# Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines)

- **operation:** document
- **citation:** 68 FR 4278
- **title:** Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines)
- **source type:** rulemaking
- **agency:** Research and Special Programs Administration
- **status:** proposed
- **official:** true
- **published on:** 2003-01-28
- **effective on:** Not available
- **summary:** This document proposes to establish a rule to require operators to develop integrity management programs for gas transmission pipelines that, in the event of a failure, could impact high consequence areas (HCAs). These integrity management programs would focus on requiring operators to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in high consequence areas. RSPA/OPS recently finalized the definition of high consequence areas by a separate rulemaking. This proposed rule proposes to expand the definition of HCAs by adding consideration of people living at distances greater than 660 feet from large diameter high pressure pipelines. The current HCA definition only requires consideration of people living at distances up to 660 feet from pipelines.
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- **source url:** https://www.federalregister.gov/documents/2003/01/28/03-603/pipeline-safety-pipeline-integrity-management-in-high-consequence-areas-gas-transmission-pipelines
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Federal Register, Volume 68 Issue 18 (Tuesday, January 28, 2003) [Federal Register Volume 68, Number 18 (Tuesday, January 28, 2003)] [Proposed Rules] [Pages 4278-4335] From the Federal Register Online via the Government Publishing Office [ www.gpo.gov ] [FR Doc No: 03-603] [[Page 4277]] ----------------------------------------------------------------------- Part II Department of Transportation ----------------------------------------------------------------------- Research and Special Programs Administration ----------------------------------------------------------------------- 49 CFR Part 192 Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines); Proposed Rule Federal Register / Vol. 68, No. 18 / Tuesday, January 28, 2003 / Proposed Rules [[Page 4278]] ----------------------------------------------------------------------- DEPARTMENT OF TRANSPORTATION Research and Special Programs Administration 49 CFR Part 192 [Docket No. RSPA-00-7666; Notice 4] RIN 2137-AD54 Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) AGENCY: Office of Pipeline Safety (OPS), Research and Special Programs Administration (RSPA), DOT. ACTION: Notice of proposed rulemaking. ----------------------------------------------------------------------- SUMMARY: This document proposes to establish a rule to require operators to develop integrity management programs for gas transmission pipelines that, in the event of a failure, could impact high consequence areas (HCAs). These integrity management programs would focus on requiring operators to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in high consequence areas. RSPA/OPS recently finalized the definition of high consequence areas by a separate rulemaking. This proposed rule proposes to expand the definition of HCAs by adding consideration of people living at distances greater than 660 feet from large diameter high pressure pipelines. The current HCA definition only requires consideration of people living at distances up to 660 feet from pipelines. DATES: Interested persons are invited to submit written comments by March 31, 2003. Late-filed comments will be considered to the extent practicable. ADDRESSES: Filing Information You may submit written comments by mail or delivery to the Dockets Facility, U.S. Department of Transportation, Room PL-401, 400 Seventh Street, SW., Washington, DC 20590-0001. It is open from 10 a.m. to 5 p.m., Monday through Friday, except Federal holidays. All written comments should identify the docket and notice numbers stated in the heading of this notice. Anyone desiring confirmation of mailed comments must include a self-addressed stamped postcard. Electronic Access You may also submit written comments to the docket electronically. To submit comments electronically, access the following Internet Web address: http://dms.dot.gov . Click on ``Help & Information'' for instructions on how to file a document electronically. Privacy Act Information Anyone is able to search the electronic form of all comments received into any of our dockets by the name of the individual submitting the comment (or signing the comment, if submitted on behalf of an association, business, labor union, etc.). You may review DOT's complete Privacy Act Statement in the Federal Register published on April 11, 2000 (Volume 65, Number 70; Pages 19477-78) or you may visit http://dms.dot.gov . General Information You may contact the Dockets Facility by phone at (202) 366-9329, for copies of this proposed rule or other material in the docket. All materials in this docket may be accessed electronically at http://dms.dot.gov/search . Once you access this address, type in the last four digits of the docket number shown at the beginning of