# U.S. DOT/RSPA - Environmental Assessment Report - Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) - **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:** Not available - **effective on:** Not available - **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:** <<>> DRAFT 6/24/02 Research and Special Programs Administration U.S. Department of Transportation .I% : =- > J c-7 -7 7 " I 8 _ . 1 L, 1 _1 1 , 7;- - f'- t> ; - - ;-i .. - . I r-> ._. -. c- r _ _ - * -- Environmental Assessment Proposed Rulemaking Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) Docket: RSPA-00-7666 RIN 2137-AD45 <<>> DRAFT 6/24/02 Table of Contents Preliminary Finding of No Significant Impact ... 111 A. B. C. Purpose and Need for Action Description of Proposed Action Alternatives Considered 1 D. Affected Environment E. Environmental Consequences of Proposed Action and Alternatives E. 1 Environmental Impact of the Proposed Integrity Management Rule E.2 Environmental Effects of the Aitzmatives F. Environmental Justice Considerations G. Information Made Available to States, Local Governments, and Individuals H. I. List of Agencies and Persons Consulted Conclusion .. 11 <<>> DRAFT 6/24/02 Preliminary Finding of No Significant Impact - This Environmental Assessment is prepared in accordance with section 102(2)(c) of the National Environmental Policy Act (42 U.S.C. Section 4332), the Council on Environmental Quality regulations (40 CFR Sections 1500-1 508), and Department of Transportation Order 5610.lc, Procedures for Considering Environmental Impacts. It was prepared to assist in the agency’s planning and decision-making. This document concisely describes the Research and Special Programs Administration’s (RSPA) proposed rulemaking to establish integrity management program requirements for operators of natural gas transmission pipelines. This Environmental Assessment also addresses the need for the proposed action, the alternative definitions considered, the environment affected by this action, the consequences to the environment of the proposed action and the alternatives, and a list of the agencies and organizations consulted. This Environmental Assessment provides sufficient evidence to determine that the provisions of the proposed rule are expected to have no significant impact on the environment. ... 111 <<>> DRAFT 6/24/02 A. Purpose and Need-for - Action The Research and Special Programs Administration (RSPA) is proposing new rules for integrity management for gas transmission pipelines. RSPA believes that requiring pipeline operators to implement more systematic and integrated approaches to assure pipeline integrity in areas where incidents have the greatest potential consequences to people and property will enhance control of pipeline risks and improve industry performance. RSPA’s experience in the Risk Management Demonstration Program and System Integrity Inspection (SII) Pilot Program have validated the importance of focusing resources and establishing higher levels of protection in areas where pipeline failure could have significant consequences. These programs showed that some companies are developing more sophisticated and mature integrity management systems and diagnostic tools, resulting in safety, environmental, and economic benefits. RSPA’s Office of Pipeline Safety (OPS) believes the next step is to require all operators to follow at least minimal requirements for integrity management programs that focus on areas of potential significant consequence from pipeline incidents. Congress has directed OPS to consiaer initiatives to improve safety and environmental protection in areas where pipeline failures might have significant consequences. In addition, the National Transportation Safety Board (NTSB) has made several recommendations addressing improved protection for high population and environmentally sensitive areas. RSPA believes that issues raised by these legislative mandates and NTSB recommendations can be best addressed by new requirements for systematic integrity management programs that consider the total spectrum of risks from pipeline operation, including those risks in locations where potential consequences to public health and safety and the environment are high. In 1999, OPS began the development of new regulations for natural gas and hazardous liquid transmission lines in high population areas, commercially navigable waterways, and areas of the environment that are unusually sensitive to damage. Areas fitting one or more of these criteria are referred to as “high consequence areas.” In the ensuing period, OPS has solicited the opinions of industry, other agencies, and stakeholders through public meetings, requests for public comment, an electronic discussion forum, and other smaller meetings and conference calls. After considering the resulting feedback and experience from the Risk Management and SI1 programs, RSPA decided to introduce pipeline integrity management requirements in a series of steps. The first rulemaking covered integrity management for hazardous liquid pipeline operators with 500 or more miles of pipeline. The final rule for these pipeline operators was published on December 1,2000 (65 FR 75378). A similar rule for hazardous liquid operators with less than 500 miles of pipeline was proposed on March 21,2001 and made final on January 16,2002 (67 FR 2136). RSPA began gathering information for the development of new regulations for integrity 1 <<>> DRAFT 6/24/02 management for gas pipeline operators through meetings with representatives of the gas pipeline industry, research institutions, state pipeline safety agencies, and public interest groups. In February, 2001, OPS held a public meeting