitiativesPipeline Integrity Management\nProgrdGas Transmission Operators Rule. OPS published a Notice in the Federal Register in\nJune, 2001 (66 FR 34318) requesting further information and clarification and inviting further\npublic comment on integrity management concepts for gas pipelines. The Notice also announced\nthe establishment of an electronic public discussion forum for gas pipeline integrity management\nissues on OPS’s Internet home page. In this notice, OPS invited comment on seven elements it\nconsidered important to include in the integrity management rule and hypotheses related to these\nelements. The comments received are included in the docket along with the transcript of the\nelectronic discussion forum.\nThe first of the seven elements was the definition of high consequence areas. OPS decided to\npropose an initial rule defining high consequence areas for gas pipeline integrity management\nbefore proposing other requirements for gas integrity management programs. OPS considered the\nreceived comments before developing the proposed high consequence area definition, which is\ndescribed in a Notice of Proposed Rulemaking in the Federal Register of January 9,2002 (67 FR\n1108). An Environmental Assessment was prepared for this proposed rulemaking (Docket\nRSPA-2000-7666). Because of the different risks associated with gas transmission pipelines\ncompared to hazardous liquid pipelines, the proposed definition for gas pipelines is different than\nthe definition in the hazardous liquid integrity management rule (see 65 FR 75378).\nOPS is now proposing rules for integrity management of gas transmission pipelines in high\nconsequence areas.\nB. Description of Proposed Action\nRSPA proposes to add a new section to 49 CFR 192, which is expected to enhance the integrity\nof gas transmission pipelines in high consequence areas. The proposed rule requires each\noperator to develop and implement an integrity management program that provides for continual\nassessment of the integrity of all pipeline segments located in high consequence areas. The\nproposed rule further requires that the program provide for evaluating the entire range of threats\nto each pipeline segment’s integrity through comprehensive information analysis and ensuring\nadditional protection to a pipeline segment’s integrity though remedial actions and preventive\nand mitigative measures.\nThe proposed rule applies to all gas transmission pipelines, as defined in Section 192.3. This\nwould include transmission pipelines transporting petroleum gas, hydrogen, and other gas\n2\n\n<<<PAGE 6>>>\n\nDRAFT 6/24/02\nmanagement for gas pipeline operators through meetings with representatives of the gas pipeline\nindustry, research institutions, state pipeline safety agencies, and public interest groups. In\nFebruary, 2001, OPS held a public meeting to exchange information on the potential regulations.\nSummaries of all meetings and the information exchanged may be found in DOT docket number\nRSPA-2000-7666 and on the OPS web site under InitiativesPipeline Integrity Management\nProgrdGas Transmission Operators Rule. OPS published a Notice in the Federal Register in\nJune, 2001 (66 FR 343 18) requesting further information and clarification and inviting further\npublic comment on integrity management concepts for gas pipelines. The Notice also announced\nthe establishment of an electronic public discussion forum for gas pipeline integrity management\nissues on OPS’s Internet home page. In this notice, OPS invited comment on seven elements it\nconsidered important to include in the integrity management rule and hypotheses related to these\nelements. The comments received are included in the docket along with the transcript of the\nelectronic discussion forum.\nThe first of the seven elements was the definition of high consequence areas. OPS decided to\npropose an initial rule defining high consequence areas for gas pipeline integrity management\nbefore proposing other requirements for gas integrity management programs. OPS considered the\nreceived comments before developing the proposed high consequence area definition, which is\ndescribed in a Notice of Proposed Rulemaking in the Federal Register of January 9,2002 (67 FR\n1108). An Environmental Assessment was prepared for this proposed rulemaking (Docket\nRSPA-2000-7666). Because of the different risks associated with gas transmission pipelines\ncompared to hazardous liquid pipelines, the proposed definition for gas pipelines is different than\nthe definition in the hazardous liquid integrity management rule (see 65 FR 75378).\nOPS is now proposing rules for integrity management of gas transmission pipelines in high\nconsequence areas.