this notice (in this case 7666), and click on search. You will then be connected to all relevant information. FOR FURTHER INFORMATION CONTACT: Mike Israni by phone at (202) 366- 4571, by fax at (202) 366-4566, or by e-mail at [email protected] , regarding the subject matter of this proposed rule. General information about the RSPA/OPS programs may be obtained by accessing RSPA's Internet page at http://RSPA.dot.gov . SUPPLEMENTARY INFORMATION: RSPA/OPS believes it can best assure pipeline integrity by requiring each operator to: (a) Implement a comprehensive integrity management program; (b) conduct a baseline assessment and periodic reassessments focused on identifying and characterizing applicable threats; (c) mitigate significant defects discovered in this process; and (d) monitor the effectiveness of their programs so appropriate modifications can be recognized and implemented. This approach also recognizes that improving integrity requires operators to gather and evaluate data on the performance trends resulting from their programs, and to make improvements and corrections based on this evaluation. This proposed rule does not apply to gas gathering or to gas distribution lines. This proposed rule will satisfy Congressional mandates for RSPA/OPS to prescribe standards that establish criteria for identifying each gas pipeline facility located in a high-density population area and to prescribe standards requiring the periodic inspection of pipelines located in these areas, including the circumstances under which an inspection can be conducted using an instrumented internal inspection device (smart pig) or an equally effective alternative inspection method. The proposed rule also incorporates the required elements for gas integrity management programs recently mandated in the Pipeline Safety Improvement Act of 2002, which was signed into law on December 17, 2002. Background RSPA/OPS is in the midst of promulgating a series of rules intended to require pipeline operators to develop integrity management programs for their entire systems, and to conduct baseline and periodic assessments of pipeline segments the failure of which could imperil the health and safety of nearby residents and cause significant damage to their property. These integrity management programs, written differently for the liquid and natural gas pipeline systems, are designed with the goal of identifying the best method(s) for maintaining the structural soundness (i.e., integrity) of transmission pipelines operating across the United States. RSPA/OPS began this series of integrity management rulemakings by issuing requirements pertaining to hazardous liquid operators. A final rule applying to hazardous liquid operators with 500 or more miles of pipeline was published on December 1, 2000 (65 FR 75378). The hazardous liquid rule applies to pipeline segments that can affect high consequence areas (HCAs), which under the liquid rule criteria include populated areas defined by the Census Bureau as urbanized areas or places, unusually sensitive environmental areas, and commercially navigable waterways. RSPA/OPS issued a similar rule for hazardous liquid operators with less than 500 miles of pipeline (66 FR 2136; January 16, 2001). Earlier this year, RSPA/OPS explained in the Federal Register that we were beginning the integrity management rulemakings for gas transmission lines by first proposing a definition of HCAs (67 FR 1108; January 9, 2002). We also described our plan to propose integrity management program requirements for gas transmission pipelines affecting those areas. In that proposed rule on HCAs ( January 9, 2002), we also said we had decided first to propose the definition of HCAs and then to propose the gas integrity management rule. We chose to propose the regulation in two separate steps for a number of reasons. For example, operators already have good information [[Page 4279]] (through the Class Location Requirements) on where the potential consequences of a gas pipeline accident may be most significant. In addition, since we were still collecting information and verifying the validity of assessment methods other than internal inspection and pressure testing, presenting the gas pipeline integrity management requirements as a single rule would delay review of the HCA definition. RSPA/OPS recently finalized the definition of HCAs (67 FR 50824; August 6, 2002). In the current definition of HCAs (August 6, 2002), we noted four significant characteristics of gas pipelines ruptures and explosions that are relevant in defining HCAs. These same characteristics are useful here in the context of developing integrity management regulations. Those characteristics are: (1) The effects of a gas pipeline rupture and subsequent explosion are highly localized. The physical properties of natural gas dictate that it rises upward from a rupture as the gas expands into the air; (2) The zone of damage or heat affected zone following a rupture is related to the line's diameter and the pressure at which the pipeline is operated; (3) The size of the heat affected zone from pipeline ruptures where pipe diameter was less