to exchange information on the potential regulations. Summaries of all meetings and the information exchanged may be found in DOT docket number RSPA-2000-7666 and on the OPS web site under InitiativesPipeline Integrity Management ProgrdGas Transmission Operators Rule. OPS published a Notice in the Federal Register in June, 2001 (66 FR 34318) requesting further information and clarification and inviting further public comment on integrity management concepts for gas pipelines. The Notice also announced the establishment of an electronic public discussion forum for gas pipeline integrity management issues on OPS’s Internet home page. In this notice, OPS invited comment on seven elements it considered important to include in the integrity management rule and hypotheses related to these elements. The comments received are included in the docket along with the transcript of the electronic discussion forum. The first of the seven elements was the definition of high consequence areas. OPS decided to propose an initial rule defining high consequence areas for gas pipeline integrity management before proposing other requirements for gas integrity management programs. OPS considered the received comments before developing the proposed high consequence area definition, which is described in a Notice of Proposed Rulemaking in the Federal Register of January 9,2002 (67 FR 1108). An Environmental Assessment was prepared for this proposed rulemaking (Docket RSPA-2000-7666). Because of the different risks associated with gas transmission pipelines compared to hazardous liquid pipelines, the proposed definition for gas pipelines is different than the definition in the hazardous liquid integrity management rule (see 65 FR 75378). OPS is now proposing rules for integrity management of gas transmission pipelines in high consequence areas. B. Description of Proposed Action RSPA proposes to add a new section to 49 CFR 192, which is expected to enhance the integrity of gas transmission pipelines in high consequence areas. The proposed rule requires each operator to develop and implement an integrity management program that provides for continual assessment of the integrity of all pipeline segments located in high consequence areas. The proposed rule further requires that the program provide for evaluating the entire range of threats to each pipeline segment’s integrity through comprehensive information analysis and ensuring additional protection to a pipeline segment’s integrity though remedial actions and preventive and mitigative measures. The proposed rule applies to all gas transmission pipelines, as defined in Section 192.3. This would include transmission pipelines transporting petroleum gas, hydrogen, and other gas 2 <<>> DRAFT 6/24/02 management for gas pipeline operators through meetings with representatives of the gas pipeline industry, research institutions, state pipeline safety agencies, and public interest groups. In February, 2001, OPS held a public meeting to exchange information on the potential regulations. Summaries of all meetings and the information exchanged may be found in DOT docket number RSPA-2000-7666 and on the OPS web site under InitiativesPipeline Integrity Management ProgrdGas Transmission Operators Rule. OPS published a Notice in the Federal Register in June, 2001 (66 FR 343 18) requesting further information and clarification and inviting further public comment on integrity management concepts for gas pipelines. The Notice also announced the establishment of an electronic public discussion forum for gas pipeline integrity management issues on OPS’s Internet home page. In this notice, OPS invited comment on seven elements it considered important to include in the integrity management rule and hypotheses related to these elements. The comments received are included in the docket along with the transcript of the electronic discussion forum. The first of the seven elements was the definition of high consequence areas. OPS decided to propose an initial rule defining high consequence areas for gas pipeline integrity management before proposing other requirements for gas integrity management programs. OPS considered the received comments before developing the proposed high consequence area definition, which is described in a Notice of Proposed Rulemaking in the Federal Register of January 9,2002 (67 FR 1108). An Environmental Assessment was prepared for this proposed rulemaking (Docket RSPA-2000-7666). Because of the different risks associated with gas transmission pipelines compared to hazardous liquid pipelines, the proposed definition for gas pipelines is different than the definition in the hazardous liquid integrity management rule (see 65 FR 75378). OPS is now proposing rules for integrity management of gas transmission pipelines in high consequence areas. B. Description of Proposed Action RSPA proposes to add a new section to 49 CFR 192, which is expected to enhance the integrity of gas transmission pipelines in high consequence areas. The proposed rule requires each operator to develop and implement an integrity management program that provides for continual assessment of the integrity of all pipeline segments located in high consequence areas. The proposed rule further requires that the program provide for evaluating the entire range of threats to each pipeline segment’s integrity through comprehensive information analysis and ensuring additional protection to a pipeline segment’s integrity though remedial actions and preventive and mitigative measures. The proposed rule applies to all gas transmission pipelines, as defined in Section 192.3. This would include transmission pipelines transporting petroleum