\nB. Description of Proposed Action\nRSPA proposes to add a new section to 49 CFR 192, which is expected to enhance the integrity\nof gas transmission pipelines in high consequence areas. The proposed rule requires each\noperator to develop and implement an integrity management program that provides for continual\nassessment of the integrity of all pipeline segments located in high consequence areas. The\nproposed rule further requires that the program provide for evaluating the entire range of threats\nto each pipeline segment’s integrity through comprehensive information analysis and ensuring\nadditional protection to a pipeline segment’s integrity though remedial actions and preventive\nand mitigative measures.\nThe proposed rule applies to all gas transmission pipelines, as defined in Section 192.3. This\nwould include transmission pipelines transporting petroleum gas, hydrogen, and other gas\n2\n\n<<<PAGE 7>>>\n\nDRAFT 6/24/02\nproducts covered under Part 192. The proposal does not apply gas distribution lines. It applies\nto. all facilities through which gas moves, including pipe, valves, compressor units, metering\nstations, regulator stations, delivery stations, holders, and fabricated assemblies. It does not\napply to pipelines operating at a hoop stress of less than 20% specified minimum yield strength\n( S M Y S ) and gathering lines.\nThe proposed rule requires that, no later than one year after the effective date of the final rule,\neach operator has a written integrity management program, consisting of:\n1.\nAn identification of all pipeline segments covered by the proposed rule.\n2.\nA plan for baseline integrity assessment of each pipeline segment. This plan must\ninclude the assessment method, the schedule for completion of assessments, and\nexplanation of the choice of assessment methods and the risk factors considered in\nestablishing the assessment schedule. The assessment method used could be internal\ninspection tool or tools, pressure test, Direct Assessment, or other technology that the\noperator demonstrates can prcvide an equivalent understanding of the condition of the\nline pipe. Different time limits for the completion of integrity assessments of segments\napply according to the location of the segments and if direct assessment is chosen as the\nassessment method.\n3.\nFor an operator planning to use Direct Assessment, a plan describing how it will use the\nmethod, including identification of External Corrosion Direct Assessment Regions;\n4.\nA program framework that addresses each of the required program elements, including\ncontinual integrity assessment and evaluation. The framework is required to document\nhow decisions will be made to implement each element. The frame work will evolve into\nan integrity management program as the operator makes decisions and gains experience.\nAn integrity management program is dynamic program that an operator would\ncontinually change as the operator gains more information about the pipeline and results\nof the assessments.\nC.\nAlternatives Considered\nRSPA considered alternatives to the proposed integrity management requirements given in\nSection B above. These alternatives are summarized below:\n1. Take No Action. In this alternative, RSPA would not propose new integrity management\nrequirements for high consequence areas but would rely on the existing regulatory requirements\nto provide protection for all areas. This alternative would not be responsive to Congressional\n3\n\n<<<PAGE 8>>>\n\nDRAFT 6/24/02\nmandates or NTSB recommendations. This alternative would not provide the protection provided\nby the proposed rule of required integrity assessment and repair of detected defects or the\nconsideration of other preventive and mitigative measures to protect high consequence areas\n2. Use the Same Provisions as in the Hazardous Liquids Integrity Management Rule (192.452).\nThe main differences between the proposed rule and the requirements of 192.452 are:\n(1) the time limits for completing the baseline integrity assessment and reassessment\nof pipeline segments that could affect high consequence areas and\n(2) the option of using direct assessment as an assessment method (not allowed in\n192.452).\nThe time limit for baseline assessment under the liquid rule is seven years, while the limit for\nbaseline assessments under the proposed rule is ten years. OPS believes that requiring the shorter\nperiod for completing baseline assessments would cause negative impacts on gas supply and cost\nfor consumers. In addition, further compressing the period required for completing baseline\nintegrity assessments is expected to place a strain on companies providing assessment services.\nThis strain could cause the quality of assessments to suffer.\nThe liquid pipeline rule requires reassessment every five years, while the proposed rule requires a\nmaximum interval for reassessment of ten years (for pipelines operating above 50% SMYS) or\nfifteen years (for pipelines operating below 50% S M Y S ) . If direct assessment is used, the\nproposed rule requires a reassessment interval of no more than five years (unless the operator\nverifies all anomalies by excavation, in which case a ten year interval is allowed).