than 36 inches and operating pressures were at or below 1000 psig, was limited to a diameter of 660 feet; and (4) The heat affected zone for pipelines of 36 inches or greater, operating at pressures in excess of 1000 psig, can extend 1000 feet. Based on these findings, the HCA definition included language that would require operators of large diameter pipelines operating at high pressures to include areas within a 1000 foot radius from the pipeline. This proposed rule, referred to as the gas integrity management program (IMP) rule, will expand the current definition of HCAs (August 6, 2002), by adding consideration of people living at distances greater than 660 feet from large diameter high pressure pipelines. This expansion is based on the need to provide the same level of added protection to population groups, as the current HCAs provide to facilities that house people who are difficult to evacuate, people with impaired mobility, people who are confined, and areas where people congregate. This population group living at distances greater than 660 feet was inadvertently omitted from the definition when we proposed and later finalized the HCA definition. The HCA definition for gas transmission lines was based on broad corridors that could potentially be impacted from a pipeline rupture and explosion. However, additional calculations have to be used to determine the likely actual area that would be impacted. This proposed gas integrity management rule provides a method to analyze how a pipeline segment will impact an HCA if the segment fails. The definitions of a potential impact circle and potential impact zone that we are proposing, that are based on a mathematical equation, will essentially determine the likely actual area within an HCA that would be impacted. Whereas the HCA definition is based on broad corridors (i.e., lateral distances perpendicular to pipeline) but not longitudinal distances (i.e., axially along the pipeline), the potential impact circle and potential impact zones that we are proposing will provide longitudinal distances to define the actual area of impact in an HCA, and narrow the area to which the proposed assessment and repair requirements will apply. This proposed rule also defines a Moderate Risk Area as an area located within a Class 3 or Class 4 location, but not within the potential impact zone. Whether a building located in a rural area, such as a rural church, which is currently included in the High Consequence Area definition, should be designated as a Moderate Risk Area requiring less frequent assessment or requiring enhanced preventive and mitigative measures is an issue for public comment that we discuss later in this document. The process of identifying pipeline segments that are located in high consequence areas and moderate risk areas is described below under Covered Segments. Pipeline Safety Improvement Act of 2002 On November 15, 2002, Congress passed H.R. 3609, the Pipeline Safety Improvement Act of 2002. The President signed the bill on December 17, 2002. Section 14 of H.R. 3609 contains requirements for integrity management programs for gas pipelines located in high consequence areas. The proposed rule which RSPA has been working on for some time is substantially in alinement with section 14 of H.R. 3609. However, there are differences. We have incorporated the requirements of section 14 into this proposed rule. These areas include the intervals for conducting baseline and reassessment testing, consideration of testing done prior to the final rule, the incorporation of issues raised by State and local authorities, the conduct of testing in an environmentally appropriate manner, a requirement that the operator notify RSPA of changes to its program, and a means to make copies of operator records available to State interstate agents. Rule Synopsis The elements of an integrity management program are to consist of: (i) An identification of covered pipeline segments and the potential impact zone for each segment; (ii) a baseline assessment plan; (iii) an identification of threats to each covered pipeline segment, including risk assessments of each covered segment; (iv) a direct assessment plan, if direct assessment is to be used; (v) provisions for remediating conditions found; (vi) a process for continual evaluation and assessment; (vii) preventive and mitigative measures; (viii) a performance plan as outlined in ASME/ANSI B31.8S, Section 9; (ix) recordkeeping requirements; (x) a management of change process as outlined in ASME/ANSI B31.8S, Section 11; (xi) a quality assurance process as outlined in ASME/ANSI B31.8S, Section 12; (xiii) a communication plan based on ASME/ANSI B31.8S, Section 10, to include a process for addressing safety concerns raised by OPS, including safety concerns OPS raises on behalf of a State authority with which OPS has an interstate agent agreement and of local authorities; (xiv) a process for providing, by electronic or other means, a copy of the operator's integrity management program to a State authority with which OPS has an interstate agent agreement; and (xv) a process for ensuring that each integrity