gas, hydrogen, and other gas 2 <<>> DRAFT 6/24/02 products covered under Part 192. The proposal does not apply gas distribution lines. It applies to. all facilities through which gas moves, including pipe, valves, compressor units, metering stations, regulator stations, delivery stations, holders, and fabricated assemblies. It does not apply to pipelines operating at a hoop stress of less than 20% specified minimum yield strength ( S M Y S ) and gathering lines. The proposed rule requires that, no later than one year after the effective date of the final rule, each operator has a written integrity management program, consisting of: 1. An identification of all pipeline segments covered by the proposed rule. 2. A plan for baseline integrity assessment of each pipeline segment. This plan must include the assessment method, the schedule for completion of assessments, and explanation of the choice of assessment methods and the risk factors considered in establishing the assessment schedule. The assessment method used could be internal inspection tool or tools, pressure test, Direct Assessment, or other technology that the operator demonstrates can prcvide an equivalent understanding of the condition of the line pipe. Different time limits for the completion of integrity assessments of segments apply according to the location of the segments and if direct assessment is chosen as the assessment method. 3. For an operator planning to use Direct Assessment, a plan describing how it will use the method, including identification of External Corrosion Direct Assessment Regions; 4. A program framework that addresses each of the required program elements, including continual integrity assessment and evaluation. The framework is required to document how decisions will be made to implement each element. The frame work will evolve into an integrity management program as the operator makes decisions and gains experience. An integrity management program is dynamic program that an operator would continually change as the operator gains more information about the pipeline and results of the assessments. C. Alternatives Considered RSPA considered alternatives to the proposed integrity management requirements given in Section B above. These alternatives are summarized below: 1. Take No Action. In this alternative, RSPA would not propose new integrity management requirements for high consequence areas but would rely on the existing regulatory requirements to provide protection for all areas. This alternative would not be responsive to Congressional 3 <<>> DRAFT 6/24/02 mandates or NTSB recommendations. This alternative would not provide the protection provided by the proposed rule of required integrity assessment and repair of detected defects or the consideration of other preventive and mitigative measures to protect high consequence areas 2. Use the Same Provisions as in the Hazardous Liquids Integrity Management Rule (192.452). The main differences between the proposed rule and the requirements of 192.452 are: (1) the time limits for completing the baseline integrity assessment and reassessment of pipeline segments that could affect high consequence areas and (2) the option of using direct assessment as an assessment method (not allowed in 192.452). The time limit for baseline assessment under the liquid rule is seven years, while the limit for baseline assessments under the proposed rule is ten years. OPS believes that requiring the shorter period for completing baseline assessments would cause negative impacts on gas supply and cost for consumers. In addition, further compressing the period required for completing baseline integrity assessments is expected to place a strain on companies providing assessment services. This strain could cause the quality of assessments to suffer. The liquid pipeline rule requires reassessment every five years, while the proposed rule requires a maximum interval for reassessment of ten years (for pipelines operating above 50% SMYS) or fifteen years (for pipelines operating below 50% S M Y S ) . If direct assessment is used, the proposed rule requires a reassessment interval of no more than five years (unless the operator verifies all anomalies by excavation, in which case a ten year interval is allowed). In developing the proposed rule, OPS has considered the important differences between gas transmission and hazardous liquids pipelines. Key differences include the existing regulations that require gas operators to obtain and maintain population data on the areas surrounding their pipelines and to replace their pipe with higher strength pipe when certain population thresholds are reached. Hazardous liquid operators have no such requirement. For this reason, gas transmission pipelines in high population areas generally operate at lower stresses than liquid pipelines in populated areas (typically 40-50% SMYS for gas pipelines vs. 72% SMYS for liquid pipelines). Studies indicate that internal inspection is not possible for a substantial percentage of gas transmission lines. Industry estimates indicate up to 50% of gas transmission pipelines can be modified to allow internal inspection only at a cost of between $88 billion to $710 billion. Pressure testing all these lines could impose negative effects on the supply of gas to consumers. Direct assessment is the only assessment method that could be employed in these lines to avoid 4 <<>> DRAFT 6/24/02 these negative impacts. Furthermore, under the proposed rule, if direct assessment is used for pipeline segments, those segments are subjected to shorter intervals for reassessment. Because of the significant differences between gas transmission and hazardous liquid