\nIn developing the proposed rule, OPS has considered the important differences between gas\ntransmission and hazardous liquids pipelines. Key differences include the existing regulations\nthat require gas operators to obtain and maintain population data on the areas surrounding their\npipelines and to replace their pipe with higher strength pipe when certain population thresholds\nare reached. Hazardous liquid operators have no such requirement. For this reason, gas\ntransmission pipelines in high population areas generally operate at lower stresses than liquid\npipelines in populated areas (typically 40-50% SMYS for gas pipelines vs. 72% SMYS for liquid\npipelines).\nStudies indicate that internal inspection is not possible for a substantial percentage of gas\ntransmission lines. Industry estimates indicate up to 50% of gas transmission pipelines can be\nmodified to allow internal inspection only at a cost of between $88 billion to $710 billion.\nPressure testing all these lines could impose negative effects on the supply of gas to consumers.\nDirect assessment is the only assessment method that could be employed in these lines to avoid\n4\n\n<<<PAGE 9>>>\n\nDRAFT 6/24/02\nthese negative impacts. Furthermore, under the proposed rule, if direct assessment is used for\npipeline segments, those segments are subjected to shorter intervals for reassessment.\nBecause of the significant differences between gas transmission and hazardous liquid pipelines,\nOPS has proposed different provisions for the gas integrity management rule.\nD. Affected Environment\nThe purpose of the rule is to provide additional protection to hgh consequence areas in the\nvicinity of gas transmission pipelines throughout the United States. The baseline integrity\nassessment and periodic re-assessments, as well as the additional preventive and mitigative\nactivities that evolve from the operator’s integrity management program, apply to segments on\nthe operator’s pipeline that are in high consequence areas. Thus the primary areas of the\nenvironment impacted by this rule are high consequence areas, as defined in the rule for defining\nhigh consequence areas for gas transmission pipelines’:\n8 Class 3 areas. Class 3 areas are defined in the pipeline safety regulations as a class\nlocation unit with 46 or more buildings intended for human occupancy. A class location\nunit is an area that extends 220 yards on either side of the centerline of any continuous\none-mile length of pipeline. A class 3 area is also an area where the pipeline lies within\n100 yards of either a building or a small, well-defined outside area, such as a playground,\nrecreation area, outdoor theater, or other place of public assembly, which is occupied by\n20 or more persons on at least 5 days a week for 10 weeks in any 12-month period.\nNeither the days nor the weeks need be consecutive.\n8 Class 4 areas. A Class 4 area is any class location unit where buildings with four or more\nstories are prevalent.\n8 Areas where a pipeline lies within 660 feet (or within 300 feet where pipeline is less than\nor equal to 12 inches diameter and operates at a MAOP of less than or equal to 1200 psig,\nor within 1000 feet2 where the pipeline is greater than 30 inches in diameter and operates\nat a MAOP greater than 1000 psig) of a well-known @e. licensed, or visibly marked, or\n2\n1 “Pipeline Safety: High Consequence Areas for Gas Transmission Pipelines,” Final\nRule, 67 FR XXXX, XXX X, 2002.\nIn a few cases the threshold may exceed 1000 feet, depending upon pipe diameter\nand MAOP.\n5\n\n<<<PAGE 10>>>\n\nDRAFT 6/24/02\nknown to local public officials) building or facility such as hospital, school, day-care\nfacility, retirement facility, stadium, prison, or other facility having personswho are\nconfined, are of impaired mobility or would be difficult to evacuate.\n0 Areas where a pipeline lies within 660 feet (or within 300 feet where pipeline is less than\nor equal to 12 inches diameter and operates at a MAOP of less than or equal to 1200 psig,\nor withln 1000 feet2 where the pipeline is greater than 30 inches in diameter and operates\nat a MAOP greater than 1000 psig) of either a building or a small, well-known (i.e.\nlicensed, or visibly marked, or known to local public officials) outside area where 20 or\nmore persons congregate at least 50 days in any 12-month period. (The days need not be\nconsecutive.) Examples of such areas include, but are not limited to, beaches,\nrecreational facilities, camping grounds, and religious facilities.\nAfter they are initially established, high consequence areas will be updated on a periodic basis to\nincorporate new information and data. For example, as communities and populations grow, the\nextent of Class 3 locations (as defined in §192.5@)(3)(1) and §192.5(b)(3)(ii)) may expand. If so,\nthe operator will need to apply any integrity management requirements to the expanded area.