assessment is being conducted in a manner that minimizes environmental and safety risks. Covered Segments Operators must identify covered segments prior to performing assessments. A covered segment is any transmission pipeline segment. The approach involves six steps that rely on the definitions contained in section 192.761. Those six steps are: (1) Identify all high consequence areas for the pipeline using the HCA definition as expanded by this proposed rule; (2) calculate the Potential Impact Radius (PIR) for each covered segment in the pipeline; (3) determine the Threshold Radius associated with the PIR for each segment; (4) identify Potential Impact Circles for the pipeline; (5) identify the Potential Impact Zones (PIZ) for the pipeline, and based on that zone for covered segments located in Class 3 and Class 4 locations, identify the moderate [[Page 4280]] risk areas; and (6) determine the priority of each covered pipeline segment (i.e., segments subject to the proposed rule that are within a potential impact zone are considered higher impact zones; those segments outside a PIZ are considered lower impact zones). Additional detail on identifying covered segments is provided elsewhere in this preamble and in the Definitions located at section 192.761 of the proposed rule. Assessment Methods There are four acceptable assessment methods defined by this rule. They are: (a) Internal inspection (also know as in-line inspection, ILI and pig testing); (b) pressure testing; (c) direct assessment, (a process that includes data gathering, indirect examination and/or analysis, direct examination, and post assessment evaluation); and (d) any other method that can provide an equivalent understanding of the condition of line pipe. In addition, the rule proposes a method known as confirmatory direct assessment that an operator could use as an interim reassessment method. The Pipeline Safety Improvement Act of 2002 provides for assessment by ``an alternative method that the Secretary determines would provide an equal or greater level of safety.'' Because the primary function of internal inspection tools or pressure testing is to determine the condition the pipe is in, we have determined that equivalent or greater safety can be provided by ``other technology that an operator demonstrates can provide an equivalent understanding of the condition of the line pipe.'' We used this language in the liquid integrity management program rules and are proposing to include it under the list of allowable assessment methods for the baseline assessment and reassessments. The rule proposes to allow direct assessment as a supplemental assessment method on any covered pipeline segment and as a primary assessment method on a covered pipeline where in-line inspection and pressure testing are not possible or economically feasible or where the pipeline operates at a low stress. None of the permitted assessment methods listed above is fully capable of characterizing all potential threats to pipeline integrity. Currently, direct assessment is only an acceptable inspection method for assessing external corrosion, internal corrosion and stress corrosion cracking. In addition, if no other assessment method is feasible, direct assessment may be used to evaluate third party damage. Operators choosing direct assessment technologies must undertake extra excavations and direct examinations during the period while direct assessment is being validated. Some additional details regarding direct assessment are highlighted here for the purpose of acquainting readers of this proposed rule with some of the basic principles associated with the use of direct assessment. First, for purposes of this rulemaking, above-ground inspection techniques (such as close interval surveys, direct current voltage gradient, and pipeline current mapper) are considered indirect examinations. Second, visual inspection, ultrasonic testing and x-ray examinations are considered direct examinations. Third, all three threats considered under direct assessment (external corrosion, internal corrosion, and stress corrosion cracking) are direct examination of pipe. Fourth, operators who assert that their pipelines cannot be internally inspected or pressure tested are required to include written justification in their plans explaining why their pipeline(s) cannot be tested using these methods. Fifth, operators who assert that internal inspection or pressure testing is not economically feasible will likewise be required to include written justification in their plans indicating why these methods are not economically feasible. Another concept in the proposed rule is the use of Confirmatory Direct Assessment to evaluate a segment for the presence of corrosion and third party damage. This is a more streamlined assessment method that uses the steps involved in direct assessment to identify these significant threats to a pipeline's integrity. As discussed later in this document, RSPA/OPS is proposing that an operator use this method as an initial reassessment method within the required seven-year reassessment interval, if the operator has, within the proposed