pipelines, OPS has proposed different provisions for the gas integrity management rule. D. Affected Environment The purpose of the rule is to provide additional protection to hgh consequence areas in the vicinity of gas transmission pipelines throughout the United States. The baseline integrity assessment and periodic re-assessments, as well as the additional preventive and mitigative activities that evolve from the operator’s integrity management program, apply to segments on the operator’s pipeline that are in high consequence areas. Thus the primary areas of the environment impacted by this rule are high consequence areas, as defined in the rule for defining high consequence areas for gas transmission pipelines’: 8 Class 3 areas. Class 3 areas are defined in the pipeline safety regulations as a class location unit with 46 or more buildings intended for human occupancy. A class location unit is an area that extends 220 yards on either side of the centerline of any continuous one-mile length of pipeline. A class 3 area is also an area where the pipeline lies within 100 yards of either a building or a small, well-defined outside area, such as a playground, recreation area, outdoor theater, or other place of public assembly, which is occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12-month period. Neither the days nor the weeks need be consecutive. 8 Class 4 areas. A Class 4 area is any class location unit where buildings with four or more stories are prevalent. 8 Areas where a pipeline lies within 660 feet (or within 300 feet where pipeline is less than or equal to 12 inches diameter and operates at a MAOP of less than or equal to 1200 psig, or within 1000 feet2 where the pipeline is greater than 30 inches in diameter and operates at a MAOP greater than 1000 psig) of a well-known @e. licensed, or visibly marked, or 2 1 “Pipeline Safety: High Consequence Areas for Gas Transmission Pipelines,” Final Rule, 67 FR XXXX, XXX X, 2002. In a few cases the threshold may exceed 1000 feet, depending upon pipe diameter and MAOP. 5 <<>> DRAFT 6/24/02 known to local public officials) building or facility such as hospital, school, day-care facility, retirement facility, stadium, prison, or other facility having personswho are confined, are of impaired mobility or would be difficult to evacuate. 0 Areas where a pipeline lies within 660 feet (or within 300 feet where pipeline is less than or equal to 12 inches diameter and operates at a MAOP of less than or equal to 1200 psig, or withln 1000 feet2 where the pipeline is greater than 30 inches in diameter and operates at a MAOP greater than 1000 psig) of either a building or a small, well-known (i.e. licensed, or visibly marked, or known to local public officials) outside area where 20 or more persons congregate at least 50 days in any 12-month period. (The days need not be consecutive.) Examples of such areas include, but are not limited to, beaches, recreational facilities, camping grounds, and religious facilities. After they are initially established, high consequence areas will be updated on a periodic basis to incorporate new information and data. For example, as communities and populations grow, the extent of Class 3 locations (as defined in §192.5@)(3)(1) and §192.5(b)(3)(ii)) may expand. If so, the operator will need to apply any integrity management requirements to the expanded area. In addition to the defined areas, the provisions of a proposed integrity management rule are likely to affect areas of the environment beyond the high consequence area. For example, some operators will choose to use internal inspection to fulfill the requirement. Due to economic and operational considerations, the launchers and receivers used to insert and remove internal inspection tools are typically Iocated at compressor stations or other isolation points, which can be many miles apart, Even though a high consequence area may exist for only a short distance along the line, because of the location of inspection tool launchers and receivers, operators will likely inspect the entire extended section of the line. Thus, in addition to the information about the condition of the line segment that could affect a high consequence area, the operator will obtain integrity data about a much larger section of pipe. Similarly, the consideration and potential implementation of additional preventive and mitigative measures has can affect additional areas beyond the boundaries of high consequence areas. For example, if Remove Control Valves (RCVs) are installed to mitigate the release of gas following a line rupture or leak, then this benefit extends along the full length of the section of the pipe between valves. This may include both pipe segments that are could affect nearby high consequence areas and segments that are not in proximity to high consequence areas. E. Environmental Consequences of Proposed Action and Alternatives This section describes the expected impact to the environment of the proposed action (Section 6 <<>> DRAFT 6/24/02 E. 1) and the alternatives (Section E.2). E. 1 Environmental Impact of the Proposed Integritv Management Rule Section B describes the requirements for the proposed rule. This section discusses the impacts of these requirements. E. 1.1 Overview of Integrity Assessment Methods The integrity assessment methods explicitly allowed by the proposed rule include internal in-line inspection, pressure testing, and direct assessment. The proposed rule does allow for an operator to employ unspecified possible alternative integrity assessment methods, if the operator can demonstrate the alternative method provides an equivalent level of effectiveness as the methods specified in the proposed