\nIn addition to the defined areas, the provisions of a proposed integrity management rule are likely\nto affect areas of the environment beyond the high consequence area. For example, some\noperators will choose to use internal inspection to fulfill the requirement. Due to economic and\noperational considerations, the launchers and receivers used to insert and remove internal\ninspection tools are typically Iocated at compressor stations or other isolation points, which can\nbe many miles apart, Even though a high consequence area may exist for only a short distance\nalong the line, because of the location of inspection tool launchers and receivers, operators will\nlikely inspect the entire extended section of the line. Thus, in addition to the information about\nthe condition of the line segment that could affect a high consequence area, the operator will\nobtain integrity data about a much larger section of pipe.\nSimilarly, the consideration and potential implementation of additional preventive and mitigative\nmeasures has can affect additional areas beyond the boundaries of high consequence areas. For\nexample, if Remove Control Valves (RCVs) are installed to mitigate the release of gas following\na line rupture or leak, then this benefit extends along the full length of the section of the pipe\nbetween valves. This may include both pipe segments that are could affect nearby high\nconsequence areas and segments that are not in proximity to high consequence areas.\nE. Environmental Consequences of Proposed Action and Alternatives\nThis section describes the expected impact to the environment of the proposed action (Section\n6\n\n<<<PAGE 11>>>\n\nDRAFT 6/24/02\nE. 1) and the alternatives (Section E.2).\nE. 1 Environmental Impact of the Proposed Integritv Management Rule\nSection B describes the requirements for the proposed rule. This section discusses the impacts of\nthese requirements.\nE. 1.1 Overview of Integrity Assessment Methods\nThe integrity assessment methods explicitly allowed by the proposed rule include internal in-line\ninspection, pressure testing, and direct assessment. The proposed rule does allow for an operator\nto employ unspecified possible alternative integrity assessment methods, if the operator can\ndemonstrate the alternative method provides an equivalent level of effectiveness as the methods\nspecified in the proposed rule. However, OPS expects that gas pipeline operators will rely on the\nspecified methods to perfom integrity assessments for almost all segments.\nInternal in-line inspection, also referred to as “smart pigging,” involves the use of an\nelectronically instrumented device traveling inside the pipe that measures characteristics of the\npipe wall. There are several different technologies used by internal inspection devices. The most\ncommon tools in use are:\nGeometry pigs, which contain electronic sensors that detect geometric or configuration\nchanges in the pipe such as dents, buckles, wrinkles, and ovalities. They are used to\nidentify construction-related or other outside force damage.\nMagnetic flux leakage pigs, which produce a magnetic flux field in the pipe wall that can\nindicate changes in wall thickness. Flux variations are used to indicate localized pipe\nwall thinning due to internal or external corrosion, or certain types of gouges.\nUltrasonic tools, which use sound waves to identify anomalies. There are several designs\nof ultrasonic tools capable of detecting wall thinning and crack or crack-like defects.\nCurrently, there is no single internal inspection tool that can detect all types of pipeline defects or\ndamage. Hence, the selection of a specific tool depends on what type of pipeline damage the\noperator is trying to identify. Some operators run geometry or caliper pigs, in combination with\nmagnetic flux leakage tools, to identify both geometric defects, as well as corrosion metal loss.\nThe internal inspection tool output is analyzed to identify the location and severity of pipe wall\nanomalies or defects. Several industry-accepted methods are used to determine the severity of\nflaws and the remaining strength of the pipe. In addition, pig vendors, consultants, and operators\n7\n\n<<<PAGE 12>>>\n\nDRAFT 6/24/02\nare developing more sophisticated analytical tools to take advantage of the increasing quality and\naccuracy of the data available from higher resolution inspection tools. These calculations\nconsider the depth, geometry, and configuration of corroded areas, as well as the proximity to\nother anomalies to estimate the remaining strength of the pipe at the location of the anomaly.\nThe calculations are used to identify which anomalies are in need of repair (Le., those areas\nwhere the remaining pipe strength is approaching a level where integrity during future operation\nmight be compromised), and to prioritize the excavation and examination of pipe wall defects.