limits, established a longer reassessment interval for a particular segment. The follow up reassessment by pressure test, internal inspection or direct assessment would then be conducted at the established interval. Additional information about direct assessment and confirmatory direct assessment is provided elsewhere in this preamble and at section 192.763(h) of the proposed rule. Baseline Assessment Periods Under this proposal, operators are required to complete a one-time baseline assessment on each covered segment. After a baseline assessment is completed on a segment, an operator will be required to reassess the covered pipeline segment at the specified interval. Operators using pressure testing or internal inspection as an assessment method are required to complete the baseline assessment of a segment located in an HCA within 10 years of December 17, 2002 (the date the Pipeline Safety Improvement Act was signed into law). 50% of the covered segments would have to be assessed within five years. Operators using pressure testing or internal inspection as an assessment method are permitted 13 years to assess pipeline segments located in Class 3 and 4 locations where the area being assessed is not within the potential impact zone i.e., the areas we are proposing to define as moderate risk areas. (Additional detail on potential impact zones is provided in the Definitions section (Sec. 192.761) of this proposed rule and in the guidance that follows the proposed rule text.) If direct assessment is used as an assessment method, the proposal is for the operator to complete the baseline assessment within seven years for segments located in HCAs, with 50% of the segments having to be assessed within four years. Ten years would be allowed for a pipeline segment located in a Class 3 or 4 location where the segment being assessed is not within the potential impact zone i.e, is within a moderate risk area. Additional detail on baseline assessments is provided elsewhere in this preamble and at section 192.763(g) of the proposed rule. The timing of baseline assessments is covered in more detail at section 192.763(g)(4). The Pipeline Safety Improvement Act of 2002 provides that a baseline assessment is to be completed ``not later than 10 years after the date of enactment * * *'' The Act further provides that at least 50% of covered facilities are to be assessed ``not later than 5 years after such date * * *'' Our proposal for baseline assessment using internal inspection, pressure test or equivalent technology is consistent with that requirement. We propose a shorter time frame for baseline assessment by direct assessment. The primary reason for proposing a shorter time frame is that direct assessment technologies are still under development and additional information needs to be gathered on their effectiveness. However, RSPA/OPS has been sponsoring research on direct assessment that should help expedite its validity as a method for assessment. Based on the results from this research OPS may be able to lengthen the time frame from five years to up to ten years. Reassessment Intervals The Pipeline Safety Improvement Act requires a minimum seven-year reassessment period. Thus, under the proposed rule we set a reassessment [[Page 4281]] interval of seven years for operators using pressure test, internal inspection or equivalent technology, and a five year interval for an operator using direct assessment that directly examines and remediates defects by sampling. However, an operator using pressure test, internal inspection or equivalent technology could establish a longer interval, within established limits if the operator by the seventh year conducts a reassessment using confirmatory direct assessment and then conducts the follow up reassessment by the chosen method in the year the operator has set for the interval. The interval for reassessment begins to run on a segment after the operator has completed the previous assessment for that segment. Under the proposed rule, an operator establishes the reassessment interval for covered segments based on the type of assessment method the operator plans on using. The type of method used establishes the maximum interval. For operators using pressure testing, internal inspection, or alternative technology as an assessment method, the operator is to base the intervals on the identified threats for the segment or on the stress level of the pipeline and then refer to ASME/ ANSI B31.8S, Section 8 to establish the interval. Under either option, the proposed maximum interval is ten years and 15 years for a pipeline operating at below 50% SMYS. However, because a reassessment must be conducted by the seventh year, under the proposal, if an operator establishes an interval of ten years for a segment, the operator would have to complete a confirmatory direct assessment by the seventh year, and then in the tenth year do a follow up reassessment using pressure test, internal inspection tool, direct assessment or alternative equivalent technology. OPS has predicated the proposed 15-year maximum reassessment interval for pipelines operating below 50% SMYS on