rule. However, OPS expects that gas pipeline operators will rely on the specified methods to perfom integrity assessments for almost all segments. Internal in-line inspection, also referred to as “smart pigging,” involves the use of an electronically instrumented device traveling inside the pipe that measures characteristics of the pipe wall. There are several different technologies used by internal inspection devices. The most common tools in use are: Geometry pigs, which contain electronic sensors that detect geometric or configuration changes in the pipe such as dents, buckles, wrinkles, and ovalities. They are used to identify construction-related or other outside force damage. Magnetic flux leakage pigs, which produce a magnetic flux field in the pipe wall that can indicate changes in wall thickness. Flux variations are used to indicate localized pipe wall thinning due to internal or external corrosion, or certain types of gouges. Ultrasonic tools, which use sound waves to identify anomalies. There are several designs of ultrasonic tools capable of detecting wall thinning and crack or crack-like defects. Currently, there is no single internal inspection tool that can detect all types of pipeline defects or damage. Hence, the selection of a specific tool depends on what type of pipeline damage the operator is trying to identify. Some operators run geometry or caliper pigs, in combination with magnetic flux leakage tools, to identify both geometric defects, as well as corrosion metal loss. The internal inspection tool output is analyzed to identify the location and severity of pipe wall anomalies or defects. Several industry-accepted methods are used to determine the severity of flaws and the remaining strength of the pipe. In addition, pig vendors, consultants, and operators 7 <<>> DRAFT 6/24/02 are developing more sophisticated analytical tools to take advantage of the increasing quality and accuracy of the data available from higher resolution inspection tools. These calculations consider the depth, geometry, and configuration of corroded areas, as well as the proximity to other anomalies to estimate the remaining strength of the pipe at the location of the anomaly. The calculations are used to identify which anomalies are in need of repair (Le., those areas where the remaining pipe strength is approaching a level where integrity during future operation might be compromised), and to prioritize the excavation and examination of pipe wall defects. After interpreting and analyzing the results from a pig run, operators typically develop an excavation and repair plan. This plan involves excavating selected anomaly locations to examine the extent of damage and thus confirm the information identified by the pig. After validating the accuracy of the pig runs through these confirmation digs3, the operator will excavate, examine, and repair, if necessary, those anomalies that have the most potential to threaten pipeline integrity. Operators develop their own criteria for scheduling anomaly repair work. Typically those indications that might pose a near term or immediate threat to pipeline integrity are repaired as soon as possible. Other, less severe defects typically become part of a longer term maintenance plan. Hydrostatic Dressure testing is ths second method of integrity assessment allowed by the proposed rule. During a hydrostatic test, a segment of the pipeline is filled with water, pressurized to a predetermined pressure, and held at this test pressure for a predetermined length of time. This testing is performed to eliminate any significant material defects or flaws that might result in failure. The test pressure normally exceeds the pipeline’s maximum allowable operating pressure. Thus the pipe is subjected to stresses much higher than it would encounter during system operation. After the testing is completed, the only defects remaining in the pipe are those that should not fail at the lower, normal operating pressures. Hydrostatic testing is especially valuable in ensuring that significant longitudinal seam weld flaws and stress corrosion cracks are not present. These two failure causes can be difficult to detect with many internal inspection devices. Direct assessment, the third integrity assessment method allowed in the proposed rule, is a method of integrating knowledge of the physical characteristics, environment, and operating history of a pipeline with the results of indirect inspection, direct examination, and analysis to evaluate threats to the line’s integrity. Different direct assessment approaches are taken to assess a pipeline’s condition with respect to different causes of pipeline failure, including external corrosion, internal corrosion, and stress corrosion cracking. The proposed rule allows direct Some operators that use modem, high resolution magnetic flux tools do not perform confirmation digs. 8 <<>> DRAFT 6/24/02 assessment to be used ifthe pipeline meets certain criteria that ensure that direct assessment methods will be effective in assessing the pipe’s integrity. For direct assessment of external corrosion (ECDA), the proposed rule requires the operator to select at least two indirect examination methods for each section of a pipeline where direct assessment is to be applied. Possible choices for indirect examination tools are Close Interval Surveys (CIS), Direct or Alternate Current Voltage Gradient (DCVG or ACVG), or electromagnetic techniques such as Pipeline Current Mapper (PCM) and C-Scan. The indirect examination methods are applied and the results are analyzed and compared to one another and to operating history. Indications that might represent defects are classified according to