\nAfter interpreting and analyzing the results from a pig run, operators typically develop an\nexcavation and repair plan. This plan involves excavating selected anomaly locations to examine\nthe extent of damage and thus confirm the information identified by the pig. After validating the\naccuracy of the pig runs through these confirmation digs3, the operator will excavate, examine,\nand repair, if necessary, those anomalies that have the most potential to threaten pipeline\nintegrity. Operators develop their own criteria for scheduling anomaly repair work. Typically\nthose indications that might pose a near term or immediate threat to pipeline integrity are\nrepaired as soon as possible. Other, less severe defects typically become part of a longer term\nmaintenance plan.\nHydrostatic Dressure testing is ths second method of integrity assessment allowed by the\nproposed rule. During a hydrostatic test, a segment of the pipeline is filled with water,\npressurized to a predetermined pressure, and held at this test pressure for a predetermined length\nof time. This testing is performed to eliminate any significant material defects or flaws that\nmight result in failure. The test pressure normally exceeds the pipeline’s maximum allowable\noperating pressure. Thus the pipe is subjected to stresses much higher than it would encounter\nduring system operation. After the testing is completed, the only defects remaining in the pipe\nare those that should not fail at the lower, normal operating pressures. Hydrostatic testing is\nespecially valuable in ensuring that significant longitudinal seam weld flaws and stress corrosion\ncracks are not present. These two failure causes can be difficult to detect with many internal\ninspection devices.\nDirect assessment, the third integrity assessment method allowed in the proposed rule, is a\nmethod of integrating knowledge of the physical characteristics, environment, and operating\nhistory of a pipeline with the results of indirect inspection, direct examination, and analysis to\nevaluate threats to the line’s integrity. Different direct assessment approaches are taken to assess\na pipeline’s condition with respect to different causes of pipeline failure, including external\ncorrosion, internal corrosion, and stress corrosion cracking. The proposed rule allows direct\nSome operators that use modem, high resolution magnetic flux tools do not perform\nconfirmation digs.\n8\n\n<<<PAGE 13>>>\n\nDRAFT 6/24/02\nassessment to be used ifthe pipeline meets certain criteria that ensure that direct assessment\nmethods will be effective in assessing the pipe’s integrity.\nFor direct assessment of external corrosion (ECDA), the proposed rule requires the operator to\nselect at least two indirect examination methods for each section of a pipeline where direct\nassessment is to be applied. Possible choices for indirect examination tools are Close Interval\nSurveys (CIS), Direct or Alternate Current Voltage Gradient (DCVG or ACVG), or\nelectromagnetic techniques such as Pipeline Current Mapper (PCM) and C-Scan. The indirect\nexamination methods are applied and the results are analyzed and compared to one another and\nto operating history. Indications that might represent defects are classified according to severity.\nThe next step in direct assessment is excavation of indications according to the severity of the\nindicated conditions from the indirect examinations.\nDirect assessment for internal corrosion involves flow modeling to identify the most likely\nlocations of water accumulation, direct examination by evacuation and inspection by ultrasonic,\nx-ray, or other technology, and chemical analysis of fluids drawn off the pipeline to determine if\ncorrosion products are present.\nE. 1.2 Environmental Impacts of Integrity Assessment Methods\nThe purpose of the integrity assessment methods described in Section E. 1.1 above is to identify\ndefects or anomalies in the pipe wall that might result in failure if operation were to continue\nwith these defects still in place. Defects such as corrosion damage, deformation incurred during\nconstruction, and outside force damage to the pipe can be identified by these inspection\ntechniques and repaired. Eliminating or repairing these defects provides greater assurance of\npipeline integrity and reduces the probability that the pipe will fail during subsequent operation.\nGas transmission pipelines transport pressurized natural gas, which is lighter than air and\nflammable. If released as a result of a pipeline failure, natural gas can potentially ignite, causing\nfires or explosions. Industry experience demonstrates that environmental consequences of\npipeline rupture-initiated fires are almost always limited to damage to the vegetation and animal\nlife in the area adjacent to the failure site. It is possible that a rupture occurring in a heavily\nforested area in the dry season could result in a forest fire, which could have a more extensive\nimpact on wildlife and vegetation. However, the likelihood of such an occurrence is believed to\nbe very low. Other than localized damage to vegetation and animal life in the event of a fire or\nexplosion, there are no significant environmental impacts from natural gas pipeline leaks or\nruptures.