several factors. [sbull] Greater safety margin the current regulations provide. Current pipeline safety requirements provide a greater safety margin against corrosion for gas pipelines located in populated areas. For example, the regulations require pipelines that are located in Class 3 and 4 locations (high population areas) to be of greater wall thickness than pipelines located in Classes 1 and 2 locations. And operators must replace the existing pipe with thicker, stronger pipe when population density increases (i.e., the class location changes). Thus, pipelines located in populated areas are less susceptible to corrosion-induced rupture, because it takes much longer for corrosion to penetrate the pipe to a depth where the corrosion causes any concern. [sbull] The actual reassessment interval is based on risk factors. The reassessment interval will depend on numerous risk factors, such as the baseline assessment results, the remediation of defects found during the baseline and the integration of data concerning other risk factors. Thus, higher risk pipe will be reassessed sooner. [sbull] Gas supply interruptions. Gas transmission pipelines typically feed directly into customer distribution lines without an intermediate storage location. A pipeline's operating pressure is generally lower (i.e., pipeline is at a lower stress level) when it is at the transition phase into a distribution line. This close coupling between the transmission and distribution systems increases the likelihood of a supply interruption if a single line is shutdown for assessment or repair. The 15-year maximum is intended to minimize these supply interruptions. [sbull] Industry consensus standards. ASME B31.8S specifies a reassessment interval of 15 years for pipelines operating below 50% SMYS, and 20 years for pipelines operating between 20% and 30% SMYS. These reassessment intervals are based on a mathematical model Kiefner and Associates developed. These factors led us to conclude that the proposed 15-year maximum reassessment interval for pipelines operating below 50% was reasonable for operators yet would ensure safety. Again, as discussed previously, an operator would have to complete a confirmatory direct assessment by the seventh year. RSPA/OPS is inviting public comment on whether we should allow a maximum 20-year reassessment interval (with a confirmatory direct assessment in the seventh and 14th years) on pipelines operating at less than 30% SMYS, and reassessment by the confirmatory direct assessment method only every seven years for pipelines operating below 20% SMYS. The proposed confirmatory direct assessment method could be further streamlined for pipelines operating below 20% SMYS. OPS is considering a maximum interval of 20 years for pipelines operating between 20% to 30% SMYS (with a confirmatory direct assessment by the 7th and 14th years) because numerous studies and analyses have demonstrated that these low stress pipelines tend to leak, rather than to rupture. Current gas pipeline safety regulations recognize the reduced risk that low stress levels pose, and structure the requirements accordingly. Examples of different requirements for pipelines operating at lower stress are in Sec. 192.65 (Transportation of pipe), Sec. 192.227 (Qualification of welders), Sec. 192.241 (Inspection and test of welds), Sec. 192.309 (Repair of steel pipe), Sec. 192.315 (Wrinkle bend in steel pipe), Sec. 192.319 (installation of pipe in a ditch, Sec. 192.505 (Strength requirements for steel pipeline to operate at a hoop stress of 30% or more of SMYS), Sec. 192.711 (General requirements for repair procedures), and Sec. 192.717 (Permanent field repair of leaks). The maximum reassessment interval for operators using direct assessment as an assessment method is five years under this proposal, provided an operator directly examines and remediates defects by sampling. The reassessment interval under direct assessment would be expanded to ten years if an operator conducts a direct examination of all indications and remediates the anomalies. If an operator establishes an interval of more than seven years on a segment, the operator would have to conduct a confirmatory direct assessment by the seventh year. Additional detail on reassessment intervals is provided elsewhere in this preamble and at section 192.763(k) of the proposed rule. RSPA/OPS is inviting public comment on whether we should allow an operator using direct assessment a maximum ten-year reassessment interval on a pipeline operating at less than 30% SMYS regardless of whether the operator excavates and remediates all anomalies on that line, or at least remediates the highest-risk anomalies. Again, the operator would have to conduct a confirmatory direct assessment by the seventh year of the interval. The number of excavations (Dig Criteria) proposed for the direct assessment method follow those being developed by the National Association of Corrosion Engineers (NACE) Recommended Practices on Direct Assessment, with the following deviations: (1) In each External Corrosion Direct Assessment (ECDA) region where all indications categorized as ``immediate'' are present, we propose that the operator reduce operating pressure by at least 20% until such indications have been excavated and mitigated. (2) In each ECDA region where indications categorized as ``scheduled''are present, we propose the operator continue the excavations until at least two indications are excavated having corrosion of depth no greater than 20% of wall thickness. [[Page 4282]] (3) In each ECDA region, we propose to require one excavation; however, the excavation must be made at a location the operator considers most suspect, not at any random place. RSPA/OPS is inviting public comment on whether the benefits of these proposed requirements that are more extensive than the NACE Recommended Practices currently being developed are worth the cost. External Corrosion Direct Assessment and Internal Corrosion Direct Assessment Work jointly funded by the gas pipeline industry and RSPA/OPS is ongoing to develop, validate and standardize the application of the direct assessment process to external corrosion (ECDA) and internal corrosion (ICDA). Future work is planned to develop, validate and standardize a direct assessment process for application to the stress corrosion cracking (SCCDA) threat. Furthermore, significant anecdotal evidence exists that the ECDA process may be capable of identifying coating damage associated with third party impacts on pipelines, but formal validation of this capability has not occurred. ICDA is an assessment process that first identifies areas along the pipeline where water or other electrolytes introduced by an upset condition may reside, then focuses direct examination on the locations in each area where internal corrosion is most likely to exist. If no evidence of internal corrosion exists in these most likely locations, then the entire section can be considered to be free of internal corrosion. An operator using direct assessment as a method to address internal corrosion in a pipeline segment must follow the requirements in ASME/ANSI B31.8S, Appendix SP-B2, and in this section. Additional detail on ICDA is provided elsewhere in this preamble and at section 192.763(h)(3) of the proposed rule. ECDA is an assessment process that combines assembly and analysis of risk factor data, indirect examination using above ground detection instruments, direct examination of suspected areas on the pipeline and post-assessment evaluation. The current approach being incorporated in the consensus standard under development for ECDA is to locate areas suspected of having external corrosion by identifying defects in the pipe coating, then excavating those defects in areas where corrosion activity is suspected. While all indications discovered by ECDA that are not adequately protected by the cathodic protection system at the time of the assessment will be excavated and directly examined, only a fraction of the ECDA indications that are protected by cathodic protection systems at the time of the assessment will be excavated. Additional detail is provided elsewhere in this preamble and at section 192.763(h)(4) of the proposed rule. The Role of Consensus Standards The underpinning analysis for this rulemaking was a consensus standard development effort. Completing this effort required nearly two years. This effort required assembling the best integrity assurance practices currently used by gas pipeline operators, and incorporating these practices into consensus standards. In addition the direct assessment process, which was conceived as a way to assess the integrity of gas pipelines for which in-line-inspection and pressure testing are not possible or economically feasible, needed to be developed, documented, and standardized. Some consensus standards on gas pipeline integrity management that we are considering incorporating by reference have been published. Others are still under development. A major effort has been underway for several years to develop consensus standards supporting integrity management practices for gas pipelines. These standards are a necessary component in assuring the quality of implementation of any new assessment requirement. ASME/ANSI B31.8, Supplement, issued early this year, structures industry knowledge and best practices into requirements for an integrity management program and a set of prescriptive requirements for assessing pipeline integrity. In addition this standard describes the requirements an operator must follow to implement a performance-based program. The ASME/ANSI standard represents a significant advance in the documentation of demonstrated integrity management practices. Although many of the tools employed in the direct assessment process have been in use for sometime, the use of these tools in the integrity assessment process is new. The National Association of Corrosion Engineers (NACE) undertook development of a Recommended Practices to support direct assessment and to expand the standardized application of In-Line Inspection (ILI). RSPA/OPS is relying heavily on the technical content of these standards. RSPA/OPS has been directly involved in the development of these standards, both to ensure that the