severity. The next step in direct assessment is excavation of indications according to the severity of the indicated conditions from the indirect examinations. Direct assessment for internal corrosion involves flow modeling to identify the most likely locations of water accumulation, direct examination by evacuation and inspection by ultrasonic, x-ray, or other technology, and chemical analysis of fluids drawn off the pipeline to determine if corrosion products are present. E. 1.2 Environmental Impacts of Integrity Assessment Methods The purpose of the integrity assessment methods described in Section E. 1.1 above is to identify defects or anomalies in the pipe wall that might result in failure if operation were to continue with these defects still in place. Defects such as corrosion damage, deformation incurred during construction, and outside force damage to the pipe can be identified by these inspection techniques and repaired. Eliminating or repairing these defects provides greater assurance of pipeline integrity and reduces the probability that the pipe will fail during subsequent operation. Gas transmission pipelines transport pressurized natural gas, which is lighter than air and flammable. If released as a result of a pipeline failure, natural gas can potentially ignite, causing fires or explosions. Industry experience demonstrates that environmental consequences of pipeline rupture-initiated fires are almost always limited to damage to the vegetation and animal life in the area adjacent to the failure site. It is possible that a rupture occurring in a heavily forested area in the dry season could result in a forest fire, which could have a more extensive impact on wildlife and vegetation. However, the likelihood of such an occurrence is believed to be very low. Other than localized damage to vegetation and animal life in the event of a fire or explosion, there are no significant environmental impacts from natural gas pipeline leaks or ruptures. While integrity assessment and repair of defects that are detected cannot eliminate all pipeline failures, they can reduce the frequency of these events. Thus on a national scale, the cumulative 9 <<>> DRAFT 6/24/02 environmental damage fiom gas pipeline accidents is reduced. Since the provisions of the rule will be implemented on line segments that can affect populated areas, it is expected that these areas will benefit by the reduced likelihood of pipeline failure in these areas. Even though these integrity assessment and repair practices can reduce the frequency of spills to the environment, they are not without some adverse impacts. These are summarized below. Although hydrostatic testing is an important tool to identify potentially critical defects, the process does have some minor adverse environmental impacts. RSPA considered these impacts in preparing an Environmental Assessment for the rulemaking on “Risk-Based Alternative to Pressure Testing Older Hazardous Liquid and Carbon Dioxide Pipelines” ( 63 FR 59475, Docket # PS-144). The key points from this Environmental Assessment are summarized below. More detailed information is available in the Environmental Assessment posted to the docket. Generally, preparation for pressure testing necessitates some disturbance of the pipeline right-of- way, as short segments of the line may have to be uncovered to conduct the hydrostatic test. However, there is no significsl: impact on the surrounding land or vegetation as a result of site preparation for the test. There should be very little or no other types of environmental impacts such as noise, air, water, or soil pollution because of the limited amount of equipment (typically a backhoe and pumps) needed on site and their operating characteristics. Another potential adverse impact of pressure testing can occur if test water is not completely removed from the section of line that is tested. This could result in acidic compounds being formed in the line that could be corrosive. If the acidic liquid is subsequently drained from the line, it must be contained and disposed of properly to avoid potential localized environmental impacts. However, this drainage would be governed by environmental regulations. Intemal inspection also has some minor adverse environmental impacts. If the pipeline is not already equipped to conduct an internal in-line inspection, the operator must install launchers and receivers to insert and remove the internal inspection device. In some situations, valves or other appurtenances may need to be replaced or modified to allow these devices to pass through the line. Typically, launchers and receivers are installed at compressor stations or other isolation points and no additional environmental disturbance is required. In other instances where new launchers and receivers must be installed along the pipeline route, and when mainline valves need to be modified or replaced to accommodate inspection devices, there may be a localized disturbance of the area along the pipeline right-of-way. This disturbance is only for a small localized area on the right-of-way, and does not involve additional vegetation or environmental disturbance beyond the equipment site. When the internal inspection results and subsequent analysis indicate anomalies that need to be 10 <<>> DRAFT 6/24/02 examined and perhaps repaired, there is additional localized disturbance along the right-of-way where the excavation occurs. This localized disturbance is confined to the small region of the line where the anomaly is located, and typically does not involve damage to vegetation or the environment beyond the immediate vicinity of the pipeline corridor. Ths localized ground disturbance to correct a