\nWhile integrity assessment and repair of defects that are detected cannot eliminate all pipeline\nfailures, they can reduce the frequency of these events. Thus on a national scale, the cumulative\n9\n\n<<<PAGE 14>>>\n\nDRAFT 6/24/02\nenvironmental damage fiom gas pipeline accidents is reduced. Since the provisions of the rule\nwill be implemented on line segments that can affect populated areas, it is expected that these\nareas will benefit by the reduced likelihood of pipeline failure in these areas.\nEven though these integrity assessment and repair practices can reduce the frequency of spills to\nthe environment, they are not without some adverse impacts. These are summarized below.\nAlthough hydrostatic testing is an important tool to identify potentially critical defects, the\nprocess does have some minor adverse environmental impacts. RSPA considered these impacts\nin preparing an Environmental Assessment for the rulemaking on “Risk-Based Alternative to\nPressure Testing Older Hazardous Liquid and Carbon Dioxide Pipelines” ( 63 FR 59475, Docket\n# PS-144). The key points from this Environmental Assessment are summarized below. More\ndetailed information is available in the Environmental Assessment posted to the docket.\nGenerally, preparation for pressure testing necessitates some disturbance of the pipeline right-of-\nway, as short segments of the line may have to be uncovered to conduct the hydrostatic test.\nHowever, there is no significsl: impact on the surrounding land or vegetation as a result of site\npreparation for the test. There should be very little or no other types of environmental impacts\nsuch as noise, air, water, or soil pollution because of the limited amount of equipment (typically\na backhoe and pumps) needed on site and their operating characteristics.\nAnother potential adverse impact of pressure testing can occur if test water is not completely\nremoved from the section of line that is tested. This could result in acidic compounds being\nformed in the line that could be corrosive. If the acidic liquid is subsequently drained from the\nline, it must be contained and disposed of properly to avoid potential localized environmental\nimpacts. However, this drainage would be governed by environmental regulations.\nIntemal inspection also has some minor adverse environmental impacts. If the pipeline is not\nalready equipped to conduct an internal in-line inspection, the operator must install launchers and\nreceivers to insert and remove the internal inspection device. In some situations, valves or other\nappurtenances may need to be replaced or modified to allow these devices to pass through the\nline. Typically, launchers and receivers are installed at compressor stations or other isolation\npoints and no additional environmental disturbance is required. In other instances where new\nlaunchers and receivers must be installed along the pipeline route, and when mainline valves\nneed to be modified or replaced to accommodate inspection devices, there may be a localized\ndisturbance of the area along the pipeline right-of-way. This disturbance is only for a small\nlocalized area on the right-of-way, and does not involve additional vegetation or environmental\ndisturbance beyond the equipment site.\nWhen the internal inspection results and subsequent analysis indicate anomalies that need to be\n10\n\n<<<PAGE 15>>>\n\nDRAFT 6/24/02\nexamined and perhaps repaired, there is additional localized disturbance along the right-of-way\nwhere the excavation occurs. This localized disturbance is confined to the small region of the\nline where the anomaly is located, and typically does not involve damage to vegetation or the\nenvironment beyond the immediate vicinity of the pipeline corridor. Ths localized ground\ndisturbance to correct a defect, has far less impact than the potential consequences of a leak or\nfailure that could occur if the defect were to remain in the pipe..\nSimilarly, a minor degree of localized ground disturbance is experienced when segments of pipe\nare excavated to evaluate pipe conditions that have been identified during the indirect\nexamination phase of direct assessment.\nBased on extensive industry experience, RSPA believes that the benefits of hydrostatic testing,\nin-line internal inspection, or direct assessment in reducing the likelihood of a significant gas\nrelease offset the minor adverse impacts of these techniques described above.