standards reflect the knowledge and perspective of RSPA/OPS, and to provide the basis for expanding requirements as needed within the Integrity Management Program (IMP) Rule. RSPA/OPS involvement included participation in the teams that developed the ASME/ANSI B31.8S standard, and ongoing participation in the development of the NACE Recommended Practice on Direct Assessment. In addition, RSPA/OPS supported participation by pipeline safety representatives from several States in the standards development and review process. This proposed rulemaking is the culmination of experience gained from inspections, accident investigations and risk management and system integrity initiatives. This experience is the foundation for proposing a rulemaking that addresses, in a comprehensive manner, the National Transportation Safety Board's (NTSB) recommendations, Congressional mandates, including the mandates in the Pipeline Safety Improvement Act of 2002, and pipeline safety and environmental issues raised over the years. These issues and considerations include: [sbull] Several NTSB recommendations concerning pipeline safety, including those which: (1) Require periodic testing and inspection to identify corrosion and other time-dependent damage. (2) Require the establishment of criteria to determine appropriate intervals for inspections and tests, including safe service intervals between pressure testing. (3) Determine hazards to public safety from electric resistance welded (ERW) pipe and take appropriate regulatory action. (4) Expedite requirements for installing automatic or remote- operated mainline valves on high-pressure lines to provide for rapid shutdown of failed pipeline segments. [sbull] Our analyses of several pipeline ruptures in Bellingham, Washington; Simpsonville, South Carolina; Reston, Virginia; and Edison, New Jersey, brought to light the need for operators to address the potential interrelationship among factors affecting failure causes and to implement coordinated risk control actions to supplement the protection provided by compliance with current regulations. [sbull] Our analysis of the rupture in Carlsbad, New Mexico, highlighting the need for methods to assess internal corrosion in pipelines that are not piggable. [sbull] Several Congressional mandates identify areas where the risk of a [[Page 4283]] pipeline failure could have significant impact. These specify that RSPA/OPS: (1) Prescribe standards establishing criteria for identifying gas pipeline facilities located in high-density population areas (49 U.S.C. 60109(a)(2)). (2) Prescribe, if necessary, additional standards requiring the periodic inspection of pipelines in high-density population areas, to include any circumstances when an instrumented internal inspection device, or similarly effective inspection method, should be used to inspect the pipeline (49 U.S.C. 60102(f)(2)). (3) Survey and assess the effectiveness of Remote Control Valves (RCVs) to shut off the flow of natural gas in the event of a rupture of an interstate natural gas pipeline facility and make determination about whether the use of these valves is technically and economically feasible and would reduce risks associated with a rupture of an interstate natural gas pipeline facility. If the use of these valves determined to be technically and economically feasible and would reduce risks associated with a rupture of an interstate natural gas pipeline facility, then prescribe standards on the circumstances where an operator of a gas transmission pipeline facility must use an RCV (49 U.S.C. 60102(j)). Risk Management and Systems Integrity Inspection Initiatives This proposed rulemaking is also based on what we learned about integrity management programs from our risk management and pipeline inspection activities, particularly the Risk Management Demonstration Program, the Systems Integrity Inspection (SII) Pilot Program and the new high impact approach to inspections. These precursor activities began in 1997. In the Risk Management Demonstration and Systems Integrity Inspection Pilot Programs, we studied and evaluated comprehensive and integrated approaches to safety and environmental protection. These approaches incorporated operator- and pipeline-specific information and data to identify, assess, and address pipeline risks, in conjunction with compliance with existing pipeline safety regulations. From these programs, we also expanded our knowledge of the extent and variety of internal inspection and other diagnostic tools that hazardous liquid pipeline operators use in their integrity management programs. We also learned of the wide variability in the extent and effectiveness of programs in use by operators to support management of pipeline integrity. Additionally, based on risk management principles, RSPA/OPS implemented a systems approach through a new high impact inspection format that evaluates pipeline systems as a whole, rather than in small segments. The focus of the high impact inspection is on understanding how operators are addressing the issues that have been recognized as impo
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