defect, has far less impact than the potential consequences of a leak or failure that could occur if the defect were to remain in the pipe.. Similarly, a minor degree of localized ground disturbance is experienced when segments of pipe are excavated to evaluate pipe conditions that have been identified during the indirect examination phase of direct assessment. Based on extensive industry experience, RSPA believes that the benefits of hydrostatic testing, in-line internal inspection, or direct assessment in reducing the likelihood of a significant gas release offset the minor adverse impacts of these techniques described above. E. 1.3 Environmental Impacts of Integrity Assessment Requirements OPS expects that the proposed rule will lead to an increased and accelerated use of integrity assessment by gas transmission pipeline operators. The proposed rule requires that operators perform integrity assessment using one of the methods described above for all pipeline segments in high consequence areas. The proposed rule provides time limits for the completion of a baseline integrity assessment of all such segments and regular intervals for integrity reassessment. Some gas pipeline operators currently conduct integrity assessments using internal inspection, pressure testing, and some elements of direct assessment over portions of their pipelines. However, the proposed rule will ensure that certain pipeline segments are subject to integrity assessment, and that the standards for assessment are uniform. Furthermore, because the proposed definition of high consequence area expands the areas where some operators might already have an integrity management plan to include areas with facilities that may be hard to evacuate and areas where people congregate, the proposed rule will expand the mileage of pipeline guaranteed to receive an integrity assessment. In addition, OPS expects that the required time frames for baseline assessment and reassessment will accelerate any voluntary schedule an operator may have developed for completing assessments. Because assessments will be conducted more widely and more frequently under the proposed rule, there should be a lower likelihood of pipeline failures, as more conditions that could develop into failures are detected by integrity assessments and repaired or otherwise corrected. Reduction in the likelihood of leaks or ruptures of pipeline segments results in greater protection of humans and the environment, because the release of gas is prevented and the resulting potential harmful impacts are prevented. 11 <<>> DRAFT 6/24/02 However, it is difficult to evaluate the magnitude of the enhanced protection that would be achieved by the proposed requirements for integrity assessments of gas transmission pipelines. Operators currently have strong incentives to protect the integrity of their pipelines and, as stated above, some operators already employ periodic internal inspection and pressure testing as part of an integrity program that goes beyond what is required by existing regulations. In developing an integrity management strategy for a given system, operators may consider numerous factors, including the pipeline’s design parameters and manufacturing process, coating type and condition, age of the system, cathodic protection system performance, observations of pipe condition when the line is exposed for maintenance or other reasons, leak history, operational parameters, and the results of previous hydrostatic tests, internal inspections, or close interval surveys. Some operators also consider the proximity of the line to population centers and environmentally sensitive resources, as well as their commitments to deliver gas to their customers, in developing testing and inspection plans. For those operators that currently employ periodic integrity assessments, it is likely that pipelines in populated areas receive more frequent assessment and increased scrutiny of any conditions that might indicate a threat to pipeline integrity. These existing practices by gas pipeline operators would somewhat limit the additional protection that would be realizcd by implementation of the integrity assessment requirements of the proposed rule. However, as discussed above, it is expected that the proposed rule will result in more areas receiving additional protection. E. 1.4 Environmental Impacts of Other Preventive and Mitigative Actions Another major element of the proposed rule is the requirement that operators review the existing preventive and mitigative measures in place for pipeline segments in high consequence areas and consider what additional activities or enhancements to these measures might be warranted to enhance protection. In conducting this evaluation, operators will be required to examine the entire range of threats to pipeline integrity in high consequence areas, integrating information from all applicable and available sources, including applicable experience along the entire pipeline. The integrated evaluation of this information should identify location-specific conditions that might pose significant risks in high consequence areas, and support improved decisions to protect these areas. Operators will be expected to identify the major risks in high consequence areas, prioritize these risks, and consider what actions might be warranted to address the most important risks. As part of this evaluation, operators will have to conduct risk analysis of their pipeline segments, critically evaluate the effectiveness of their existing prevention and mitigation measures, and take measures to prevent and mitigate the consequences of a pipeline failure tha - **truncated:** true - **body characters:** 54644