\nE. 1.3 Environmental Impacts of Integrity Assessment Requirements\nOPS expects that the proposed rule will lead to an increased and accelerated use of integrity\nassessment by gas transmission pipeline operators. The proposed rule requires that operators\nperform integrity assessment using one of the methods described above for all pipeline segments\nin high consequence areas. The proposed rule provides time limits for the completion of a\nbaseline integrity assessment of all such segments and regular intervals for integrity\nreassessment.\nSome gas pipeline operators currently conduct integrity assessments using internal inspection,\npressure testing, and some elements of direct assessment over portions of their pipelines.\nHowever, the proposed rule will ensure that certain pipeline segments are subject to integrity\nassessment, and that the standards for assessment are uniform. Furthermore, because the\nproposed definition of high consequence area expands the areas where some operators might\nalready have an integrity management plan to include areas with facilities that may be hard to\nevacuate and areas where people congregate, the proposed rule will expand the mileage of\npipeline guaranteed to receive an integrity assessment. In addition, OPS expects that the required\ntime frames for baseline assessment and reassessment will accelerate any voluntary schedule an\noperator may have developed for completing assessments. Because assessments will be\nconducted more widely and more frequently under the proposed rule, there should be a lower\nlikelihood of pipeline failures, as more conditions that could develop into failures are detected by\nintegrity assessments and repaired or otherwise corrected. Reduction in the likelihood of leaks or\nruptures of pipeline segments results in greater protection of humans and the environment,\nbecause the release of gas is prevented and the resulting potential harmful impacts are prevented.\n11\n\n<<<PAGE 16>>>\n\nDRAFT 6/24/02\nHowever, it is difficult to evaluate the magnitude of the enhanced protection that would be\nachieved by the proposed requirements for integrity assessments of gas transmission pipelines.\nOperators currently have strong incentives to protect the integrity of their pipelines and, as stated\nabove, some operators already employ periodic internal inspection and pressure testing as part of\nan integrity program that goes beyond what is required by existing regulations. In developing an\nintegrity management strategy for a given system, operators may consider numerous factors,\nincluding the pipeline’s design parameters and manufacturing process, coating type and\ncondition, age of the system, cathodic protection system performance, observations of pipe\ncondition when the line is exposed for maintenance or other reasons, leak history, operational\nparameters, and the results of previous hydrostatic tests, internal inspections, or close interval\nsurveys. Some operators also consider the proximity of the line to population centers and\nenvironmentally sensitive resources, as well as their commitments to deliver gas to their\ncustomers, in developing testing and inspection plans. For those operators that currently employ\nperiodic integrity assessments, it is likely that pipelines in populated areas receive more frequent\nassessment and increased scrutiny of any conditions that might indicate a threat to pipeline\nintegrity. These existing practices by gas pipeline operators would somewhat limit the additional\nprotection that would be realizcd by implementation of the integrity assessment requirements of\nthe proposed rule. However, as discussed above, it is expected that the proposed rule will result\nin more areas receiving additional protection.\nE. 1.4 Environmental Impacts of Other Preventive and Mitigative Actions\nAnother major element of the proposed rule is the requirement that operators review the existing\npreventive and mitigative measures in place for pipeline segments in high consequence areas and\nconsider what additional activities or enhancements to these measures might be warranted to\nenhance protection. In conducting this evaluation, operators will be required to examine the\nentire range of threats to pipeline integrity in high consequence areas, integrating information\nfrom all applicable and available sources, including applicable experience along the entire\npipeline.\nThe integrated evaluation of this information should identify location-specific conditions that\nmight pose significant risks in high consequence areas, and support improved decisions to\nprotect these areas. Operators will be expected to identify the major risks in high consequence\nareas, prioritize these risks, and consider what actions might be warranted to address the most\nimportant risks. As part of this evaluation, operators will have to conduct risk analysis of their\npipeline segments, critically evaluate the effectiveness of their existing prevention and mitigation\nmeasures, and take measures to prevent and mitigate the consequences of a pipeline failure tha","truncated":true,"body_characters":54644}